REPORT ON VOCATIONAL TRAINING

AT

INDIANOIL CORPORATION LIMITEDHALDIA REFINERY

PERIOD OF TRAINING(21st June – 17th July 2010)

DEPARTMENT OF CHEMICAL ENGINEERING3RD YEAR

SAMARSHI CHAKRABORTY

SANTANU ADHIKARY

AKASH PODDAR KUNTAL MAITI

HALDIA INSTITUTE OF TECHNOLOGY

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DEPARTMENT CONCERNED :

Training Department …………………………

FuelOil Block (FOB) ……………………………

Lube Oil Block (LOB) ……………………………

DHDS …………………………...

Oil Movement & Storage (OM&S) …………………………..

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PREFACE

Industrial training plays a vital role in the progress of future engineers. Not only does it provide insights about the industry concerned, it also bridges the gap between theory and practical knowledge. We were fortunate that we were provided with an opportunity of undergoing Industrial training at INDIAN OIL CORPORATION Ltd., Haldia, one of the leading refineries in India.

The experience gained during this short period was fascinating to say the least. It was a tremendous feeling to observe the operation of different equipments and processes. It was overwhelming for us to notice how such a big refinery is being monitored and operated with proper co-ordination to obtain desired results.

During our training we realized that in order to be a successful process engineer one needs to possess a sound theoretical base along with the acumen for effective practical application of the theory.Thus, we hope that this industrial training serves as a stepping-stone for us and helps to be successful in future.

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Acknowledgement

We would like to express our deep sense of gratitude to Mr. G.G.Gupta (Training Manager) for granting us permission to undergo training at IOC, Haldia refinery over a period of 4 weeks and for providing us with necessary inputs as and when needed. We would also like to appreciate and acknowledge the efforts put in by the Senior Production Managers. In spite of their busy schedule, they were always eager to help us out and share their vast experiences with us. We would also like to heartily thank the shift engineers and operators who in spite of their arduous task took time out to explain each and every detail of the processes and also provided us with invaluable technical advices about every aspect of the plant. We are really thankful to the staff for cooperating with us immensely. We are thankful to the following departments and their staffs for their insights on the industry.

Training Department: Mr. D.Sinha. Mr. B.K.Mondal. Mr. S.Bag.

Fuel Oil Block: Mr.S.K.Roy , PNM

Lube Oil Block :

Mr.S.Samanta, SPNM Mr. Lalan Kumar Paul, DMPN Mr. R. Alam.

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DHDS / RFCCU / SRU: Mr.S.Baitha, PNM Mr. Soumen Mondal., DMPN Mr. S. Partha.

Oil Movement & Storage: Mr. S K.Das, CPNM Mr. B.K.Panda, SPNM

Samarshi Chakraborty

Santanu Adhikary

Akash Poddar

Kuntal Maiti

INTRODUCTION

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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 21st 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 in India.

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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.) Narimanam Bongaigaon (Assam) Digboi (Assam) Chennai

The combined rate capacity of these ten refineries is 49.30MMPTA. IOC accounts for 42% of India’s total refining capacity. The Corporation's cross-country network of crude oil and product pipelines, spanning about 9,300 km and the largest in the country, meets the vital energy needs of the consumers in an efficient, economical and environment-friendlymanner.

The 5.8 MMTPA refinery at Haldia is the 4th in the chain of refineries under IOCL.

          Haldia Refinery, the fourth in the chain of seven operating refineries of Indian Oil, was commissioned in January 1975. It is situated 136 km downstream of Kolkata in the district of East Midnapur, West Bengal, near the confluence of river Hoogly and river Haldi. The refinery had an original crude oil processing capacity of 2.5 MMTPA. 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.

The strategic significance of this Refinery lies in its being the only coastal refinery of the Corporation and the lone lube flagship, apart from being the sole producer of Jute Batching Oil and Russian Turbine Fuel. Capacity of

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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. Diesel Hydro Desulphurisation (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 Fluidised 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. In addition, a Catalytic Dewaxing Unit (CIDWU) was installed and commissioned in 2003, for production of high quality Lube Oil Base Stocks (LOBS), meeting the API Gr-II standard of LOBS. This is the only refinery in the country to produce such high quality LOBS.

In order to meet the Euro-III fuel quality standards, the MS Quality Improvement Project has been incorporated for production of Euro-III equivalent MS. Currently the unit is under stabilisation. At present, the Refinery is operating at a capacity of 5.5 MMTPA. Refinery expansion to 7.5 MMTPA as well as a Hydrocracker project has been approved for Haldia Refinery, commissioning of which shall enable this Refinery to supply entire Euro –III HSD to the eastern region of India.

Fuel oil products include:   1. LPG.

2. Motor spirit (MS).3. Mineral turpentine oil (MTO).

4. Superior kerosene oil (SKO).

5. Aviation turbine fuel (ATF).

6. Russian turbine fuel (RTF).

7. High speed diesel (HSD).

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8. Jute batching oil (JBO C/P).

9. Naptha.

10. Furnace oil.

Lube oil base stocks are:

1. Inter neutral HVI grade.

2. Heavy neutral HVI grade.

3. Bright neutral HVI grade.

Beside the above, slack wax, carbon black feed stock (CBFS) , Bitumen, sulphur are the other product of this refinery.

Block Flow Diagram of Haldia Refinery

Crude

CDU

1

CDU

2

Fuel Gas

LPG

SR Naph

Kero Cut

St.Run G.O

JBO

RCO

ATU

Desulphurised Fuel Gas

SRU Sulphur

LPGNaphtha

90 – 140°CCRU MS( 3 GRADES)

C5 – 90°C

KHDS

MTO

RTF/ATF

Kerosene

DHDS HSD (2 GRADES)

HGU

H2

JBO (2 GRADES)

VDU

1

VDU

2

IFO

GO

SO

LO / IO / HO

SR

PDA

DAO

FEU

NMPSDU HFU

70 N GR-II

150 N GR-I / II

500 N GR-I / II

850 N

150 BS GR-I/II

FCCU

Ext.

S.Wax

LO

Asp.

VBU FO (2 GRADES)

BTUBitumen(3GRADES)

Bit Eml.

CBFS

MCW MCW

CDWU

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FIRE AND SAFETY:

The main & utmost thing , which is to be known to all is the safety durin working in an industry. A person in an industry should well aware about the safety rules to keep safe himself & others from any unwanted misshap. 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 thin is that one should ware safety jacket during work.

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.

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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 he can 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.

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

i. 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 is fire.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.

Now the next important thing is the type of fire extinguisher.Type of fire extinguisher- TYPE USE FOR CHEMICAL

A general fire water, AFFF(aqueous . film forming foam)

B fire from oil sand, water AFFF, . . DCP(dry chemical . . powder )

C fire from gases CO2

D metallic fire DCP E electrical fire CO2

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

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OVERVIEW OF HALDIA REFINERY

FUEL OIL BLOCK

Fuel Oil Block is the unit that takes the imported crude oil from storage and performs the initial separation of broad components in an atmospheric distillation column. These broad products are further modified to other products which are treated, stored and finally marketed. In this sense it can be called the mother unit of IOC (Haldia). 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) are processed. The capacity has been increased from 2.5 MMPTA to 4.6 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 TREATMENT (Unit 14)1. Naphtha caustic wash

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AMINE ABSORPTION AND REGENERATION (Unit 15)1. Fuel gas amine absorption system2. Amine (DEA) regeration

NAPTHA PRETREATMENT UNIT (Unit 21)

CATALYTIC REFORMING UNIT (Unit 22)

KHDS UNIT (Kero Hydro Desulphurisation Unit)

Crude Distillation Unit:

Principle of operation:  The crude oil from storage tanks (generally 35,000 cubic meters) is first taken to a set of heat

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DESALTER

FURNACE

PREFRACTIONATOR

GASOLINE

PRETOPPEDCRUDE

IBP-140OC

DIESEL

JBO (C) / JBO (P)

RCO

CRUDE DISTILLATION UNIT

exchangers for preheating to about 120 °C-130 °C and introduced to the desalter setup for 95% desalting. The crude is then heated to 260-265°C in second set of heat exchanger. Then it’s further heated up to 350-360°C in furnace. The hot crude is distilled in an atmospheric distillation column to draw the following products from different stages:

Sl No                  Stream Approx. Boiling Range(°C )

1. Gasoline ( overhead ) IBP – 140

2. Heavy Naphtha 140 – 160

3. SKO / ATF 160-271 / 160-240

4. HSD 271-320 / 240-320

5. JBO(C)/JBO(P) 320-360 / 320-330

6. RCO 360+ / 385+/>400+

  

OVERHEAD (IBP-140OC 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 column .

SPLITTING OF IBP-C4 CUT: 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.

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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 Spirit (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.

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.

DOSING OF ADDITIVE IN ATF RUN: Dosing with particular compounds from outside to build up properties like high conductivity and antifreezing property processes aviation turbine fuel. Generally, Hiracon and Stadis 450 is dosed at a particular rate. Hiracon acts as an antioxidant and reduces the chance of inflammation.

Stadis 450 (Toluene and Isopropanol mixture) increases the heat conductivity of product causing safer transport.

Generally funnel at the top of 23B09 is to be opened and from it 300 kgs. of Hiracon and 37.5 kgs. of Stadis 450 are to be inserted .

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PRODUCTION OF HIGH SPEED DIESEL (HSD): It is drawn off from the column 11C01 and sent to HSD storage. SR gas oil is the main component of HSD. The other components are heavy naptha, excess JBO , vacuum gas oil,spindle gas oil etc.

PRODUCTION OF JBO(C) / JBO( P ): Jute Batching Oil abbreviated as JBO (clear and pale) is directly drawn from main distillation column in blocked out operation and is sent to JBO storage.

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 desalter main valve (11PIDC06) or at both places by using pumps.

After proper mixing, the crude experiences an alternating electrostatic field in the desalter. 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.

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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 vapour 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 vapour 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

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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 stabiliser 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. vapour 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)

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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.

