VOCATIONAL TRAINING REPORT

INDIAN OIL CORPORATION LTD.

MATHURA REFINERY

Submitted By:SWEETY CHANDAK

B.TECH, CHEMICAL ENGINEERING

MNNIT, ALLAHABAD

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Indian Oil Corporation LtdMathura Refinery-281005

U.P, India.

I, SWEETY CHANDAK, student of MOTILAL NEHRU NATIONAL INSTITUTE OF TECHNOLOGY, Chemical Engineering (B.Tech), roll no: 20129052, have done training in IOCL Mathura refinery from 18/05/2015 to 15/06/2015 under the guidance of Mr. Hari Shankar (CPNM, production department) in following process areas:

1) Overview of refinery.

2) Studied FCCU in detail and have done material and energy balance of reactor and regenerator section.

3) Calculated NPSH available for the feed pump.

HOD Signature & Stamp

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ACKNOWLEDGEMENT

It is great that Indian Oil Corporation Limited provides training to a large number of students like us for practical assimilation of knowledge pertaining to our respective disciplines. After the completion of the training program, I found it to be of immense help, not only in supplementing the theoretical knowledge, but also by gaining highly practical knowledge regarding the actual work carried out in a Refinery Plant.

I would like to express my gratitude to Mr. R. SAXENA (PNM) who helped me in any way to complete my project work.

I am also very grateful to Mr. Vivek Vikram Singh (Section In-charge Engineer, FCCU) & Mr. Aakash Puri (Section In-charge Engineer, FCCU) who patiently explained the working of the plant and provided the needed conceptual understanding for the project. The series of discussions with him has increased my practical knowledge about the plant and the industry.

I am heartily thankful to all unit heads and all technical & Non-technical staff of MATHURA REFINERY for their great efforts to enhance my practical knowledge.

Thank you once again.

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TABLE OF CONTENTS

S.NO PROCESS UNIT1) INDIAN OIL REFINERY OVERVIEW

2) MATHURA REFINERY OVERVIEW

3) REFINERY PROCESS

4) PROCESS UNIT DESCRIPTION

4) a) AVU (ATMOSPHERIC VACUUM UNIT)

4) b) FCCU(FLUIDISED CATALYTIC CRAKING UNIT)

4)c) VBU(VISBREAKER UNIT)

4)d) CCRU(CONTINUOUS CATALYTIC REFORMING UNIT)

4)e) DHDT( DIESEL HYDROTREATING UNIT)

4)f) SRU(SULFUR RECOVERY UNIT)

5) PROJECT -1

MATERIAL AND ENERGY BALANCE OF REACTOR AND REGENERATOR

SECTION OF FCCU

6) PROJECT-2

CACULATION OF NPSH AVAILABLE FOR THE FEED PUMP.

INDIAN OIL REFINERY: - AN OVERVIEW4

Introduction

Indian Oil Corporation Ltd. is India's largest company by sales with a turnover of

Rs.271,074 crore and profit of Rs. 10,221 crore for the year 2009-10.

Indian Oil is the highest ranked Indian company in the latest Fortune ‘Global 500’

listings, ranked at the 98th position (2011). Indian Oil's vision is driven by a group

of dynamic leaders who have made it a name to reckon with. Indian Oil Company

Limited, a wholly owned Government company was incorporated on 30 June,

1959 to undertake marketing functions of petroleum products. Later, Indian Oil

Corporation Limited (IOC) was set up on 1st September, 1964 by amalgamating

the Indian Refineries Limited (started in August, 1958) with the Indian Oil

Company Ltd., for better coordination between refineries and marketing. Indian

Oil Corporation Limited or IOCL is India’s largest commercial enterprise and the

only Indian company to be among the world’s top 200 corporations according to

Fortune magazine. It is also among the 20 largest petroleum companies in the

world. The Indian Oil Group of companies owns and operates 10 of India's 20

refineries with a combined refining capacity of 65.7 million metric tonnes per

annum (MMTPA, .i.e. 1.30 million barrels per day approx.). Indian Oil's cross-

country network of crude oil and product pipelines spans 10,899 km with a

capacity of 75.26 MMTPA of crude oil and petroleum products and 10 MMSCMD

of gas. This network is the largest in the country and meets the vital energy needs

of the consumers in an efficient, economical and environment-friendly manner.

Indian Oil Corporation has four divisions:

Marketing Division with Headquarters at Bombay;

Refineries and Pipelines Division with Headquarters at New Delhi;

Assam Oil Division with Headquarters at Digboi; and

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Research and Development Centre at Faridabad.

The Assam Oil Division was established on 14th October, 1981 on taking over the

refining and marketing operations of Assam Oil Company Limited.

The Company wholly owns a subsidiary Company viz. Indian Oil Blending Limited,

which is engaged in the manufacture of lubricants and greases. The products of

the subsidiary Company are also marketed by the Company. Indian Oil and its

subsidiary (CPCL) account for over 48% petroleum products market share, 34.8%

national refining capacity and 71% downstream sector pipelines capacity in India.

It has a portfolio of powerful and a much-loved energy brand that includes Indane

LPGas, SERVO lubricants, XtraPremium petrol, XtraMile diesel, PROPEL,

petrochemicals, etc. Validating the trust of 56.8 million households, Indane has

earned the coveted status of 'Superbrand' in the year 2009 and now has a

customer base of 61.8 million. Indian Oil has a keen customer focus and a

formidable network of customer touch-points dotting the landscape across urban

and rural India. It has 20,421 petrol and diesel stations, including 3517 Kisan Seva

Kendras (KSKs) in the rural markets. With a countrywide network of 36,900 sales

points, backed for supplies by 140 bulk storage terminals and depots, 3,960

SKO/LDO dealers (60% of the industry), 96 aviation fuel stations and 89 LPGas

bottling plants, IndianOil services every nook and corner of the country. Indane is

present in almost 2764 markets through a network of 5456 distributors (51.8% of

the industry). About 7780 bulk consumer pumps are also in operation for the

convenience of large consumers, ensuring products and inventory at their

doorstep. Indian Oil's ISO-9002 certified Aviation Service commands an enviable

63% market share in aviation fuel business, successfully servicing the demands of

domestic and international flag carriers, private airlines and the Indian Defense 6

Services. The Corporation also enjoys a 65% share of the bulk consumer,

industrial, agricultural and marine sectors.

With a steady aim of maintaining its position as a market leader and providing the

best quality products and services, Indian Oil is currently investing Rs. 47,000

crore in a host of projects for augmentation of refining and pipelines capacities,

expansion of marketing infrastructure and product quality up gradation.

Objectives

The objectives of the Company as approved (June, 1984) by Government are as

follows:

To serve the national interests in the oil and related sectors in accordance

and consistent with Government policies.

To ensure and maintain continuous and smooth supplies of petroleum

products by way of crude refining, transportation and marketing activities

and to provide appropriate assistance to the consumer to conserve and

use petroleum products most efficiently.

To earn a reasonable rate of return on investment.