PROCESS DESCRIPTION

There are three sections in this plant1. De-ethaniser2. Amine wash column3. 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 vapouriser.c. Third part to depropaniser for separation of propane and butane.

Feed is heated by depropaniser bottom in heat exchanger and enters the 14th tray of column. Overhead vapour 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

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done by MEROX process. It involves the catalytic oxidation of mercaptans to harmless disulphides. 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. % maxm)

Mercaptan Sulphur

(wt % maxm)V.B. gasoline 0.740 1.0 0.50S.R. gasoline 0.671 1.0 0.85

PROCESS DESCRIPTION

Light mercaptans are extracted by caustic containing merox catalyst and heavier mercaptans from LPG and gasoline steams are also extracted by same procedure. The extracted mercaptans in caustic phase are oxidised to disulphides, which are separated with regeneration of caustic alkali. For heavier mercaptans the resulting disulphide remain in the gasoline and the process is referred as merox sweetening.

Gasoline merox undergoes a caustic pre wash for removal of H2S and then is fed to a perforated tray column where gasoline is counter-currently extracted from caustic solution containing a merox catalyst. Light mercaptans are transferred to caustic solution containing Na-mercaptides and residual mercaptans are converted to disulphide in a fixed bed reactor containing impregnated charcoal activated with merox catalyst. The oxygen required is supplied by air injection at the inlet of the reactor. Caustic solution is separated from gasoline by settling in gasoline caustic settler. Gasoline passes through sand filter and under gravity is routed to storage

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after injection of oxidation inhibitor i.e. antioxidant and copper deactivator to avoid gum formation.

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

Naphtha Caustic Wash Unit ( U-14 ) :

               C5 - 90˚C is treated with caustic to remove H2S before sending to the storage. Naphtha is washed with caustic solution in wash drum and the naphtha from the drum is water-washed and sent to storage while the caustic part is recirculated.

Amine Absorption & Regeneration Unit ( U-15 )           

                This section is consist of two part i.e. amine absorption and regeneration. Sour fuel gas after passing through a filter (to remove hydrocarbon liquid which causes foaming in the column) from the refinery is fed to amine absorption system (15C02) is to remove H2S. Lean amine is counter currently passed through fuel gas to remove 99% of H2S. Sweet fuel gas from the top of the column is passed to coalescer for entrained amine settlement. Rich amine from 15C02 column, hydro finishing unit and fuel gas amine absorption column exchange heat with lean amine and fed to a regeneration column (15C01) where stripped with steam to remove H2S. Remove H2S is routed to SRU.                     

Naphtha Pretreatment and Reforming Units:

        Choice of naphtha:

                      Naphtha consists of mainly naphthalene (N) and aromatics (A). This N +2A are known as reforming index. As octane number is a function of aromatics content. Feed with high reforming index is high of naphthalene content is thus can be used for catalytic reforming. Again heavy cuts having high reforming index yields

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easier condition. But unstable compounds in the part can lead to high coke formation which can deactivation catalyst.

                       On the other hand light cuts devoid of naphthalene and aromatics,   contains stable compounds which can’t be reformed even in presence of catalyst.  

         This leads to the choice of feed towards the 90-140ºC cuts.

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 likeSulphur, 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

A. 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

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

B. 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 carbozo, 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.

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

( Pb + Cu ) : 1ppb

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

E.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

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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.

Naphtha Hydro Desulphurization Unit ( U-21 ) :

      In this unit naphtha is passed through a magnetic filter to extract the iron pieces. Naphtha is mixed with H2 and recycle gas and preheated in heat exchangers (21E01 A/B/C) using hot reactor effluent passing through the tube side. Again the feed is taken to an open draft furnace (22F01) for heated up to the reactor temperature. After heating it flow across the reactor containing Co-Mo catalyst for desulphurization reaction takes place. The effluent is then cooled in heat exchangers and taken to a separator drum consist of demister above which the H2S accumulates. Liquid is then preheated and sent to a stripper 21C01 column. The bottom of the stripper is reboiler in the furnace and overhead vapor is condensed. A part of it is refluxed and a part is taken out as pretreated naphtha.

         

Catalytic Reforming Unit ( U-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

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In CRU main categories of reactions are as follows :

Aromatisation of napthenes and paraffins

Isomerisation of napthenes and paraffins

Hydrocracking of paraffins

Hydrogenation of paraffins

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.

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Example : C7H6 Methyl Cyclohexane + H2

Reactions :

         1. Dehydrogenation:

         2. Isomerization:

         3. Paraffin hydrocyclization:

         4. Hydro cracking:

          The following reversible reactions take place in three reactors according to written below:

                1st reactor:

1. Dehydrogenation 2. Isomerization

                2nd reactor:

1. Dehydrogenation 2. Isomerization 3. Hydro cracking 4. Dehydrocyclization

                          3rd reactor:

                               1. Hydro cracking

                               2. Dehydrogenation

Process description:  Pretreated naphtha is pumped to the heat exchanger’s (22E01) shell side. Hot reactor effluent flows through the tube side. Vaporized feed fed to the furnace 22F01 for further heating up to the reaction temperature. Then it is fed to flow reactor’s (22R01) high purity Al2O3 extrudates impregnated with .3% Pt and .3% Rh catalyst bed. Due to endothermic nature of the reaction the product temperature decreases and it is again fed to a furnace 22F02 and then to the catalytic reactor 22R02. The product again reheated and fed the third reactor 22R03. The hot reactor effluent is cooled down in a series of heat exchangers and the vapor – liquid

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mixture is taken to a separator. The gas from the top is recycled to the unit 21 and to KDS unit and liquid is fed to stabilizer column.  

Process operating variable : Octane number is a function of pressure and temperature and aromatic content of products.

Temperature: An increase in reaction temperature leads to an increase in operation severity. More sensitive hydro cracking reaction leads to a high coke deposit decreases the catalyst activity.

Reactor inlet temperature: In practice the reaction temperature are kept constant. Generally with a decreasing reaction temperature coke deposit in catalyst bed is small and hence gives catalyst gain. Sometimes due to high naphtha content the endothermic heat of reaction is so high that it is impossible to make up for a furnace and a decreasing temperature patterns follow.

Pressure: Although pressure during a operation can’t change, it can influences to a large extent the quality of the product.

              A decrease in pressure leads to a more complete aromatization, the desired object of reforming and at the same time limits hydro cracking, a parasitic reaction. Thus a lower pressure leads to a higher yield of desired products and decrease in amount of light products (from methane to butane). However as an adverse effect, a decrease in pressure leads to further deactivation catalysts as with the decrease in H2 partial pressure coke formation increases.

             This deactivation may be compensated to a large extent by an increase in recycle rate. Thus for optimum equipment design of a reforming unit a precise choice of operating condition (pressure and recycle rate) has to be made. This choice is guided by an economic balance between the yields to obtain the life of the catalyst and power consumption of recycle compressor.

Space velocity: Reduction of space velocity favors hydro cracking. Thus increases octane number but reduces yield. Hence, temperature is kept low when reducing flow rate.

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Catalyst: Catalyst deactivation takes place due to coke formation, metal poisoning, water poisoning etc.  

Kero Hydro Desulphurization Unit ( U-23 ) :

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 OC2. TBP Fraction 140 – 247 OC3. TBP Fraction 140 – 240 OC4. 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 OCPressure: 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:

1. 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 .

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2. 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 requalation 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.

3. 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 23C01II. One part of vapour is sent to Hydrofinishing Unit of Lube Oil

block. Another part is recycled along with make up gas and compressed by two parallel reciprocating compressor 23K01A/B.

4. 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. All the stripper bottom is pumped by 23P03, cooled and sent to storage as finished product.

The stripper overhead vapours 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.

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5. 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 vapour from the knockout drum are compressed in the second set of compressors and cooled in a water cooler . The vapour separated liquid hydrocarbons are sent to fuel gas system or amine unit. The condensed hydrocarbons are drained manually.

IMPORTANT DATA OF KERO HDS UNIT

1. CAPACITY: 5,77,500 MT/Yr. or 1690 MT/day

2. FEED PROPERTIES: Specific gravity at 15OC = 0.803 TBP range = 140-271 OC Total Sulphur ( wt. % ) = 0.90

3. CATALYST: Diameter : 1.5 mm Bulk density = 0.65 gm/cm2

Pore volume = 0.50-0.55 cm2/gm. Chem. Composition :

1. CoO : 5.0%2. MoO3 : 13.0 %3. SiO2 : 1.0 %4. Sulphate : 1.0 %5. NaOH : 0.6 %6. Al2O3 : Rest

4. OPERATING CODITIONS: Reactor inlet temperature : 340 OC Reactor outlet temperature : 375 OC Working pressure in reactor : 34.6 kg/cm2

Working temperature in reactor : 380 OC Stripper feed temperature : 139-140 OC Stripper top temperature : 111-129OC

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Stripper bottom temperature : 200-215 OC Stripper bottom pressure : 2.3 kg/cm2

FURNACE (23F01):

Type : Vertical Diameter : 5.0 X 13.5 ft Fuel used : Fuel oil from furnace No. of tubes :

radiation section : 44 (V)convection section : 24 (H)

No. of burners : 4STRIPPER ( 23C01)

9 valve trays -- Single pass type17 valve trays -- Two pass type

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DIESEL – HYDRO DESULPHURISATION UNIT (UNIT --25) 

The diesel hydro desulphurization unit (DHDS unit), Unit 25, is based on the Unionfining 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 Unionfining Process is a proprietary, fixed-bed, catalytic process developed by UOP for hydro treating a wide range of feedstocks. 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. Unionfining is designed primarily to remove sulphur and nitrogen. In addition, the process does the job of saturating olefins and aromatic compounds while reducing Conradson Carbon and removing other contaminants such as oxygenates and organometallic compounds.

The desired degree of hydrotreating 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 Unionfining catalysts are formulated by composing varying amounts of Nickel or Cobalt with Molybdenum oxides on a alumina base.

Purpose: To reduce the sulfur content of the sour diesel and to produce sweet diesel with sulfur content of less than 0.25/0.05 % by wt.