To work towards the achievement of self-sufficiency in the field of oil

refining, by setting up adequate domestic capacity and to build up

expertise for pipe laying for crude/petroleum products.

To create a strong research and development base in the field of oil refining

and stimulate the development of new petroleum products formulations

with a view to eliminate their imports, if any .

Products Services I.O.C Refineries:7

Auto LPG

Aviation Turbine

Fuel (ATF

Bitumen

High Speed Fuel

Industrial Fuels

Liquefied

Petroleum Gas

Lubricants and

Greases

Marine Fuels

MS/Gasoline

Petrochemicals

Refining

Pipelines

Marketing

Training

Research &

Development

Digboi Refinery,

Guwahati Refinery ,

Barauni Refinery

Gujarat Refinery

Haldia Refinery

Mathura Refinery

Panipat Refinery

Bongaigon

Refinery

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MATHURA REFINERY

The Mathura Refinery, owned by I.O.C.L is situated in Mathura, Uttar Pradesh. It is

the sixth refinery of Indian Oil was commissioned in 1982 with a capacity of 8.0

MMTPA to meet the demand of petroleum products in north western region of

the country, which includes National Capital Region. Refinery is located along the

Delhi-Agra National Highway about 154 KM away from Delhi. The refinery

processes low sulfur crude from Bombay High, imported low sulfur crude from

Nigeria, and high sulfur crude from the Middle East.

The refinery, which cost Rs.253.92 crores to build, was commissioned in January;

1982.Construction began on the refinery in October 1972. The foundation stone

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BLOCK FLOW DIAGRAMLPG

C5-85

HY REF GASOLINE

85-120 ISMLT REF

H2

Hy. Nap PXPTA CUT

SKO/ATF

LGO/HGO

RCO

LVGO LT NAPLPG

HVGO LPGATF

HNLCO+HN

VR CLOHY. N HCU BOTTOMS

ACID GASSULPHUR

VBGO

BITUMEN

VBTAR

CDU

VDU FCCU

CRUMSQ

VBU

HCUDHDS

DHDT

HGU-1/2

PXPTA-SPLT

MRX

MRX

LPG

Propylene

SKO

ATF

HSD

FO

HPS

BITUMEN

'S'

PRU

PRIME G

BBUARU / SRU

CrudeMS

NAPHTHA

Px-PTA NAP

was laid by Indira Gandhi, the former prime minister of India. The FCCU and Sulfur

Recovery Units were commissioned in January, 1983. The refining capacity of this

refinery was expanded to 7.5 MMTPA in 1989 by debottlenecking and revamping.

The present refining capacity of this refinery is 8.00 MMTPA.

The major secondary processing units provided were Fluidised Catalytic Cracking

Unit (FCCU), Vis-breaker Unit (VBU) and Bitumen Blowing Unit (BBU). The original

technology for these units was sourced from erstwhile USSR, UOP etc. Soaker

drum technology of EIL was implemented in VBU in the year 1993. For production

of unleaded Gasoline, Continuous Catalytic Reforming Unit (CCRU) was

commissioned in 1998 with technology from Axens, France. A Diesel Hydro

Desulfurisation Unit (DHDS) licensed from Axens, France was commissioned in

1999 for production of HSD with low Sulfur content of 0.25% wt. (max). With the

commissioning of once through Hydrocracker Unit (licensed from Chevron, USA)

in July 2000, capacity of Mathura Refinery was increased to 8.0 MMTPA.

Diesel Hydro-treating unit (DHDT) & MS Quality Up-gradation Unit (MSQU) were

installed with world class technology from Axens and UOP respectively in 2005 for

production of Euro-III grade HSD & MS w.e.f. 1st April 2005 as per Auto Fuel Policy

of Govt. of India. Project for FCC Gasoline Desulfurization (FCCGDS) and Selective

Hydrogenation Unit (SHU), the Prime-G technology of Axens, France was

commissioned in February 2010 and supply of Euro-IV grade MS and HSD started

on continuous basis from February 2010.

Mathura Refinery is having its own captive power plant, which was augmented

with the commissioning of three Gas Turbines (GT) and Heat Recovery Steam

Generator (HRSG) in phases from 1997 to 2005 using Natural Gas (NG) as fuel to

take care of environment.

For upgrading environmental standards, old Sulfur Recovery Units (SRU) was 10

replaced with new Sulfur Recovery Units with 99.9 % recovery in the year 1999.

Additional Sulfur Recovery Unit is under implementation as a hot standby.

Mathura Refinery had also set up four nos. of continuous Ambient Air Monitoring

Stations far beyond the working area before commissioning of the Refinery in

1982 as a mark of its concern towards the environment and archaeological sites.

Its close proximity to the magnificent wonder Taj Mahal adds extra responsibility

towards maintaining a cleaner environment.

Mathura Refinery has planted 1,67,000 trees in surrounding areas including

refinery & township and 1,15,000 trees in Agra region around Taj Mahal. The

Ecological Park which is spread across 4.45 acres is a thriving green oasis in the

heart of sprawling Refinery.

At Mathura Refinery, technology & ecology go hand in hand with continuous

endeavour for Product Quality up-gradation, Energy Conservation and

Environment Protection. Mathura Refinery is the first in Asia and third in the

world to receive the coveted ISO-14001 certification for Environment

Management System in 1996. It is also the first in the World to get OHSMS

certification for Safety Management in 1998.

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MAJOR UNITS IN MATHURA REFINERY

UNIT PRESENT CAPACITY(TMTPA)

FEED SPECIAL FEATURES

Fuels refinery & propylene Product pipelineo MJPL:3.7 MMTPAo Mathura tundia:1.2 MMTPAo MBPL: 1MMTPA Bit. Drum filling: by Mktg LPG bottling: by Mktg. Crude Recipient thru SMPL Captive Power Plant Mode of product despatch

– tank truck, tank wagon and pipeline

CDU 8000 Bombay high imported- high sulfur and low sulfur crude

FCCU 1350 Vacuum gas oil ex- IMP. LS & OHCU bottom

OHCU 1200 VGO ex.IMP. HSCCRU 466 NaphthaVBU 1000 Vacuum residue(VR)DHDS 1100 Straight run gas oil,

total cycle oilDHDT 1800 Straight run gas oil

and total cycle oilBiturox 750 Vacuum residuePENEX(MS Quality Up gradation)

440Naphtha, FCC Gasoline heart cut

PRIME G+ (FCC Gasoline desulfurisation)

525FCC Gasoline splitter bottom

PRODUCTS: Finished products from this refinery cover both fuel oil products as well as lube oil base stocks.

1.Liquid Petroleum Gas (LPG) 2.Fuel Oil Products:

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

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3. Lube Oil Products: Inter Neutral, Heavy Neutral & Bright Neutral HVI

4. Other Products:

Slack Wax Carbon Black Feed Stock Bitumen Sulfur

REFINERY PROCESS

The refining process depends on the chemical processes of distillation (separating liquids by their different boiling points) and catalysis (which speeds up reaction rates), and uses the principles of chemical equilibria. Chemical equilibrium exists when the reactants in a reaction are producing products, but those products are being recombined again into reactants. By altering the reaction conditions the amount of either products or reactants can be increased.Refining is carried out in three main steps.

Step 1 - SeparationThe oil is separated into its constituents by distillation, and some of these components (such as the refinery gas) are further separated with chemical reactions and by using solvents which dissolve one component of a mixture significantly better than another.

Step 2 - ConversionThe various hydrocarbons produced are then chemically altered to make them more suitable for their intended purpose. For example, naphthas are "reformed" from paraffins and naphthenes into aromatics. These reactions often use catalysis, and so sulfur is removed from the hydrocarbons before they are reacted, as it would 'poison' the catalysts used. The chemical equilibria are also manipulated to ensure a maximum yield of the desired product.

Step3 - PurificationThe hydrogen sulfide gas which was extracted from the refinery gas in Step 1 is converted to sulfur, which is sold in liquid form to fertiliser manufacturers.

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PROCESS

UNIT

DESCRIPTION

ATMOSPHERIC AND VACUUM DISTILLATION UNIT

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THE UNIT CONSISTS OF FOUR SECTIONS:

Section 1: Crude Oil Desalting

Section 2: Prefractionator column and Stabilisation of Naphtha.

Section 3: Atmospheric Distillation of Crude oil.

Section 4: Vacuum Distillation of Reduced Crude oil.

1.1. STREAM DAYS: 345 days per year.

1.2. TYPES OF CRUDE:

Low Sulfur Indian : Bombay high.

Nigerian: Girasol, Escravos, Farcados, Bonny light

High Sulfur Imported: Arab Mix, Kuwait, Dubai, Ratawi, Basra etc.

1.3. PRODUCTS OF AVU

The unit is to produce the following products designated by T.B.P. cuts also:-

Product Stream Use / Using secondary units

LPG Sent to MEROX unit for treatment

C5 - 120 °C cut Naphtha Component

C5 - 118 °C cut CCRU / NSU feed

120 - 135 °C cut (BH) Heavy Naphtha for blending with Diesel

118 - 142 °C cut (AM) Can be used as Naphtha component

135 - 255 °C cut (BH) Used as Superior kerosene

142 - 255 °C cut (AM) Sent as ATF to MEROX for treatment

255 - 296 °C cut (BH) Used as Superior kerosene

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255 - 300 °C cut (AM) Used as Cutter stock / HSD component

296 - 325 °C cut (BH)

HSD component (Light Gas Oil)300 - 330 °C cut (AM)

325 - 380 °C cut (LS) HSD component (Heavy Gas oil)

330 - 386 °C cut (AM)

HVGO component

(Heavy Atmospheric Gas Oil)

Light Vacuum Gas Oil HSD component

(<380 °C cut )

380 - 425 °C cutLight Diesel Oil

(also HVGO component)

425 - 530 °C cutHeavy Vacuum Gas Oil

Used as OHCU / FCCU feed

Vacuum Slop Blended with SR for VDU feed

Atmospheric Residue Used as IFO component in LS run

RCO

Vacuum Residue Feed for BBU in AM run

SR Feed/Hot feed for VBU in all runs

IFO component in LS run

Hydrocarbon Gas Used as Refinery Fuel gas

1 .5. PROCESS DESCRIPTION AND PRODUCT ROUTING:

1.5.1. ATMOSPHERIC DISTILLATION UNIT

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The ADU (Atmospheric Distillation Unit) separates most of the lighter end

products such as gas, gasoline, naphtha, kerosene, and gas oil from the crude oil.

The bottoms of the ADU are then sent to the VDU (Vacuum Distillation Unit).

Crude oil is preheated by the bottoms feed exchanger, further preheated and

partially vaporized in the feed furnace and then passed into the atmospheric

tower where it is separated into off gas, gasoline, naphtha, kerosene, gas oil and

bottoms.

Atmospheric and Vacuum unit (AVU) of Mathura Refinery is designed to process

100% Bombay High Crude and 100% Arab Mix crude (consisting of Light and

Heavy crude in 50:50 proportion by weight) in blocked out operation @ 11.0

MMTPA. Crude is received from the tank and is pumped through a series of heat

exchangers(1st stage preheat) before sending it to desalters.In desalters, salts

bottom sediments and water are removed from crude by injecting water and

separating out brine with the help of electrodes. This desalted crude is then

passed through another chain of exchangers(2nd stage preheat).After that crude

is sent to prefractionator column where IBP- 100o C, IBP – 110oC cut naphtha

product BH and AM operation respectively, is recovered from crude oil in the

prefractionator column as overhead product whereas topped crude from bottom

is sent another chain of exchangers(3rd stage preheat).The topped crude is

heated further in furnaces. This heated crude is sent to atmospheric distillation

column where fractionation of crude is sent into different products takes place.

Column profile is maintained by regulating CRs. Different parameters are

maintained to maintain product quality.

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1.5.1. VACUUM DISTILLATION UNIT:

Bottom residue of 11C-1(Atmospheric Distillation Column)is again processed in

vacuum column to increase distillate yield(and profitability).

RCO from 11C-1 is heated further in vacuum furnace before processing it in 12C-

1(Vacuum Distillation Column). In vacuum column, pressure is maintained at

around 60mmHg at column top pressure using ejectors. Fractionation of RCO into

different products under reduced pressure takes place. Different parameters are

maintained to adjust and control the product quality.

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The finished products are then sent to storage tanks before extracting heat in

heat exchangers, which can be used for crude preheating (ENCON).

1.6. PROCESS FLOW DESCRIPTION

1.6.1. FEED SUPPLY

Crude oil is stored in eight storage tanks (eight tanks each having a nominal

capacity of 50,000 m3 whereas remaining other 2 tanks are of 65,000 m3 nominal

capacity). Booster pumps located in the off-sites are used to deliver crude to the

unit feed pumps. Filters are installed on the suction manifold of crude pumps to

trap foreign matter. For processing slop, pumps are located in the off-site area,

which regulate the quantity of slop into the crude header after filters. Provision to

inject proportionate quantity of demulsifier into the unit crude pumps suction

header with the help of dosing pump is available.

1.6.2. SYSTEM DESCRIPTION:

Crude Oil is heated up to 136 -141 ºC in the first train of heat exchangers

operating in two parallel sections up to the desalter which is connected in series.

Desalting temperature as required can be maintained manually by operating the

bypass valve of heat exchangers.

A two-stage desalter has been designed for 99% salt removal. It is designed to use

stripped sour water for desalting which is being taken ex stripped sour water

unit. Provision to use DM water/ services water is also provided. The electric

field in the desalter breaks the emulsion and the outlet brine from the 1st stage

desalter is sent to ETP on level control.