Sulfur removal: Feed stocks to the union fining .Unit contain simple mercaptanes, sulfides and disulfides are easily converted to H2S. Feed stocks containing hetero atomic, aromatic molecules are preceded by initial ring opening and then sulfur removal followed by saturation of the resulting olefins.  

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

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Nitrogen removal: De-nitrogenation is generally more difficult than desulphurization. The de-nitrogenation of pyridine proceeds by aromatic ring saturation hydrogynolysis and finally de-nitrogenation.

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

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

Olefin  saturation: Olefin saturation reaction proceeds vary rapidly and have high heat of reaction.

Linear olefins C-C=C-C-C-C + H2 = C-C-C-C-C-C (and isomers)

Aromatic saturation: Aromatic saturation reaction is the most difficult and exothermic.

Benzene + H2 = Cyclohexane

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

      Metal contained in the crude oil are usually nickel and vanadium. Iron is found concentrated at the top of the catalyst bed as iron sulfide, which is corrosive.

      Na, Ca and Mg are present due to the contact of the bed with salted water or additives.

      Improper use of additives, to protect the fractionator overhead systems from corrosion or to control foaming, accounts for the presence of P and Si. Lead may also deposit on the hydro treating catalyst bed from reprocessing

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leaded Gasoline through the crude unit. The total metal retention capacity of the catalyst system can be increased by using a guard reactor or guard bed of catalyst specially designed for de-metallisation.

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

Chlorine removal Ph-C-C-C-Cl + H2 = HCl + Ph-C-C-C-HHCl + 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

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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.

               Sulphur Recovery unit (Unit-28)

The sulphur recovery unit is designed to recover sulphur from the sour vapors 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:

1. A knock out drum for the feed gas stream and fuel gas stream.

2. A Claus Section, consisting of a thermal stage and three reactor stages.

3.  A super claus stage.

4. A thermal incinerator, burning the tail gas and vent gas of the sulphur.

5. Degassing System.

6. A Sulphur pit with degasifying facilities and sulphur yards.

UNIT CAPACITY OF SRU:

Design Capacity:     60 metric tons per day

Turndown Ratio:     30% on the normal feed gas rate

On-Stream Factor:  8000 hr per day

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FEED CHARACTERISTICS:  The feed stock of SRU is a mixture of “acid gas ex ARU” and “acid gas ex SWS”. The quality and quantity of H2S feed to the unit will vary depending on the shut down of the various preceding units. The unit should be capable of converting 99% Wt. of the H2S content in the feed streams to sulfur in all cases.

PRODUCT CHARACTERISTICS:

The product sulphur meets the following specification after degasification,

State:       Liquid Sulphur

Color:   Bright Yellow

Purity:    Minimum 99.9% on dry basis

H2S Content:  10 PPM wt. Maximum

CATALYST AND CHEMICALS:

1. 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. PPM Na2O.

2. SULPHUR CLAUS CATALYST:  It is a catalyst for selective oxidation and consists of Al2O3 50% vol. SiO2 with iron (III) oxide/ phosphate 50%vol. Catalyst is premixed by 50%/50% vol. by manufacturers.

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

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 condenser.

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To increase the pH, trisodium phosphate solution is injected and the concentration of phosphate solution in the boiler and condenser is kept at 50-100 PPM. 

CHEMICAL REACTIONS INVOLVED IN SRU

CLAUS SECTION: The main reaction in this section takes place at main combustion chamber.

   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 Claus Reaction, Sulphur is formed in the main burner and reaction chamber.

SUPER CLAUS SECTION: In this section partial oxidation of H2S takes place according to the reaction

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

PROCESS DESCRIPTION:

CLAUS SECTION: By the reactions described above 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 the 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 first 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 & 3rd reactor stages the H2S and SO2 again react to form sulphur but this time at low temperature. In the super clause 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 down stream of 3rd reactor stage the amount of H2S in the range of 0.5- 0.7%vol. and the SO2

concentration is as low as possible. Before entering the first reactor the

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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 first reactor is routed to second sulphur condenser. The process gas flow in next routed to second steam re-heater and then to second 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 re-heater, and then passed to 3rd reactor when 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 4th steam re-heater then passed to reactor. Before it enters the reactor, a controlled amount of air is added. Proper mixing is obtained in static mixer. In the reactor sulphur S8 is formed according to the reaction mentioned above.  The formed sulphur is condensed in 5th sulphur condenser. A sulphur condenser is installed downstream of last sulphur condenser to separate entrained sulphur mist. The sulphur condensed and separated in the condenser and coalescer is drained via the sulphur logs and sulphur cooler into 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 to SO2 in presence of oxygen. After the gas is cooled in incinerator, waste heat boiler and super heater it is routed to the stock. In the incinerator and waste heat boiler, MHP steam is produced and in the super heater 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 polysulphide. Without treatment of 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 1300 C 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 which is the safe level to avoid exceeding the lower explosive limit.

The function of this process is to enhance the decomposition of polysulphide 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 sulphur. In this way, the H2S content is reduced

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from approximately 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)

MSQ UNIT (UNIT-85,86,87)

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NAPTHA SPLITTER UNIT 85

NHDT UNIT 85

ISOMERIZATION + DIH +

LPG RECOVERY

UNIT 86

NHDT & CRU

UNIT 21 & UNIT 22

REFORMATE SPLITTERUNIT 85

FCC GASOLINE

SPLITTER UNIT 87

SHU UNIT 87

PRIME G+ SELECTIVE DESULPHURIZATION UNIT UNIT 87

SR NAPTHA

FCC GASOLINE

PYROLYSIS GASOLINE

NAPTHA PRODUCT

LPG

HYDROGEN

MS PRODUCT

ISOMERIZATE

HEAVY NAPTHA

LIGHT NAPTHA

NAPTHA HEART CUT

HEAVY FCC GASOLINE

FCC GASOLINE HEART CUT

LIGHT FCC GASOLINE

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. 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 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.

RESIDE   FLUID CATALYTIC CRACKING UNIT

Process Chemistry/Theory: Cracking process uses high temperature to convert heavy hydrocarbons into more valuable lighter products. This can be done either by thermal cracking or by catalytic cracking. Catalytic cracking process has almost surpassed thermal cracking because of inherent advantage of low temperature and pressure. Catalytic cracking produces high octane gasoline, a more valuable cracked gas and less of undesirable residual products.

      Theory of catalytic cracking is based on the carbonium ion formation and subsequent hydrogen transfer reaction. First step is the formation of a carbonium ion from the feed stock. Carbonium ion is readily formed from olefin. This reaction takes place on the active side of the catalyst. Once carbonium ions are formed, they may either crack to form a small olefin plus another carbonium ion reacts with another olefin to form a different carbonium ion, isomerizes or breaks the chain by donating the proton back to the catalyst. For dealkylation a tertiary amyl side chain comes off very easily. Propyl, n-butyl, ethyl chains are progressively more difficult to remove. The methyl group is generally not attached.

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      Next step is associated with the hydrogen transfer reaction which converts olefins to paraffin. The source of hydrogen is another olefinic hydrocarbon on the catalyst which will progressively become more hydrogen deficient. This hydrogen deficient species will absorb very strongly to the catalyst surface and deposit the coke on the catalyst during reaction.  

Brief process description: Fluidized bed catalytic cracking unit consists of the following sections:

1. Feed preheat section. 2. Reactor/ Regenerator section. 3. Flue gas section. 4. Catalyst handling section. 5. Main fractionator section. 6. Product recovery section. 7. Amine treating section.

The main products coming out from FCCU are as follows:1. Fuel gas.2. LPG.3. Gasoline.4. TCO (Total cycle oil).5. CLO (Clarified oil).

 Feed preheat section: Cold feed from F.C.C.U. feed tank and hot feed from process units are combined and received in storage 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 manual draining of water accumulated during start-up upset conditions. The feed drum pressure floats on the main fractionator by means of a balance line which ties into the fractionator below the LCO (light cycle oil) drawing chimney tray.

      Fresh feed is pumped by fresh feed pump to the preheat circuit. The feed preheat circuit comprises 11 heat exchangers in series. The fresh feed after preheat attains a temperature around 1880 C (for feed 3) and 2550 C (for feed 2). Fresh feed is heated in these exchangers against lean oil, HCN, LCO, LCO pump-around, HCO pump-around and slurry pump-around.

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      For feed 2, final feed is preheated in the fired heater before being sent to the riser feed nozzles of the reactors.

      For feed 3, slurry pump-around passes completely. Feed heater will be operating at a minimum operating duty. If preheat temperature is still higher than the required, other feed preheat exchangers are by-passed also.

Reactor /regenerator section:  Preheated feed is finely atomized and mixed with dispersion steam in four feed injectors mixing chamber and injected to the riser. Above the feed injectors two HCO recycle oil injectors are provided to maximize distillate production. Above the recycle oil injectors, a recycle slurry backwash injector is provided. Also a visbreaker naphtha injector is provided below the feed injector at riser bottom. Dispersion steam (MP steam) is supplied through individual flow control to each injector for proper atomization and vaporization of oil. 

      The fined atomized feed is contacted with hot regenerated catalyst and vaporizes immediately. The vaporized oil mixes with the catalyst particle 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 sec. at design conditions.

      Riser outlet temperature is regulated by controlling the flow of regenerated catalyst by the regenerated catalyst slide valve (RCSV).

Catalyst separation from hydrocarbons/steam vapour is necessary to avoid any undesirable continuation of the reaction which produces light gases at the expense of valuable liquid products.

      After existing the initial separator the vapour passes through two high efficiency single-stage cyclones to complete the catalyst separation from hydrocarbon products, thus minimizing the amount of catalyst lost to product. The product containing a small amount of inert gas and steam flows to quench zone of main fractionator. Small quantity of catalyst contained in the product is carried to the fractionator slurry circuit.

      Pressure controller at the wet gas compressor knock-out drum provides the steady operating pressure of the reaction system.

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      Catalyst emitting the initial separator is prestripped with MP steam to reduce coke yield and further stripped with steam. A series of baffles enhances the contacting of steam and spent catalyst. The stripping steam displaces the volatile hydrocarbon contained in the catalyst particles before they enter the first stage regenerator.

      The stripped spent catalyst flows down through the catalyst standpipe and spent catalyst slide valve (SCSV) which controls the stripper level by controlling flow of spent catalyst from the splitter.

      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 the first stage regenerator and rest in the 2nd

stage regenerator.

      Combustion air for combustion process in regenerators is supplied by combustion air blower driven by steam-turbine.

      The hot regenerated catalyst flows to the 2nd stage regenerator through a lateral connection to the withdrawal well (WDW) from which catalyst flows down to the regenerated catalyst pipe (RCSP),

The RCSV and 450 C stand section to the reactor riser base where catalyst begins the upward flow towards the fresh feed injectors.

      1st stage regenerator internal primary and secondary cyclones and 2nd stage regenerator internal primary and secondary cyclones separate the entrained catalyst from the flue gas existing the 2nd stage regenerator. Flue gas existing both regenerators flows to the flue gas section.

Flue gas section:

      The flue gas from the 1st stage regenerator passes through a double disc slide valve (DDSV1) for controlling the differential pressure between the 1st and 2nd regenerators. An orifice chamber is provided immediate downstream of the 1st and 2nd regenerator slide valve to reduce the flue gas pressure. As the flue gas passes through each plate the pressure is gradually reduced to the desired outlet pressure. The pressure reduction is the function of the fuel gas volumetric flow rate. To compensate for the varying flow rate through

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the orifice chamber the slide valve provides the flexibility needed in processing varying fresh feed rate.

      The CO rich flue gas exists the orifice chamber and enters the incinerator to convert CO to CO2 to comply with environmental emission requirement.

Catalyst handling 

      Hoppers are used for storage and transfer of fresh equilibrium and spent catalyst. Hopper pressurization is required prior to loading catalyst into FCC. Pressure is lowered when catalyst moves from regenerator to hopper or for loading fresh catalyst. Blower air is used for transportation of catalyst and aeration connections are also provided. Batch loaders and purge streams are provided to prevent back flow.

Main fractionator column 

      The fractionator 18C10 consists of 30 valve trays and 8 rows of shed decks. The reactor effluent, comprising of cracked hydrocarbon vapor, steam and inert gas enters the column at the bottom of the quench section. In this section, products are cooled and condensed. The slurry pump around and decanted oil are withdrawn from the bottom and returned to the top of shed decks. Entrained catalyst is removed from the decant oil in slurry filter 18S01. Fractionation liquid has a tendency for coking. Quench steam is injected to prevent this.

      Sponge absorber lean oil is withdrawn out of fractionator, cooled used as lean oil in sponge absorber. Rich gas from bottom of absorber is returned to fractionator. The total fractionator overhead vapors consist of HCN, LCN, lighter hydrocarbons, steam and inert gases plus tower top reflux. These are condensed in overhead condenser 18EA11 and separated from the gas in overhead receiver 18B11.

 Product Recovery System

      Wet gas from overhead receiver is compressed to 16.9kg/cm2 by 2 stage centrifuge compressor 18K10. The uncondensed vapors, medium pressure distillate and sour water are separated in 18B13.

      The uncondensed vapors are sent to primary absorber 18C14 for C3 and C4 recovery. The absorber overhead products are mixed with lean oil and

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get separated in the reflux drum 18B15. The unabsorbed vapors are routed to sponge absorber 18C15 and semi rich naphtha is pumped to the top tray of primary absorber. The rich oil from the bottom of the absorber is contacted with wet gas compressed effluent from the compressor before flowing to high pressure separator. The off gas flow to amine section for H2S and CO2 recovery. The stripper is designed to remove inerts, C2 and lighter hydrocarbons from liquefied C3 hydrocarbon stream. The stripper overhead is cooled and collected. The stripper bottom is sent to a debutanizer where C3, C4 are separated. Its bottom is again sent to a naphtha splitter where heavy naphtha product (HCN) and light naphtha product (LCN) are obtained. 

Amine treating section 

The absorber gas from the sponge absorber contains majority of H2S resulting from cracking reactions plus CO2 entrained in regenerated catalyst as inert. These acidic gases are removed from absorber gas before being sent to refinery gas pool. To remove gases it is contacted with a 25% wt. solution of diethanol amine (DEA) in absorption tower 18C18. Entrained liquids are separated in a knock out drum prior to this. Lean DEA solution from top tray and sweet gas leaves from the top of the column, flows through wet gas knock out drum 18B20 and is routed to battery limits. The rich DEA and condensed liquid from knock out drums are flashed in another knock out drum and sent to CO incinerator. The strippedH2S and CO2 are sent to SRU.

 

 LUBE OIL BLOCK 

      In lube oil block 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 ten units: 

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Name of the Unit Unit No. Unit Capacity[TMT/YR]

Vacuum Distillation Unit (VDU) U 31 3790Propane De asphalting Unit U 32 800Furfural Extraction Unit U 33 515Solvent De waxing Unit U 34 310Hydro Finishing Unit U 35 225Visbreaking Unit U 37 462N-Methyl Pyrolidine (NMP) Extraction Unit

U 38 350

Wax Hydrofinishing Unit U 39Catalytic iso dewaxing unit(CIDWU) U84 200

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.

VACUUM DISTILLATION UNIT (U 31):

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 grade LOBS feed stock or FCCU feed. Inter Oil ---- 500 N grade LOBS feed stock or FCCU feed. Heavy Oil ---- 850 N grade LOBS feed stock or FCCU feed. Vacuum Residue ---- Feed stock for PDA unit.

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QUALITY MONITORING: K. V at 1000C, Flash Point, Density.

Capacity :1111200 T/year

   Reduced crude oil from atmospheric unit or from tanks is the feed stock for Vacuum Distillation unit. Reduced crude oil is preheated to 285 0C in preheat exchangers and then to 4000C in the furnace. Steam is injected in the furnace to achieve vaporization / prevent coking of the furnace coils. The reduced crude oil 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.

StreamsApproximate boiling range TBP ( degree C )

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REDUCED CRUDE OIL

MP STEAM

VACUUM GAS OIL

SPINDLE OIL

LIGHT OIL

INTERMEDIATE OIL

HEAVY OIL

SHORT RESIDUE

FLUE GAS

VACUUM DISTILLATION UNIT

Gas oil265-362

Spindle oil362-385

Light oil385-462

Intermediate oil465-504

Heavy oil504-542

Short residue542+

 

      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 vapour 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

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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. The vapor leaving the top of the tower is taken into primary ejectors via pre condenser E128A/B from the two overhead vapor lines. The non-condensable gases from E128A/B are successively passed through inter condenser E129 and secondary ejectors. The secondary ejectors exhausts non-condensable after passing through condenser E130 directly to the atmosphere through a vent system via water seal pot B107.

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

e) Recycle to head temperature 375 OC

f) Column base temperature 350 OC

g) Stripping stream flow rate 6780 m3/hr.

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Vacuum Distillation unit-1 (U-31)

RCO• Ex HS & LS crude•Ex Tk 701/702/716•Temp 402 deg C•pressure 130mmHga

Capacity • Rated -270 m3/hr•Normal- 200-250 m3/hr

Gas Oil•yield % wt :6.5•Visc @ 100 deg C: 2.5•flash point deg C : 140•density @ 15 deg C : 0.892•To HSDSpindle Oil

•yield % wt :11.6•Visc @ 100 deg C: 3.5•flash point deg C : 180•density @ 15 deg C : 0.9071•to HSD/VBU/Tar/FCC Light Oil

•yield % wt :0.05•Visc @ 100 deg C: 4-6•flash point deg C : 190•density @ 15 deg C : 0.9081•To Tk-761/VBU/FCC/VBU/Tar

Inter Oil•yield % wt :29.6•Visc @ 100 deg C: 10-13•flash point deg C : 230+•density @ 15 deg C : 0.93•To Tk-760/759/FCC/VBU

Heavy Oil•yield % wt :2.9•Visc @ 100 deg C: 20-24•flash point deg C : 260+•density @ 15 deg C : 0.95•To Tk-758/FCC/VBU

Vacuum slopShort residue•yield % wt :45.90•Visc @ 100 deg C: 1000+•flash point deg C :300+•density @ 15 deg C : 1.03•To PDA/VBU/FCC/Tk

To Ejectors

Vacuum Column

•Top Temp:70-80•top pres: 60-75 •mmHga

Objective:•To Draw Gas oil range Distillates & Lube Distillates by Vacuum Distillation

PROPANE DEASPHALTING UNIT ( UNIT NO – 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 recorded. 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.

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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

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SOLVENT

FURNACE

KOPot

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

evaporators are maintained at the required pressure level so that the vapourised 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 vapours pass overhead and DAO products. The steam and solvent vapours 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 vapourise most of the solvent and to prevent foaming in the flash tower. Vapourised solvent is separated from asphalt in flash tower C-2.

Solvent specification:

Name of component Weight

Propane97.5

Ethane1.0

Butane By difference

Operating Variables: Operating Variables and their effects are described below. The ROSE (Residuum Oil Super Critical Extraction) extraction column temperature and pressure gradient and solvent feed ratio are the most important among them.

1. Extraction temperature and temperature gradient

      Above 380 C propane has a negative temperature co-efficient in respect of asphalt and resin solubility. The top and bottom temperature are maintained at 680 C and 520 C respectively. These temperatures are raised depending on the feed stock 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

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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 is 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, and C-2. Solvent composition is maintained for steady product quality.   OPERATING CONDITIONS :

1. Extraction Column : Short residue feed flow rate ( Mt/hr.) - 4

Temperature ( OC ) - 130Solvent ( Propane ) flow rate ( Mt/hr.) - 283Ratio of Propane/Feed - 6.3 by wt.