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1.7. FURNACE OPERATION:  

1.CDU Fired Heater 2.VDU Fired Heater

1.7.1. CDU Fired Heater:

The convection section has 8 rows of tubes with 8 nos. tubes in each. The two

rows of shock tubes, i.e. the two rows just above the radiant section are plain

tubes without studs. The rest six rows are of extended surface type having

cylindrical studs. All the convection bank tubes are of 152 mmx8mm dimension

and 5Cr 1/2 Mo material of construction. Of these 64 tubes in the convection

section, 4 no’s studded tubes are for the service of superheating MP steam for

strippers; and the rest 60 nos. tubes are for crude oil service. Crude oil to be

heated enters the convection section in four passes. From outlets of the

convection bank, it passes through crossovers provided inside the furnace into

bottom coils of the radiant section. Steam flow is of single pass to superheating

coils.

1.7.2. VDU Fire Heater:

Like any conventional process heater, these heaters are also having two distinct

heating sections: (I) a radiant section, and (ii) convection section.

The convection section has 13 rows of tubes with 8 nos. tubes in each. The top

three rows are for the service of superheating LP steam for vacuum column and

the rest 10 rows are for RCO service. The three rows of shock tubes, i.e. the three

rows just above the radiant section are plain tubes without studs. The next seven

rows are of extended surface type having cylindrical studs. Provision exists to vent

out MP steam ex- super heating coils of furnaces to atmosphere through silence.

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The floor of furnace is elevated above grade and the hot air duct (supplying

combustion air to burners) runs across the length of the furnace below the

furnace floor. The skin temperature of tubes is limited to 542 0C.

The furnaces are of balanced draft type with forced draft (FD) fans to supply

combustion air and induced draft (ID) fan to take suction of the flue gases through

air-preheating system and discharge the same to stack.

 

1.8. CRUDE DIS TILLATION UNIT:  

The column is provided with 56 trays of which 8 are baffle trays in the stripping

section. Heated and partly vaporized crude feed coming from fired heater enters

the flash zone of the column at tray no. 46 at 355 ºC/365 ºC. Hydrocarbon

vapors flash in this zone and get liberated. Non-flashed liquid moves down which

is largely bottom product, called RCO.

MP steam having some degree of superheat is introduced in the column below

tray no. 46 at approximately3.5 kg/cm2 (g) and 290 ºC for stripping of RCO. Steam

stripping helps to remove lighter constituents from the bottom product (RCO).

Reduced crude oil product is collected at the bottom of the column and the

overhead vapors are totally condensed in Overhead air Condenser and train

condenser. This condensed overhead product is separated as hydrocarbon and

water in the reflux drum. Water is drawn out under inter-phase level control and

sent to sour water drums.

 

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1 .9. VACUUM DISTILLATION UNIT:

Hot RCO from the atmospheric column bottom at 355 ºC is mixed with slop

recycle from Vacuum Column, heated and partially vaporized in 8-pass vacuum

furnace and introduced to the flash zone of the vacuum column. The flash zone

pressure is maintained at 115-120 mm of Hg. Steam (MP) is injected into

individual passes and regulated manually. Three injection points have been

provided on each pass. This is to maintain required velocities in the heater, which

is Fuel Gas, Fuel Oil or combination fuel fired. Each cell is provided with 10

burners fired vertically upshot from furnace floor along the centerline of the cell.

The vaporized portions entering the flash zone of the column along with stripped

light ends from the bottoms rise up in the vacuum column and is fractionated into

four side stream products in 5 packed sections. The hydrocarbon vapors are

condensed in the Vac Slop, HVGO, LDO and LVGO sections by circulating refluxes

to yield the side draw products. Vacuum is maintained by a two-stage ejector

system with surface condensers. The condensed portion from the condensers are

routed to the hot well from where the non-condensable are sent to the vacuum

furnace low-pressure burners or vented to the atmosphere.  

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FLUID CAT ALYTIC CRAKING UNIT (FCCU)

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In this process Heavy Gas Oil cut (Raw Oil) from Vacuum Distillation Section of

AVU is catalytically cracked to obtain more valuable light and middle distillates.

The present processing capacity of the unit is about 1.48 MMT/Yr. It consists of

the following sections:

Catalytic section,

Fractionation section and

Gas concentration section.

The unit is designed to process two different types of feed i.e. Arab Mix HVGO,

Bombay High HVGO.

2.1. CRACKING SECTION

Cracking process uses high temperature to convert heavy hydrocarbons into more

valuable lighter products. This can be accomplished either thermally or

catalytically. The catalytic process has completely superseded thermal cracking as

the catalyst helps the reactions to take place at lower pressures and 24

temperatures. At the same time, the process produces a higher octane gasoline,

more stable cracked gas and less of the undesirable heavy residual product. The

process is also flexible in that it can be tailored to fuel oil, gas oil operations

producing high yields of cycle oils or to LPG operations producing yields of C3-C4

fraction.

The fluid Catalytic Cracking process employs a catalyst in the form of minute

spherical particles, which behaves like a fluid when aerated with a vapour. This

fluidized catalyst is continuously circulated from the reaction zone to the

regeneration zone. The catalyst also transfers heat carried with it from one zone

to the other viz. in the vessels reactor and regenerator. The reaction and

regeneration zones form the heart of the catalytic cracking unit.

Catalyst section consists of the reactor of the reactor and regenerator, which

together with the standpipes and riser form the catalyst circulation circuit. The

catalyst circulates up the riser to the reactor, down through the stripper to the,

regenerator across to the regenerator standpipe and back to the riser. The

vertical riser is in fact the reactor in which the entire reaction takes place. The

reactor is a container for cyclone separators at the end of vertical riser.

Coke is deposited on the catalyst in the reaction zone. The spent catalyst flows

downwards into the stripping section of the reactor. After steam stripping to

remove oil vapours from it the catalyst flows from the reactor standpipe to the

regenerator through a slide valve in the regenerator, the coke is burnt off, oxygen

for burning being supplied by an air blower. Air from the blower is uniformly

given to the regenerator through a pipe grid at its bottom. The heat of

combustion raises the catalyst temperature to more than 600 (C. Most of the heat

in the catalyst is given to the feed in the reactor riser to raise it to the reaction 25

temperature and to provide the heat of reaction. The regenerated catalyst from

the standpipe flows into the riser through a slide valve to complete the catalyst

circulation cycle. Catalyst particles in the flue gas leaving the regenerator are

separated at the top of regenerator by three sets of two-stage cyclones. The flue

gas contains both CO and CO2 as carbon is burnt off partly to CO and partly to

CO2 in the regenerator. The sensible and chemical heat in flue gas is utilized to

generate steam in CO Boiler. The flue gas is passed through' the orifice chamber &

regenerator. Pressure is controlled by double disc slide valve. Orifice chamber

holds backpressure downstream of double-disc slide valve. By reducing the pr.

drop across slide valve, operating life of slide valve is greatly extended by avoiding

sudden accelerations of catalyst, bearing flue gas stream. The unit is designed for

use of high ZEOLITE catalyst (Fresh catalyst), which is microspheriadical in shape.

2.2. CATALYTIC SECTION 

The fluid Catalytic Cracking process employs a catalyst in the form of minute

spherical particles, which behaves like a fluid when aerated with a vapour. This

fluidized catalyst is continuously circulated from the reaction zone to the

regeneration zone.