Temperature ( OC ) - 53Operating temperature - Top ( OC ) - 68 Bottom ( OC) - 52Operating pressure , kg/cm2 - 40

2. DAO Evaporator columns C-3:i Operating temperature ( OC ) ---- 67

ii Operating pressure ( kg/cm2 ) ---- 23iii Feed flow to column ( Mt/hr.) ---- 274.2iv Feed solvent / DAO ratio ---- 15/1

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3. DAO Evaporator columns C-4: i. Operating pressure , kg/cm2 --- 21 ii Operating temperature in OC

Feed - 90 Top - 190 Bottom - 150.6

iii. Feed flow , Mt/hr. - 93.6

4. DAO Stripper columns C-6: i. Operating pressure , kg/cm2 --- 1.7 ii Operating temperature in OC

Feed - 144 Top - 144 Bottom - 149

5. Asphalt Heater F-1: i. Flow to heater , Mt/hr. - 53.3

ii. Temperature ( OC ) Inlet - 52.0 Outlet - 67.8

iii. Pressure ( Kg/cm2 ) Inlet - 34.0 Outlet - 22.0

6. Propane Condenser E-6:Operating Pressure ( kg/cm2 ) - 21.0

7. Propane Condenser E-7: i. Flow of propane vapour , Mt/hr. – 2.7 ii. Temperature ( OC )

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Propane De-asphalting Unit (U-32)

DAO•yield % wt :20-25•Visc @ 100 deg C: 33-45 cst•flash point deg C : 300+•density @ 15 deg C : 0.93•To Tk 754/755/756

Asphalt •yield % wt :80-75•Visc @ 150 deg C: 384•density @ 15 deg C : 1.06•To U-36

Propane •density @ 15 deg C : 0.53

Short residue•Visc @ 100 deg C: 1000+•flash point deg C :300+•density @ 15 deg C : 1.03•Tk-706/718

Capacity• Rated -100 m3/hr•Normal- 50-80 m3/hr

Extractor Column

Operating Conditions•Solvent/feed ratio : 12/1 Vol/Vol•Pressure: 33-35 kg/cm2•Top temp: 71 deg C•Bot temp: 60 deg C

Objective:•To produce feed stock for production of Bright Stock grade of LOBS

 

FURFURAL EXTRACTION UNIT (UNIT33):    

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.

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 The Furfural extraction unit includes the following sections:

1. De aeration 2. Furfural Extraction 3. Raffinate separation 4. Extract separation 5. Solvent recovery

from raffinate solution from extract solution from water-furfural & furfural-water mixture

6. Neutralized with Na2CO3 solution

   One of the important characteristics of lubricants is the viscosity temperature relationship i.e. viscosity index. Viscosity plays a vital role in the lubrication of moving part of machine. Temperature increase in most of the applications are inevitable, viscosity tends to decrease, thus affecting the performance. A good lubricant should have viscosity variations within specified limits. A higher V.I. denotes less variation and such lubes are used

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FEED STOCK

TO ATMOSPHERE

VM STEAM

FURFURAL

RAFFINATE

DE-AERATOR

EXTRACTOR

FURFURAL EXTRACTION UNIT (UNIT- 33)

EXTRACT

in places where either temperature variations are high or viscosity specification is very straight.

 The low V.I. is due to presence of aromatics in the stock and can be improved by extracting out aromatics. Furfural is a good solvent for this purpose.

      The process is liquid-liquid extraction, where the extract phase is automatic-rich oil plus major quantity of solvent and the raffinate phase is comparatively paraffinic oil plus solvent.

      Solvent is recovered from the two phases by heating, flushing and stripping. Raffinate is routed to dewaxing unit for onward treatment while extract is either blended in F.O. pool or sent as Carbon Black Feed Stock.

The solvent power and selectivity: The activity of a solvent to keep the hydrocarbon component in solution is called its solvent power. For the given hydrocarbons feed and at fixed solvent/feed ratio, solvents that can hold more of selecting hydrocarbons in solution can be termed as solvent with high solvent power.

      Selectivity of a solvent indicates the degree of performance with which a component or a group is dissolved in it to from a mixture.

Best solvent properties:

High solvent power Low light-heavy selectivity and high group

selectivity Much different B.P. from that of feed stocks

processed Low melting point Density of 1.0 to 1.2 gm/cc Low surface tension Low toxicity High thermal/chemical stability Low flammability Low corrosively Low latent heat and specific heat Low viscosity at working temperature High bio-degradability

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      The temperature affects the operating parameters in a solvent extraction process. Hence, an optimum temperature is selected for economic operation.

      The effect of pressure is not appreciable extract for keeping liquids in liquid phase only. A higher pressure also helps in clearer separation.

      Solvent feed ratio is very much important parameter. A high ratio leads to better extraction but increase the operation costs.

 PROCESS DESCRIPTION1. 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 114 OC enters the cooler operating at 100 mm Hg from, where liquid furfural is pumped at 60 OC is pumped into the

59

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 vapour 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 vapour from the extract pressure flash tower at 180 OC are

cooled in drying solvent tower to 165 OC . The furfural vapours 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 vapour 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.

OPERATING VARIABLES

Solvent/ Feed ratio: better raffinate and lower yield with increase in ratio.

Rotating Disc Column Speed: low speed- not enough contact.High speed- inter mixing and bad phase separation.

Interface level: on increase in interface level, lowers the extraction zone, yield and quality. Decrease in interface level, decreases stripping zone and also lowers the yield.

Top and bottom temperature: Top temperature should be maintained at 10OC less than CST.

Extract recycle to bottom: Recycle reduces solubility of desirable components. Increased recycle leads to higher yields but lowers quality of raffinate.

Water in furfural: the presence of water reduces solvent power.

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Oxidised Furfural: It contains acids, polymers and resins and leads to fouling and corrosion.

High Temperature operation of furfural: if the temperature is > 232oC, furfural decomposes, polymerizes and coke deposits.

The temperature affects the operating parameters in a solvent extraction process. Hence, an optimum temperature is selected for economic operation.

The effect of pressure is not appreciable except for keeping liquids in liquid phase only. A higher pressure also helps in clearer separation.

Solvent feed ratio is very much important parameter. A higher ratio leads to better extraction but increases the operation costs.

Furfural Extraction Unit (U-33)

Raffinate•yield % wt :49-65•density @ 15 deg C : 0.88-0.90•IN Raff to Tk 804,806•HN Raff Tk 802•BN Raff Tk 803•LN Raff Tk 801

Extract•density @ 15 deg C : 1.000+•To CBFS/TK 705/FO

LO•density @ 15 deg 0.90IO•density @ 15 deg 0.93HOdensity @ 15 deg C : 0.94DAO•density @ 15 deg C : 0.93

Furfural•density @ 15 deg C : 1.15•B.P : 162 deg C

Capacity • Rated -60-70 m3/hr•Normal- 50-70 m3/hr

Extractor Column

Operating Conditions•Solvent/feed ratio : 1.6-2.11 Vol/Vol•Pressure: 3-3.2 kg/cm2•Top temp: 112-132 deg C•Bot temp: 68-88 deg C

Objective:•To Improve Viscosity Index (VI) of LOBS by removing Aromatics.

 SOLVENT DEWAXING UNIT (UNIT-34):

Feedstock: Raffinate from furfural extraction unit.

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Product: Dewaxed oil & Slack Wax.

Quality Monitoring:DWO: Pour point, Flash point, KV @ 100oC & 40oCSlack Wax: Flash Point.

 Feed of this unit is the distillate obtained from VDU either directly or after processing the same in Furfural Extraction Unit.

      Either of the following is used as solvent.

1. Bright stock (HVI, LVI). 2. Heavy Neutral (HVI, LVI). 3. Intermediate Neutral (HVI, LVI). 4. Spindle Oil (HVI, LVI).

Objective: Objective of solvent Dewaxing Unit is to remove paraffinic hydrocarbons of the extract to bring down the Pour Point Value in lube base stock. In that case, it will be suitable for low temperature applications.

Theory: Dewaxing is a complex process in which extraction and crystallization followed by filtration occurs. The solvent blended extracts the lube oil (which is desired product) is crystallized from and the wax (i.e., undesired part) is collected from a two phase mixture of MEK and toluene. In Haldia Refinery toluene is used as solvent to dissolve the desired component of feed stocks.

Antiwax Solvent: Antiwax solvent, also called wax-rejecter (MEK) is use 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 imposes highest solvent effect on oil and little solvent effect on wax.

Oil Miscibility Temperature:  Oil miscibility temperature is the lowest temperature of the blend which without any problem can be used Dewaxing purpose. Below this OM temperature a second oil phase which is rich in wax generates in addition to oil in solvent and wax phases. To avoid it, the dewaxing temperature is kept above oil-solvent miscibility temperature for the given solvent blend and feed stock. Otherwise the

62

filtration becomes more erratic, wax contains more oil and also Pour Point of oil will be affected with increase in MEK in the blend.

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.

      The size and shape of wax crystals are affected by:

1. Nature of feed stock. 2. Hydrocarbons composition.

Normal paraffin = Plate type crystal

Isoparaffins       = Needle type crystal

Napthenes     = Microcrystalline

Boiling ranges of the feed stock: As boiling range increases, its viscosity increases and composition changes from n-paraffin to iso-parrafins and napthenes. Again if viscosity increases more solvent is required for dilution which is necessary for crystallization and to reduce the precooling in chiller.

Rate of chilling:  Faster/sock chilling results finer crystals which clog the filter medium and also carry more oil into crystal lattices.

Mode of solvent addition: Minimum solvent dilution at the time of nucleation provides the few nuclei of wax crystal and gives the best crystals for filtration. Wax cycle growth is also benefited by low concentration of initial dilution as well as long residence time in chillers. Low initial dilution concept is not applicable for

high viscosity /high Pour Point feed stock but applicable and useful for medium/low viscosity stocks.

Viscosity of crystalline media: The viscosity of media must be favorably low and uniform to keep the crystal size distribution to a limited range that would give good filtration rate.

PROCESS DESCRIPTION

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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 a 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

64

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 vapourised by the overhead vapour 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 vapours go for solvent drying (34-C-10) where bottom liquid of 34-C-3 flows by gravity to 18 th 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, liquefication and evaporation. It is a closed circuit system.Ammonia vapour rescued from the cooler, chiller, heat exchangers are send to the refrigeration section for the two cooling stages at –15 oC and 30 oC respectively. The plant is equipped with two centrifugal compressor for compression of such vapour.