Feed to the FCC Unit is gas oils obtained by vacuum distillation of long residue

from the crude distillation unit. In our unit the vacuum cut boiling in the range

380-530°C is used as feedstock to the FCC Unit.

. Catalyst section consists of the reactor of the reactor and regenerator, which

together with the standpipes and riser form the catalyst circulation circuit. The

catalyst circulates up the riser to the reactor, down through the stripper to the,

regenerator across to the regenerator standpipe and back to the riser. The

26

vertical riser is in fact the reactor in which the entire reaction takes place. The

reactor is a container for cyclone separators at the end of vertical riser

Fresh feed after heating up to 350 °C in a feed pre-heater along with recycle

streams enters the base of the riser. In the riser the combined feed is vaporized

and raised to the reactor temperature by the hot catalyst flowing upward through

the riser. Cracking reactions start immediately as the gas oil comes into contact

with the hot catalyst. Entrained catalyst and hydrocarbon vapors, after cracking,

flow upwards and pass through two cyclone separators attached to top of the

reactor. These cyclones remove most of the entrained catalyst. Oil vapors

containing a small quantity of catalyst pass overhead through the vapour line into

the fractionator.

Coke is deposited on the catalyst in the reaction zone. The spent catalyst flows

downwards into the stripping section of the reactor. After steam stripping to

remove oil vapours from it the catalyst flows from the reactor standpipe to the

regenerator through a slide valve in the regenerator, the coke is burnt off, oxygen

for burning being supplied by an air blower. The heat of combustion raises the

catalyst temperature to more than 600 °C. Most of the heat in the catalyst is given

to the feed in the reactor riser to raise it to the reaction temperature and to

provide the heat of reaction. The regenerated catalyst from the standpipe flows

into the riser through a slide valve to complete the catalyst circulation cycle.

Catalyst particles in the flue gas leaving the regenerator are separated at the top

of regenerator by three sets of two-stage cyclones.

2.3. Type of catalyst

The unit requires two types of catalyst, viz.

27

(1) Fresh catalyst

(2) Equilibrium catalyst

2.4. FRACTIONATION SECTION 

In this section, the vapors coming out of the reactor top at very high temperature

are fractionated into wet gas and un-stabilized gasoline overhead products, heavy

naphtha, and light cycle oil as side products. Heavy cycle oil drawn from the

column is totally recycled along with the feed after providing for the recycle

stream to the column.

28

The column bottom slurry containing a small quantity of catalyst is sent to a slurry

settler. From the settler bottom, the thickened slurry is recycled back to the riser

for recovering catalyst is sent to a settler and from the settler bottom, the

thickened slurry is recycled back to the riser for recovering catalyst and further

cracking. From the top of slurry settler, clarified oil product is taken out after

cooling which goes for blending in Fuel Oil.

Heavy naphtha and light cycle oil streams after steam stripping are used as gas oil

blending components. The un-stabilized gasoline and wet gas are sent to Gas

Concentration Unit for further processing. Both heavy naphtha and light cycle oil

being blending components for HSD can be blended in the unit and sent to

product blending station, as a single stream. In addition, light cycle oil, if required

for blending in FO, fertilizer feed, etc. can be diverted to the extent required for

product blending in a separate line.  

 

2.5. GAS CONCENTRATION SECTION

29

The wet gas from the fractionator overhead receiver is compressed in a two-stage

centrifugal compressor and sent to a high-pressure (HP) receiver after cooling.

Gas from the HP receiver is sent to the Primary Absorber for recovery of C3's and

heavier components by absorption with stabilized gasoline taken from the

debutanizer column bottom and un-stabilized gasoline from main column

overhead receiver. Rich gasoline from Absorber bottom is recycled back to the HP

receiver. The stripped gasoline is further stabilized in the debutanizer removing

C3 and C4 components from it as cracked LPG and bottom product as stabilized

FCC gasoline. Both LPG and gasoline are Merox treated before routing to storage.

2.6. CO BOILER

The flue gas leaving the regenerator via orifice chamber contains 8-13% carbon

monoxide, the rest being inert like nitrogen, steam, carbon dioxide, etc. In the CO

Boiler, flue gas is burnt with air converting, carbon monoxide to carbon dioxide,

thus releasing the heat of combustion of CO in the boiler. This heat as well as the

sensible heat in flue gas available at a high temperature is utilized for raising

medium pressure steam.

30

VIS-BREAKING UNIT

3.1. Introduction:

The Visbreaker Unit is designed for processing a mixture of Atmospheric and

Vacuum Residue from 1:1 mixture of Light Arabian and North Rumaila Crudes. It

reduces the viscosity and pour point of heavy petroleum fractions so that product

can be sold as fuel oil. The nominal capacity of the plant is 0.8 MMTPA of mixed

Feed. However, the design capacity has been kept as 1.0 MMTPA to take care of

Fluctuations in the Bitumen production. The unit produces Gas, Naphtha, and

Heavy Naphtha, VB Gas Oil, Visbreaker fuel oil (a mixture of VB gas oil and VB tar).

In actual practice design feed was not available. So long residue and short Residue

of Nineteen type of imported crudes e.g. Arab Mix, Arab Light, Arab Heavy,

Rostam, Solman, Light Iranian, Algerian, Heavy Iranian, Lagos medio,

Basrah,Ummshaif, Iran Mix, Iran blend, AbooAlbakoosh, Dubai, Kuwait, Haut.

Oman, Nigerian and two types of Indegeneous crude Bombay High and Ratnabad

had to be processed in the unit from the very commissioning. Long And short

residue proportion also varied to a large extent depending on tank Ullage position

etc. A provision is also made by a small modification to route V B Gas oil to HSD /

LDO pool over and above its original routing provision to V B tar.

At present all the Short residue and vac slop produced in BH run in AVU is routed

to VBU for HPS production. Short residue and vac slop in Nigerian crude run along

with BH cold feed is routed to VBU for HPS production. Nigerian SR and vac slop is

also routed to VBU (limited to 20% of blend) for FO production with HS as cold

feed .Balance Nigerian SR is routed along with RCO for IFO top up. Short residue

produced in HS run is routed to Bitumen unit and balance SR along with vac slop

31

is routed to VBU. Following table summaries shows the mode of operation in VBU

and their feed streams.

Feed Stream Design Capacity,MMTPAAtmospheric Residue 400Vacuum Residue 600

 

3.2. THEORY OF VISBREAKING

The Visbreaker is essentially a Thermal cracking unit designed to operate at mild

conditions and to retain all the cracked light oils in the bottom product. This

results in reduction of viscosity of bottom product. In the Thermal cracking

reaction, heavy oil is kept at a high temperature for a certain amount of time and

this causes the larger molecules to break up. The resulting product has a random

distribution of molecular sizes resulting in products ranging from light gas to

heavy gas oil. These products are characterized as "Cracked" products and contain

a certain percentage of olefinic compounds. Whenever a molecule breaks one of

the resulting molecules is an olefin.

CH3-CH2-CH2-CH2-CH2-CH2-CH3CH3-CH2-CH=CH2 + CH3-CH2-CH3

Cracked products are unstable and form gum. The cracked naphtha has higher

octane number than straight run gasoline. During the cracking operation, some

coke is usually formed. Coke is the end product of polymerizations reaction in

which two large olefin molecules combine to form an even larger olefinic

molecule.

C10H21-CH=CH2 + CH2=CH-C10H21C10H21-CH=CH-CH2-CH2-C10H21

32

When above reaction gets repeated several times, the end product is coke. This is

usually found inside the walls of furnace tubes and other spots where oil may

remain at high temperature and soak heat for some time. Severity of over-all

reaction is determined by residence time and temperature of cracking. Residence

time in the unit can be varied by varying charge rate and steam injection rate of

DMW injection into furnace coils. Temperature can be varied as per requirement.

The cracking reaction usually does not become evident until transfer temperature

crosses 400 °C. When transfer temperature reaches 460 °C; sufficient cracking of

oil takes place. Gas and Naphtha are produced, the viscosity of product is lowered

and simultaneously coke deposits in the furnace tubes & soaker.

Increased severity results in shorter run lengths and more unstable fuel oil with

sediments in it.

3.3. System Description

The feed passes through the furnace, where cracking reaction take place and the

conversion in the coil is about 50 to 60%. The effluent from the furnace is routed

to the soaker drum for completion of visbreaking reaction. The soaker effluent is

quenched before entering fractionator by injecting column bottom product (VB

Tar). The quenched effluent ten enters the VB fractionator. In the bottom of the

fractionator, steam is introduced to remove lighter fractions. VB Tar is removed as

the bottom product. The overhead fraction is unstable naphtha and gas. The

naphtha is stabilized and sent to merox unit for sweetening.

3.4. Visbreaker Furnaces

Visbreaker unit is provided with two identical natural draft furnaces. They are up-

right steel structures with outer steel casing lined with refractory material. Each

of the furnaces is independent with radiation section at the bottom. Convection

33

section is at the top of the radiation section and above convection section is the

stack. The convection further heat from the flue gases leaving the radiation

section. It is having numbering 6, 10 and 14 respectively. The radiation section

houses the radiation tubes numbering 30 in each pass. In this section heat is

transferred primarily by radiation by flame and hot combustible gases.

VBU furnace tubes skin temperature is measured by skin thermocouples provided

on tubes in radiation zone. Furnaces are provided with thermocouple in radiation

and convection zones for measuring tube skin temperatures, box temperatures

before and after steam coils, and flue gas to stack temperatures. Thermocouples

are also provided inside furnace tubes for measuring liquid temperatures at

different points. The maximum allowed tubes skin and box temperature in the

heaters is 650 oC and 750 oC respectively.

There is a provision for on-stream analyzer of SO2 emission from both the stacks.

The purpose of the water, injection is to maintain suitable velocity in the furnace

tubes and to minimize coking.

Effluent from these passes is gathered and sent to soaker drum. It enters from the

bottom and leaves from the top. Thermal cracking of the feed, which is initiated in

the furnace, gets completed in soaker drum. Residence time of the order of half

an hour is given in soaker.

To arrest cracking reactions, materials from each pass of the two furnaces are

individually quenched by the injection of cooled VB tar at 2230C. To increase

turbulence and to prevent coke deposit in the coils, there is provision to inject

steam in each pass. The purpose of the water injection is to maintain suitable

velocity in the furnace tubes and to minimize coking.

34

3.5. V.B. FRACTIONATOR

Soaker effluent after quenching enters fractionator. Temperature in the flash

zone is around 420 oC. From the column, gas & gasoline are separated as

overhead, gas oil as side stream and the VB tar as bottoms. The fractionator has

26 valve trays and one blind tray. Feed enters flash zone below the 26th Valve

tray. The overhead vapours from the column are condensed and cooled in heat

exchangers.

The liquid vapour mixture is separated in the reflux drum. Gasoline from flash

fractionator is picked up by reflux pumps and partly pumped to column top as

reflux. The remaining gasoline is routed to stabilizer under reflux drum level

controller, which is cascaded with flow controller. The sour water is drained from

the drum boot under interface level controller and routed to sour water stripper.

Main reflux drum and its water boot are having level glasses. Uncondensed gas

from Gas oil stripper goes to FCC/AVU furnaces / Flare. Column top pressure

around 4.5kg/cm2 (g). Column overhead line is provided with working and

controlled safety valves.

The heavy naphtha at a temperature of about 170 oC is withdrawn from tray no.

10 under level controller. It is stripped in the stripper to maintain its flash point.

The heavy naphtha is routed to HSD. Gas oil at a temperature of about 260 oC is

withdrawn from the blind accumulator tray under tray level controller. It is steam

stripped in the stripper ot maintain its flash point. Vapor from stripper top returns

back to column just above the blind accumulator tray. A part of gas oil from air

cooler is used for washing VB tar filters Blind accumulator tray and strippers are

provided with level glasses.

To remove extra heat and to maintain desired temperature profile in column, a

portion of gas oil from blind tray is taken and pumped in two streams. One stream

35

is used as heating media in steam generator where it is cooled from 260 oC to 214 oC. The second stream supplies re-boiling heat to stabilizer re-boiler and gets

cooled from 260 oC to 215 oC. To protect column bottom against coking, cooled VB

tar condensed in air cooler and go to reflux drum. Safety valve is provided to

release gas and protect the vessel from over pressure.

Tar is cooled from 351 oC to 225 oC in feed exchangers and further cooling to 214 oC is done. Pumps are having two filters in the suction line with gas oil flushing

facilities. Only one filter is kept in service while the other remains as spare. Cooled

VB tar is partly used as quench to

1. Fractionator column bottom. Bottom temperature is maintained at

355 oC.

2. Transfer lines of the two furnaces. Temperature of the combined

effluent entering main fractionator is maintained at 427 oC.

3. Gas oil stripper bottom should be protected against coking. Bottom

temperature is maintained at 351 oC.

VB tar is then cooled in boiler feed water exchanger from 232 oC to 210 oC. It is

further cooled to 90 oC and sent to storage with gas oil.

3.6. Stabilizer

Un-stabilized gasoline from reflux drum is picked up by reflux pump and then it is

pumped to stabilizer through stabilized gasoline exchanger. In heat exchanger,

feed is heated from 43 oC to 120 oC while stabilized gasoline is cooled from 180 oC

to 120 oC. The column has 30 trays and the feed enters on the 19th.The overhead

product at 60 oC goes to water condensers. The condensed liquid is collected in

the reflux drum. Uncondensed gas from the drum goes to FCC/unit fuel gas

header. Pressure at the drum is maintained at 8.4kg/cm2 (g).

36

CONTINOUS CATALYTIC REFORMING UNIT(CCRU)

3.1.Introduction:

The Continuous Catalyst Regeneration type of Reforming Unit (CCRU) , process is

based on advanced technology from IFP (France), which allows continuous

regeneration of catalyst unlike in earlier semi-regenerative type of CRU’ s

operating with limited cycle length between two consecutive regenerations.