OPERATING PARAMETERS

Boiling ranges of the feed stock: As boiling range increases its viscosity increases and composition changes from n-parrafin to iso-paraffins and napthenes. Again if viscosity increases more solvent is required for dilution, which is necessary for crystallization and to reduce the precooling in chiller.

Rate of chilling: Faster/sock chilling results finer crystals, which clog the filter medium and also carry, more oil into crystal lattices.

Mode of solvent addition: Minimum solvent dilution at the time of nucleation provides the few nuclei of wax crystal and gives the best crystals

65

for filtration. Wax crystal growth is also benefited by low concentration of initial dilution as well as long residence time in chillers. Low initial dilution concept is not applicable for high viscosity/high Pour Point feed stock but applicable and useful for mediem/low viscosity stocks.

Viscosity of crystalline media: The viscosity of media must be favorably low and uniform to keep the crystal size distribution to a limited range that would give good filtration rate.

Rate of agitation: The constant motion of solution keeps a steady growth of crystals. Absence of agitation would lead to decomposition of wax crystals on internal surface and affect the performance.

Oil Miscibility Temperature: Oil miscibility temperature is the lowest temperature of the blend that without any problem can be used for Dewaxing purpose. Below this OM temperature a second oil phase, which is rich in wax, generates in addition to oil in solvent and wax phases. To avoid it, the dewaxing temperature is kept above oil-solvent miscibility temperature for the given solvent blend and feed stock. Otherwise the filtration becomes more erratic, wax contains more oil and also Pour Point of oil will be affected with increase in MEK in the blend.

Solvent: Methyl Ethyl Ketone + Toluene

Feed: IN/BN/HN Raffinate

Slack Wax•To:IFO/Tar/FCC/762

Vacuum rotary Filter

Solvent De-waxing unit (U-34)

Capacity • Rated -20-55m3/hr•Normal- 10-25 m3/hr

Operating ConditionSolvent/Feed ratio: 3.5-8.0Dewaxing temp: -14 deg C

De-Waxed Oil•IN DWO Tk712,714,851,853•BN DWO Tk 716•LN DWO Tk 713,852

VacuumPulling

Rotary Drum

Boot

Scraper Blade

Objective:•To Improve Pour Point of LOBS by removing Paraffines.

66

HYDRO FINISHING UNIT(UNIT – 35):

     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.

 The aim of the hydro finishing unit is to improve the color and the color stability of Lube Base Stocks.

The process is a mild hydro treating one, using a catalyst made of sulphide from Group-VIII and VI A of periodic elements table, combined with non acidic carriers e.g., ones of the alumina type

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Many reactions are involved during hydrofinishing and we can distinguish the following:

1. Hydro-desulphurisation.2. Mild hydro-denitrogenation.3. Olefins hydrogenation.4. Mild aromatics hydrogenation.

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FURNACE

COMPRESSOR

K.O. DRUM

DWO OIL FEED

HYDROGEN GAS

AMINE SOLVENT

RICH AMINE

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)

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

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

PROCESS DESCRIPTION:

The following chemical reactions are involved:

1.Desulphurisation: The sulfur is present in the feed under various forms such as mercaptans, sulphides, disulphides 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 + H2SAll 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.

2.Mild hydro-denitrification: Nitrogen is contained essentially in heterocyclic compounds. When hydrofinishing 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 colour stability.

Amines RNH2 + H2 = RH + NH3

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

3.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.

4. Very mild hydrogenation of aromatics: Normally in the hydrofinishing aromatics is not hydrogenated. Nevertheless, the analysis

69

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.

5.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.

Reaction section: Lube oil from storage tank is fed to the unit by feed pump 35-P-01 A/B. The feed rate is controlled by 35-FRC-03. Hydrogen rich gas is a mixture of makeup gas boosted by hydrogen makeup compressor 35-K-01 A/B and of recycled gas boosted by recycles compressor 35-K-02 A/B/C. The flow of makeup gas is controlled by 35-PRC-01 acting on compressor by-pass, which allows maintaining a constant pressure in the suction drum of compressor 35-B-01. The makeup flow is recorded on 35-FR-02. The lube oil feed and hydrogen gas are mixed, preheated by drier (35-C-03), bottom is exchanger 35-E-06 (shell side) they by exchanges with the reaction effluent is exchangers 35-E-1 A/B/C (shell side).

During the above operations the effluent is sent directly to atmosphere at high point provide for the purpose. The reactor effluent from 35-R-01 gives up heat to the reactor feed in exchangers 35-E-01 A,B,C (tube side) before flowing to the high pressure separator drum 35-B-02. The required temperature of 35-B-02 is controlled by 35-TRC-01 which regulates the by-pass reactor feed around exchanger 35-E-01 by acting in 3-way valve 35-TRCV-01. The reactor effluent is subsequently flashed in the first high pressure separator 35-B-02 at high temperature (at least 200 oC). The liquid from 35-B-02 flows to the low pressure separator 35-B-04 (at high temperature) under level control 35-LIC-02.

70

The vapour from 35-B-02 is cooled in the water cooler 35-E-02 and flows to the second high pressure separator drum 35-B-03 at low temperature (50 oC). The liquid from 35-B-03 goes to low pressure separator under level control 35-LIC-03.

B-4

E-7

B-8

B-5

B-6

C-2

C-3

P-2A/B E-6A/B E-5Feed Ex P-1A/B

To E-1A/B/C s/s

CW

Stripping steam

E-4

CW

E-3

CW

VM steam

PC-04To fuel gas

LC-06

LC-08

LC-11 LC-18

To drain

drain to Sour Water

Product R/D

LC-09

Page 2 of 2

To F-1

#15

#1

CW

From B-2 / B-3 bottom

Haldia RefineryLube Hydrofinishing unit

(H2 separation & Product Drying)

PRPD BY: V.SUNIL KUMAR,PSECHKD BY: I.B.BERA,PSM

Ejectors

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

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The feed has the following characteristic:Viscosity at 100 oC = 5.05 c.p.Pour point = 27 oC

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.

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FURNACE

SOAKER VISBREAKER

FEED

GAS OIL QUENCH

GAS OIL

VB TAR (FOR FURTHER PROCESSING)

VISBREAKER UNIT( Unit-37)

FRACTIONATOR

VISBREAKER NAPTHA

Soaker Visbreaker Unit (U-37)

VB Gas (To FG)•yield % wt :0.5-2.0•To Fuel Gas

VB Tar•yield % wt :86-90•Visc @ 150 deg C: 200-2000•To FO /TPS

Asphalt +SR +LO + SO•visc @ 50 deg C: 1000-30000•temp 445 deg C•pressure : 5-6 kg/cm2

Capacity • Rated -70 m3/hr•Normal- 55-70 m3/hr

VB Naptha•yield % wt :3-8•To MeroxTreatment

VB Gas Oil•yield % wt :2.5-10•To VB Tar / HSD

Fractionator

Objective:•To reduce the viscosity of feed stock by mild Thermal Cracking.

NMP EXTRACTION UNIT (UNIT- 38)

73

74

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)

The solvent used for extraction is NMP i.e., M-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. The water vapour leaving drying column (38-C-10) is routed through the de aerator (38-C-01) and the contaminate NMP (if present) is absorbed by the feed meeting stream countercurrently.    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.

De aeration/extraction section: The charge oil from offside is pumped through the charge pump to de aerator (38-C-01) after heating to 110 oC through the de aerator feed preheater. Stream heater 38-E-01 located downstream of 38-E-01 A/B is used to heat the de aerator feed during startup. Dissolved air in feed is stripped out by L.P. steam coming from solvent drying column (38-C-10). The solvent is pumped from the bottom of the solvent drying column (38-C-10) by solvent charge pumped (38-P-05 A/B) to the top of the extractor under flow control.

The oil sprayed in the extractor rises through the tower as droplets and meets the continuous phase, following the oil and the solvent a counter current

75

flow between solvent passing through the packed beds dissolves aromatics mainly condensed and polymeric aromatics. The solvent rich extract phase leaves the bottom of the extractor column to the extract recovery section under interphase level control maintained at the top section of the extractor. The hydrocarbon phase having mainly non-aromatics components (paraffins and napthanes with considerable amount of monoaromatics) leaves the top of the column as raffinate mixture with about 12-20% solvent.

Raffinate recovery section: The raffinate mixture from the top of the extractor is subjected to solvent recovery. It is collected from the extractor top and then collected at the raffinate mixture drum (38-V-01). The raffinate mix which is heated to about 271 oC in the natural draught raffinate mix heater (38-F-02) is then flashed in the raffinate mix flash column (38-C-03) operated at 0.16 kg/cm2 abs. Then it enters the raffinate stripper (38-C-04) under flow control. The solvent vapour leaving the column top (38-C-03) is condensed in the exchanger (38-E-04) and water cooler/condenser (38-E-24) and it is sent to the vacuum flash condensate drum (38-V-05). From 38-V-05 the condensed liquid is finally pumped to the solvent drying column 38-C-10.

Extract recovery section: Separation of solvent from extract mixture having solvent content of 78-83 % is subjected to solvent recovery in this section. The extract mixture from extract bottom (38-C-03) is collected in extract mixture drum (38-V-06) is maintained by split range controller with inert gas. The extract mixture from 38-V-06 is pumped by pump to the flash column (38-C-05) through a series of exchanger.

Solvent drying section: The solvent vapours from L.P., M.P., and H.P. flash columns goes to the 5th tray (from bottom) of solvent drying column 38-C-10. The condensed from extract vacuum flash column pumped from vacuum flash condensate drum by vacuum flash solvent pump and fed to the 7th plate of the solvent drying column (38-C-10). The condensate (water) from solvent drying column accumulator drum (38-V-04) is pumped by solvent drying column reflux pump to the 27th plate of the column at 55 oC.

Solvent utility/conservation section: In acidic medium NMP, in presence of air undergoes degradation. Besides, the de aeration of feed and nitrogen blanketing in tanks, vessels and columns, the pit of the solvent is controlled by neutralization, using sodium carbonate. The sodium

76

carbonate solution from sodium carbonate mixing pot (38-V-11) is injected both to solvent drying column accumulator drum (38-V-04) and to the extract mixture extract mixture solution drum (38-V-06) with sodium carbonate injection pumps (38-P-14 A/B).

NMP Extraction Unit (U-38)

Extract•density @ 15 deg C : 0.9692-1.0191•To CBFS/TK 705/FO

NMP•density @ 15 deg C : 1.15•B.P : 204 deg C

Capacity • Rated -47-56 m3/hr•Normal- 40-50 m3/hr

Extractor Column

Raffinate•yield % wt :40-56•density @ 15 deg C : 0.875-0.900•IN Raff to Tk 804,806•HN Raff Tk 802•BN Raff Tk 803•LN Raff Tk 801

LO•density @ 15 deg 0.90IO•density @ 15 deg 0.93HOdensity @ 15 deg C : 0.95DAO•density @ 15 deg C : 0.93

Operating Conditions•Solvent/feed ratio : 1.75-2.05 Vol/Vol•Pressure: 2 kg/cm2•Top temp: 70-95 deg C•Bot temp: 60-85 deg C

Objective:•To Improve Viscosity Index (VI) of LOBS by removing Aromatics.

WAX HYDROFINISHING UNIT

PURPOSE: To improve properties like color and color stability of paraffins. Ca talysts allow hydrogenation of aromatics and removal of sulphur and nitrogen. Oxygneated compounds that may be present will be hydrogenated. The unit produces microcrystalline wax from de-oiled wax.

OPERATING CONDITIONS:

• Reactor inlet/outlet pr. : 135.5/134 kg/cm2g

• Reactor inlet/outlet temp : 300 def C

• Liquid Hourly space velocity : 0.25 hr-1

• Hydrogen Partial pressure : 100 kg/cm2g

• Hydrogen to Hydrocarbon mole ratio : >500

• Hot HP separator : 180 deg C/132 kg/cm2g

• Cold HP separator : 40 deg C/131.7 kg/cm2g

77

• HP Purge : 36 deg C/66 kg/cm2g

• LP Seperator : 185 deg C/6.0 kg/cm2g

• LP Purge : 40deg C/4.4kg/cm2g

• Liquid in to stripper : 185deg C/0.3 kg/cm2g

• Liquid MCW ex drier : 180deg C/0.082 kg/cm2g

Feed: De-oiled BN wax•Oil content: 2% max•Ex TK -763

Wax Hydro-finishing Unit(U-39)

Product: Micro crystalline Wax• Density : 0.86-0.87•colour : 0.5 max•Visc, cst @98.9 Deg C: 15-20•Flash:>260 deg C•To TK - 810,811,812

Reactor

Operating ConditionsTemp: 340 deg Csystem pressure: 134 kg/cm2

Capacity • Rated -2083 kg/hr•Normal- 900-1300 Kg/hr

Hydrogen•Purity: 80% vol

Objective:•To Improve Colour & Colour Stability of LOBS by removing Sulphur, NH3 etc

78

CATALYTIC ISODEWAXING UNIT: (UNIT 84)

OBJECTIVE: To produce Group-II & III grade LOBS.

MAJOR REACTIONS: Hydrotreating, Catalytic Dewaxing & Hydrofinishing.

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 hydrotreating reaction takes place where nitrogen is converted to NH3 while sulphur to H2S.Reaction is exothermic in nature, so interbed 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

79

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. Vapour 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.It is then sent to low temperature seperator 84-B-02.There are two phases liquid and vapour are separated. Vapour phase goes to amine and water wash section for recycle gas purification and liquid goes to HP stripper. Vapours from 84-B-02 are scrubbed with lean amine in HP amine absorber 84-C-02 for H2S removal. Overhead vapours from 84-C-02 goes to amine knock out drum 84-B-03 and then to wash water column 84-C-03 for NH3 removal. Rich amine from 84-C-02goes to amine degassing drum to flush off dissolved gas and liquid goes to amine recovery unit. Sweetened vapour from 84-C-03 is reheated in HDT stripper overhead/treat gas heat exchanger 84-E-04.

Preheated clean treat gas is then recombined with bottom liquid product of 84-C-01 which is heated in 84-E-06.Final heat to dewaxing reactor temperature is achieved is MSDW reactor charge heater 84-F-02.

In MSDW reactor the paraffin in the waxy oil feed are selectively cracked and isomerised in presence of hydrogen and MSDW catalyst to improve feeds cold flow property. Reaction being exothermic so inter bed quenching is required. MSDW reactor effluent are cooled in heat exchanger 84-E-06 against waxy feed and then it is charged to HDF reactor 84-R-03.Here the contaminant in the oily feed are removed and most of the olefins are saturated to improve product quality and stability. Reaction is mild exothermic.

Low pressure recovery section: Liquid from LTS B-05, HTS B-04 and HDT LTS B-02 are fed to HP stripper 84-C-04 for separation of naphtha and light materials from dewaxed oil streams. Pressure letdown, heat in HTS liquid and MP stripping steam to 84-C-04 bottom provided for flashing and stripping. Overhead vapours are cooled and condensed in HP stripper overhead condenser 84-E-12.Effluent from 84-E-12 is phase separated in HP stripper overhead accumulator 84-B-10.Vapours from 84-B-10 is contacted with lean amine in LP amine absorber 84-C-09 for H2S

80

removal, before discharging into fuel gas header under pressure control of 84-B-10.Unstabilised naphtha product is pumped from84-B-10 to distillation unit for stabilization a portion of naphtha material is refluxed. Bottom product from 84-C-04 is pumped to vacuum fractionator charge heater 84-F-03 under level control..

In vacuum fractionator 84-C-05 distillate and lighter material are separated from dewaxed base stock to avoid thermal cracking and degradation. Distillation is carried under vacuum. Overhead vapour from fractionator is cooled and condensed and sent to vacuum fractionator overhead accumulator 84-B-11 for phase separation. Part of the liquid, light distillate cut are refluxed, balance of the liquid is pumped out as net product to refinery storage tank.

To meet quality specification on the dewaxed base stock product a heavy distillate cut is produced. This cut is steam stripped and vacuum dried in heavy distillate stripper 84-C-07 and vacuum dried in heavy distillate drier 84-C-08. The heavy distillate product is pumped to cooler. Dewaxed based stock product from bottom of 84-C-05 is vacuum dried in vacuum drier.

Catalytic De-waxing Unit(U-84)

ReactorsR-1/2/3

Operating ConditionsR-1 WART : 318-344 deg C

Press: 140 kg/cm2

R-2 WART : 318-329 deg CPress: 126 kg/cm2

R-3 WART : 220-225 deg CPress: 118 kg/cm2

C-4 Temp: 232-238 deg CPress: 4.5 Kg/cm2

C-5 Press: 80 mmHGT/B Temp: 186-240/252-343

Capacity • Rated –40.8 M3/hr• Normal-20-25 m3/hr

Hydrogen•Purity:98% Vol

Feed:IN/BN/LN Raffinate

Wild Naphtha•Yield:2.74%wt•Dist Range: C5-150 deg C

To Ejectors

Light Distillate (HSD)•Yield:8.85% wt•Flash: 35 deg C,min•Dist Range: 165-364•Pour Pt: 3 deg C max

Heavy Distillate/Light Lube•Yield: 16.52%wt•Sp Gr: 0.84•Flash : 218 deg C•Visc, cst @40 deg C: 36.5To Ejectors

Gr-2 Lube R/D•Yield: 70.88%wt•Sp gr: 0.88 •Flash: 232 deg C,min•Visc, cst @40 deg C: 95-105•VI: 105 min•Pour Pt deg C: -15 max

C-5

C-6

C-4 B-11

Objective:•To Produce Group-2 LOBS with high VI & low Pour Pt by Isomerisation of N-paraffines

OIL MOVEMENT AND STORAGE: 

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This unit plays an important role in the storage of imported crude brought by tankers. Refinery storage tanks are used in storage of crude oil and finished petroleum products. Products from these storage tanks are dispatch for marketing by tankers, wagon, drums, cylinders etc.

The mode of dispatch depends on the distance to be traversed and on the capacity of the pump. For the pumping of highly viscous oils, positive displacement type pump are used where as in the case of non viscous oil centrifugal pump are used.

The broad functions of OM & S are listed as follows:i. Receipt and storage

Crude oil from tankers Intermediate and finished products from process units.

ii. Preparation and supply of feed to various unitsiii. Blending of productsiv. Despatch of productsv. Supply of fuel oil to furnaces

vi. Unloading, storing, supplying various solvents and chemicals to units

vii. Recovery of steam condensateviii. Accounting of petroleum products and observing necessary

customs and excise formalitiesix. Effluent treatment

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

a. Calibration of tank wagons and tanksb. Cleaning/Steam flushing of tank wagonsc. Decantation/ trans-shipment of tank wagons and tank.

TANK FARM:Types of tanks: Generally, the tanks used for storing petroleum products are:

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

iii) Fixed cum floating roof type.

i) Fixed cone roof type tank:

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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.

iii)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.

iii)Fixed cum floating roof type:These type of tanks are used to store unsaturated hydrocarbon solution. From outside these tanks are looks like fixed roof tank. But there is floating roof inside the tank. Nitrogen blanketing is there to prevent any kind of explosion .Although several other design are also made according to the needs tanks are provided with

                  a) Manhole on the shell and roof.

b) Product inlet and outlet nozzle.

              c) Drains.

              d) Staircase and ladder.

              e) Mechanical type level gauge.       

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              f) Open vane with wire mesh or Breather valve or vent with flame arrest depending on the service the tanks are provided with

             a)  Sampling device

             b)  Temperature gauge

           c)  Jet mixing nozzle

             d)  Inert gas blanketing

             e)  Steam heating coils

Product is taken to this tank though the inlet by different pumps. There are two outlet one for blending and product conveying and another for drainage. Generally products from different units also contain some amount of water with them. This unwanted water is drained through that outlet. Some other important operation such as blending is also done by the outlets. In blending different oil are mixed up to meet the specifications of the final product oils such as Motor Speed Oils (MS), Diesel etc. Constant circulation of the product of tank is done for better mixing through these outlets.