Installed at the cost of about Rs. 360 crores (inclusive of power plant), the CCRU is

serving us to produce high octane reformate (up to 98 RON) from straight run

(C5–145 oC cut) naphtha through catalytic reforming process. Reformate so

produced is a component used to upgrade (by blending with) lower Octane

streams up to the desired level of Octane number for production of Euro-III and

Euro-IV grade MS.

A catalytic reforming process converts a feed stream containing paraffins, Olefins

and naphthene to aromatics. The product stream of the reformer is generally

referred to as reformate. The purpose of the CR unit is to produce a high octane

no. reformate as a blending stock for the production of motor spirit. The octane

no. of the gasoline coming from the AVU is around 66, whereas the required value

of the octane no. is 87, 88 and 93.

3.6.1. Design Capacity The normal capacity of the CCR Unit is 466,000 MT based on a stream

factor of 8000 hours/year with 120% over design factor.

The normal operating flexibility of the CCR is 60% of Design.

3.6.2. Feed Specification Naphtha from Bombay high crude oil 80 –1400C TBP cut (Feed I)

37

95/5 blend of naphtha from Arab mix (80-1450C TBP cut) and vis-

broken Naphtha (Feed II)

Composition: - wt. %

Feed Feed I Feed II

PARAFFIN

iC5 0.20 0.00

nC5 0.3 0.04

iC6 3.80 4.29

nC6 4.98 5.61

C7 20.76 9.88

C9 5.88 5.55

C10+ 0.89 0.27

NAPHTHENE

N5 0.26 0.24

N6 7.97 8.91

N7 13.33 13.07

N8 3.81 7.78

N9 2.39 2.55

N10 0.00 0.00

AROMATIC

A6 6.87 8.14

A7 7.85 12.38

A8 4.21 11.39

A9 0.32 0.07

A10 0.00 0.00

TOTAL 100.00 100.00

38

Catalytic Reforming is a major conversion process having applications in

Petroleum Refining and Petrochemicals Industries as it transforms low octane

(Straight Run) Naphtha into:

High Octane Motor Gasoline Blending Stock

Produce Aromatic Concentrates rich in benzene ,Toluene & Xylene(BTX)

By Products:

Hydrogen used in refinery for hydro-treating,hydro-cracking making it a

more economically viable process.Although use of Catalytic Reforming only

as a means to produce hydrogen is not economically viable.

LPG

3.2 Unit Subdivision

The whole CRU can be divided into three subunits as:

Naphtha Splitting Unit (NSU)

Naphtha Hydro-treater Unit (NHU)

Catalyst Reforming Unit – CRU &Continuous Catalyst Regeneration Unit-

CCRU

3.2.1 Naphtha Splitter Unit:

Naphtha splitting unit produces feed of required TBP range for the

reforming unit by splitting wide cut naphtha from CDU. The selected cut is

then Hydro treated before feeding to the Reforming Unit.

This unit has been designed to split SR naphtha (144 MT/hr for BH or 95

MT/hr for AM) to C5-80 oC and 80-115 oC cut. Due to the restriction on

Benzene content in the final product (motor spirit), the IBP of the heavier 39

cut is raised to approximately 105oC. The present operating cut range of

NSU for light naphtha product is C5-105oC and for heavy naphtha product is

105-160 oC. NSU can be operated with naphtha directly from AVU (hot

feed) or from OM&S (Cold feed) or using both the feeds simultaneously.

NSU splits C5-150 oC cut naphtha into C5-90 oC cut and 90-150 oC cut.

Heavier cut forms the feed for reformer. Cut point of 90 oC has been

chosen to get required octane number with moderate severity and also to

exclude the benzene precursors from the reformer feed.

a) FEED SELECTION:

For normal operation of the plant, the feed naphtha will be supplied by

AVU stabilizer section at a temperature of about 60 OC. This naphtha is pre-

heated by column bottom Heavy naphtha in feed-bottom exchanger to 95

°C The back pressure controller operates to maintain a set point of 4.4

Kg/cm2 (g) at the inlet of the column to avoid two-phase flow in the feed

line. The Heavy Naphtha from the Splitter column is routed to rundown or

as hot feed to NHTU.

In case of pre-planned AVU shutdown, stabilized naphtha (C5-150 oC) will

be stored in the existing naphtha tanks and processed in NSU as cold feed.

b) SPLITTER SECTION:

Naphtha splitter receives feed on its 19th tray. The hot feed from AVU/cold

feed, after getting preheated goes to the LP steam pre-heat exchanger, and

the MP steam pre-heat exchanger, before entering the splitter. In former,

the naphtha feed temperature is increased to 1350C from 95 0C by LP Steam

and in later the required feed temperature of 1450C is achieved by using

MP Steam. The feed naphtha after preheating enters the splitter through

the control valve. Splitter has a total of 40 trays.

40

Overhead vapours of splitter are totally condensed in the splitter air-cooler

and in the new overhead condenser before it is collected in splitter Reflux

drum. Part of the liquid collected in reflux drum is sent back as reflux to

splitter section by splitter reflux pumps and balance is sent back to AVU

after cooling it in light naphtha cooler.

Splitter bottom product is cooled in splitter bottom Air Cooler followed by

splitter bottom Heavy Naphtha trim cooler. Heavy Naphtha can directly

send to Hydrotreater feed coalesce.

c) REBOILING HEATER:

Splitter re-boiler supplies the heat necessary for splitter re-boiling. It is a six

pass vertical cylindrical heater with 6 burners having provision for

combination firing of both fuel gas and fuel oil. However they are designed

for 100 % of fuel gas or fuel oil firing.

Desired temperature at outlet is maintained by controlling the fuel firing.

The radiant section of the heater is provided with 12 bare tubes per pass.

The convection section has studded as well as bare tubes. The permissible

maximum tube skin temperature for the heater is 253 oC.

In the heat recovery system, FD fan supplies hot air for combustion through

APH and hot flue gases are discharged to stack using ID fan after

exchanging heat in APH.

d) CONDENSATE RECOVERY SECTION:

Feed naphtha preheating is achieved by LP and MP steam pre-heaters. The LP

steam condensate vessel floats with the LP steam header through a 1.5”

line from the top of the vessel. The level in LP condensate pot is maintained

at 50% by level control valve, which transfers the condensate to 41

condensate recovery drum by pressure head. MP Steam is under cascade

control splitter inlet temperature. The level in MP condensate vessel is

maintained at 50% by level control valve, which transfers the condensate to

condensate recovery drum by its pressure head. The total condensate

received in the condensate recovery vessel, is pumped to condensate

polishing unit. Small quantity of steam is safely vented to atmosphere. The

condensate recovery vessel is also provided with an overflow line routed to

drain to take care of level controller failure.