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 tanksii) Recording the temperature of the product

iii) Drawing a representative sample of the product.

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

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ii) RussiaIn 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

. Bitumen filling station:Bitumen has two grades:

i. Industrialii. Straight

IOC Haldia produces straight grade only .The straight grade can again be of three types depending on the penetration point. This grade also has some classification viz. 80/100, 60/70, 30/40 etc. At a time one particular type of bitumen is loaded into the tank. Bulk loading is done separately for each grade of bitumen through dedicated lines.

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. The capacity is likely to increase to 2,50,000 MT/a . Bitumen filling station has been designed to fill 82,000 drums per month and works for two shifts per day. The remaining is dispatched by tanks/trucks/wagons.

NORMAL OPERATION:-

1. Check DM water level in steam drum. 2. Check steam pressure in steam drum. 3. Check inlet/outlet temperature of Bitumen &MP steam pressure.

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4. 6Nos of semi automatic filling machines (Altus, Italy) are provided to fill bitumen drum as weight controlled basis.

5. Filling empty drums to filling machine is done manually is a roller conveyor.

6. Drum centering and positioning at the filling point is automatic. 7. Filling valve closing is automatic with cutoff point set at 156.5 kgs. 8. Removal of filled drum from machine plat from and feeding to power

driver roller conveyor is done manually. 9. Pressure filling is done through back pressure control valve with

controller 4 kg/cm². 10.There is an electric counter to count the number of drum fills. 11.Open mouth of filled bitumen drums are taken at 4Nos. of diverters by

chain conveyor, Forklift or jhumka there after take the said drum and stack in storage yard.

                 a) Drum filling temperature oppose 100-120ºc.

                 b) Filling pump capacity -85cum/hr with 9 kg/cm² 

12.Total time for filling of one drum including feeding empty   drums20-23seconds and removal of filled drum from machine from platform.

Tank Truck Loading ( TTL ) : The tank truck loading system consists of fourteen points through which different fuels are filled in trucks. The trucks consist of three (generally) chambers in which different fuels are filled as required. The fuels are pumped through the pipes and the PDM (positive displacement meter) measures the flow rate. There is also a liquid controller which removes the liquid vapour (if any). Different fuels like ATF ( Aviation Turbine Fuel ) , MS ( Motor Spirit ) , MTO ( Mineral Turpentine Oil ) , SKO ( Super Kerosene Oil ) , HSD ( High Speed Oil ) , JBO ( Jute Batch Oil ) , FO ( Furnace Oil ) , CBFS ( Carbon Black Feed Stock ) and Microcrystalline Wax are filled in this station .

Operation: The trucks are weighed and taken to the appropriate point where first the dip is checked. There is a mercury terminal in the gantry which display the specification of loading to be done for example the no. of chambers and capacity etc. on driver’s card punching .The loading operation

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is completed on supervisor’s card punching. Then the truck is weighed again.  Subtraction of the tear weight and gross weight gives the net weight. 

TANK TRUCK CONTRUCTION:-  Tank truck of multi –compartment type 10-28KL capacity are used for dispatch of product by road and either be single product or on mixed load.

Fitting of the tanks trucks (for each compartment):-

Manhole with cover-breather valve

Fill valve- Discharge valve

Dip pipe – Moster valve

Vent pipe.

TANK TRUCK MUST MEET THE FOLLOWING STATIONARY REQUIREMENTS:-

a. Compartment wise calibration chart b. MVI Registration c. Explosive licence from CCE.

Tank Wagon Loading ( TWL ) : The petroleum products (mainly MS, HSD etc.) are also dispatch to different parts of India through railway wagon.

Operation:  Two types of wagon are used in this purpose viz. General Purpose and BPD (of capacity 64700 lit.) .A primary test is taken for body leakage. Again the dip is calibrated with the theoretical data. Initially 700 to 1000 lit. Product is given for leak-testing and then the tested wagons are filled with the products.                  Tanker Operation: To import crude and some finished products such as MS, HSD, and The purpose of importing the latter two is that country wide demand of these two products is more than the amount produced in the refinery. Some other companies such as H.P, B.P also import crude from abroad.

Types & Capacities of Tanker :

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1. G.P(general purpose) series : Small ships (up to 25,000 tons) 2. M.C(medium capacity) series : 25,000 to 45,000 tons 3. L.R(low range) series : Three categories namely L.R-1,L.R-2,L.R-

3(45,000 to 1,20,000 tons) 4. V.L.C.C(very large crude carrier) :1,20,000 to 2,80,000 tons 5. U.L.C.C (ultra large crude carrier) :( 2, 80,000 tons onwards) vessels

of these type do not come to Indian ports.

► per day requirement of Haldia Refinery is 17,000 tons of crude

► as ships move up and downwards due to unloading, and in the time of tide and ebb tide a special type of joint (chickson) is used in the pipes between ship & shore. Hinge type joints are used in the coupling.

LPG STORAGE AND FILLING: LPG stands for liquefied petroleum gas which is a mixture of mainly butane and propane and also some unsaturated hydrocarbons like propylene and butylenes.

As per Indian standard specifications:-

a. Commercial butane b. Commercial propane c. Commercial butane propane mixture(LPG produced at

IOC)

Areas covered with the LPG plant:-

1) Receipt of LPG from crude distillation unit.

2) Storage in Bullets & Horton sphere

3) Filling operation in cylinders & bulk

4) Dispatch in cylinders & by bulk

5) Transfer of liquid propane to Deasphalting unit 

LPG Bulk Storage :

        1) Horton sphere- Four number1500 m³ normal capacity.

      2) Bullets-Eight number of 150m³ normal capacity

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3) Mounted bullet- 1500 cubic meter.

Bulk Storage:- LPG and Propane are obtained from other units. Propane is stored in three bullets LPG in the rest five bullets. The LPG from the bullets is then transferred to Horton sphere.

  Horton Sphere:- It consists of a pipe line through which the LPG enters and leaves when required. The vapour is removed through another pipe line. When the pressure inside the sphere increases the vapour is removed by a safety pop to the flare. The LPG in Horton sphere is filled up to 10.1 m, the height of which is 11 m. The quantity of LPG inside the sphere is measured by the gauges the top and the temperature of the LPG are also measured by it.

Bullets :-    These gauges are used to check the level of LPG and Propane inside the bullets. For LPG the bullets are filled up to 210 cm to 220 cm, and for propane it is up to 160 cm, the height of bullets being 260 cm. Water draining and safety pop (for high pressure) are provided for both the systems. Bulk storage is done by mass flow meter.

Mounted bullets: These types of LPG storage are introduced to absorb the shock wave if any explosion occurs. Capacity of these tanks is 1500 cubic meter. Bullet tanks are installed inside the concrete layer.

Bulk Loading:- The trucks where LPG is to be filled are taken to the site of bulk storage. The weight of empty trucks and filled up trucks are found on a weigh bridge. Their information’s are sent to the control room which gives the approval for the amount of LPG to be filled in. Two pipes are there in the filling site, one through which the product enters the truck cylinder and the other through which the vapour is taken out to the Horton sphere and the bullets. The trucks are filled up to the required level and then dispatched. There are six bulk filling sections and three weigh bridges having capacities 50MT, 30 MT, 50MT.        

Effluent Treatment Plant (ETP):

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      All the effluents from the refinery are subjected to a purification process in ETP. Hence, it is one of the important parts of the plant. 

EFFLUENT TREATMENT FACILITYRaw Effluent from different process units

I nfluent Sump

API Separator

Oily Sludge

Oil

EqualisationPond

FlocculatorFlashMixer

Alum + H2O2 DOPE

Chemical Sludge

DAF

Satu

ratio

nV

ess

el

Air

Compressed

Bio-Tower Feed Sump

DAP + Urea

New Aeration Tank

Old Aeration TankBio-Tower

Final Clarifier

SecondaryClarifier

I nner Sump

Filter Feed Sump

PSF ACF

Reuse In PCT

TreatedWater Pond

FireNetwork

PDAScrubber

Waste Sludge ToDrying bed

Oil To Slop Oil Tanks

Holding Tank

(TK-104)

EFFLUENT TREATMENT PLANTEFFLUENT TREATMENT PLANT

RiverHooghly

Fire Tank

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.

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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 ,destroy 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.

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2) BIO-CHEMICAL OXYGEN DEMAND (BOD): It is not a pollutant itself, but it’s a characteristics 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 liter 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 liter (mg/L), which indicates the mass of oxygen consumed per liter 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.

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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.

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 sedimentationii) Filtrationiii) Ion exchangeiv) Reverse osmosisv) Carbon adsorption

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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 is 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.

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

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 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 mass in aeration tank. 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.

PRODUCT DESPATCH

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.

It is done by four different ways:

1. Road (15%). 2. Rail (23%).

3. Barges & tankers (22%). 4. Pipelines (40%).

There are two main pipelines present

1. HMR (Haldia – Mourigram – Rajbandh)

2. HB (Haldia – Barauni)

  CONCLUSION

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      Industrial training is very much important for chemical engineering point of view. Here all units very much important and every unit have an important objective.

      Form CDU, we are knowing how to occur physical separation and deferent products and various process equipment and unit operation

      Form VDU, we know how to occur physical separation and deferent products and various process equipment and unit operation. Here we are seeing how to occur vacuum.

      From DHDS, KHDS & SRU, we get wide knowledge of sulfur recovery which is much important for environmental aspect and we know how to remove sulfur and various process equipment and unit operation

      Today   LPG &Gasoline are more important for automobile and domestic purpose, but form CDU, we get less amount LPG & Gasoline than our requirement. So, FCCU give LPG & Gasoline which is more important for our requirement. 

       Haldia refinery take important role for Lube oil production and separation of aromatics wax and asphalt from lube oil is very much important.

 Above all from the point of view of a chemical engineering, it is very much important. Actually this plant is the application of mass transfer, heat transfer, fluid mechanics and thermodynamics which is close relation and heart of chemical engineering.

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