3.2.2. Naphtha Hydro – Treater Unit.

The purpose of Naphtha Hydrotreater is to eliminate the impurities (such

as sulfur, nitrogen, halogens, oxygen, water, olefins, di-olefins, arsenic

and metals, except for water, which is eliminated in the stripper) from the

feed that would otherwise affect the performance and lifetime of the

Reformer catalyst. This is achieved by the use of selective catalyst (nickel,

molybdenum) and optimum operating conditions. The unit is designed to

handle a wide range of feed naphtha from very low sulfur (10.9 PPM in

neat BH) to a maximum sulfur content of 1043 PPM so as to give treated

product of sulfur less than 0.5 PPM. Nitrogen is also reduced to less than

0.5 PPM and water content is reduced in the stripper to less than 4

PPM.The normal capacity of the unit is such that the capacity of the

reforming unit is 466000 MT/Year based on an On-Stream factor of 8000

hours/year (345 days operation) with 120% over design. Operating

flexibility is of 60%, same as that of the reforming unit.The hydrogenation

of di-olefins and conversion of mercaptans take place in a fixed bed axial

reactor, 14R2. The hydrogenation of olefins, hydro-desulfurization and

hydro-denitrification reactions take place in another fixed bed axial reactor,

42

14R1. A middle range temperature is required to promote the chemical

reactions, which improve the product quality. The hydrotreatment

catalysts shall be periodically regenerated to recover its activity. The liquid

product from the reaction section is then stripped to remove H2S, water

and light hydrocarbons.

3.2.3.CATALYTIC REFORMING UNIT – CRU &CONTINUOUS CATALYST REGENERATION UNIT- CCRU

a) REFORMING UNIT

Catalytic reforming is normally facilitated by a bi-functional catalyst that is

capable of rearranging and breaking long-chain hydrocarbons as well as removing

hydrogen from naphthenes to produce aromatics. The idea of a Catalytic

Reforming Unit is to have RON (Research Octane Number) as high as possible at

the same time keeping the Olefins, Benzene & Aromatics under the specified

limits. The different types of reformers are classified as a fixed-bed type, semi-

regenerative type, cyclic type and the continuous regenerative type. This

classification is based on the ability of the unit to operate without bringing down

the catalyst for Regeneration. During the regeneration process, the refinery will

suffer production loss. In the Continuous Catalytic Reforming unit, the reactors

are cleverly stacked, so that the catalyst can flow under gravity. From the bottom

of the reactor stack, the 'spent' catalyst is 'lifted' by nitrogen to the top of the

regenerator stack. In the regenerator, the above mentioned different steps, coke

burning, oxychlorination and drying are done in different sections, segregated via

a complex system of valves, purge-flows and screens. From the bottom of the

regenerator stack, catalyst is lifted by hydrogen to the top of the reactor stack, in

a special area called the reduction zone. In the reduction zone, the catalyst passes

a heat exchanger in which it is heated up against hot feed. Under hot conditions it 43

is brought in contact with hydrogen, which performs a reduction of the catalyst

surface, thereby restoring its activity. In such a continuous regeneration process,

a constant catalyst activity can be maintained without unit shut down for a typical

run length of 3 - 6 years.

Feed for the Reforming unit (94 m3/hr at 14 kg/cm2 and 110 oC) is received

directly from hydrotreater stripper after heat exchanger. The filters must be

provided for the protection of the welded plate exchanger. Feed is filtered to

remove any foreign particles. At the D/S of the feed filter, chloriding agent and

water injection are done. CCl4 solution of 1% in reformate is dosed by pump.

Dosing @ 1 ppm wt. CCl4 in feed is done when continuous regeneration unit is

down. Water injection (not on regular basis) is done to maintain Cl-OH

equilibrium on the catalyst when regenerator is out of service.

Feed mixed with recycle H2 stream gets preheated in PACKINOX exchanger from

91oC to 451oC by the effluent from 3rd Reactor which gets cooled down from

497oC to 98oC. Due to the endothermic nature of the reforming reactions, the

overall reforming is achieved in stages with inter stage heater provided to raise

the temperature. There are three Reactors (15R-1, R-2 & R-3) each provided with

reaction heater.

b) REACTORS

In the reactors, the feed contacts the reforming catalyst which is divided

approximately in the ratio 15:30:55. In the CCR process, the catalyst circulates

continuously in reactors, in the space between the external grid and the central

pipe from the top to the bottom, from one reactor bottom to the top of the next

one, from the last reactor to the regeneration unit for regeneration. From the

regeneration unit, the regenerated catalyst returns to the first reactor. Each

reactor is a vertical cylindrical vessel with spherical heads. It is equipped with one

44

inlet & one outlet nozzle for feed & effluent respectively. Catalyst enters the

reactor through 12 nos. of 3" pipes, flows through the space between external

grid and the central pipe from top to bottom and exits through 12 nos. of 2"pipes,

slow moving bed of bimetallic catalyst and exits through the outlet nozzle at the

bottom. The radial flow of feed is achieved by directing the flow through external

grid to catalyst bed & exit is made to central outlet collector pipe. Gas tight baffle

is provided on the outlet pipe to avoid short-circuiting of the feed to outlet pipe

at the entrance. Reactor effluent after passing through PACKINOX exchanger is

cooled in air cooler to 65 oC and then by trim cooler to 45oC before entering the

separator. The separated gas is compressed in the recycle gas compressor and a

part is recycled to the reactors. The remaining gas is routed to a re-contacting

section to improve hydrogen purity and recover liquid yield.

45

DHDT: DIESEL HYDROTREATING UNIT

3.7. DHDT UNIT DETAILS:

Process Licensor: IFP, France

LSTK Contractor: Daelim, S. Korea

PMC: Jacobs H& G Pvt.Ltd.

Capacity: 1.8 MMTA(Designed for 2 MMTPA)

Turndown: 50%

Process: IFP Licensed Hydro treating technology

Capacity Basis: 8000 HRS/YEAR

Cost: 6000 crores

Commissioning date: 02/05/2005

3.8. PURPOSE OF UNIT:

To reduce low sulfur (<30ppm) and high cetane number (55) HSD to cater

to the needs of bharat stage II, bharat stage III and bharat stage IV.

With recommendation of task force of government’s AUTO FUEL POLICY,

following emission’s norms will be followed.

3.9. SPECIFICATIONS OF BHARAT STAGE I AND IV:

SULFUR IN DIESEL CETANE NUMBER

BHARAT STAGE I 2500 ppm

BHARAT STAGE II 500 ppm

BHARAT STAGE III 350 ppm 51(min)

BHARAT STAGE IV 50 ppm

46

3.10. Cetane number:

A rating on a scale use to indicate the tendency of a fuel for diesel

enginesto cause knock, comparable to octane number for gasoline.

The rating is comparing the fuel’s performance in a standard engine with

that of a mixture of cetane 100 and alpha-amine-naphthalene (0). The

cetane of diesel is the percentage by volume of the cetane(say 55) in the

mixture of alpha-methy-naphtalene (say 45)then the cetane number of the

said diesel is 55.

3.11. CHEMICAL REACTIONS:

The main reactions taking place in the process are refining and hydrogenation

reactions, in addition some hydrocracking reactions takes place as well.

3.11.1. Refining reactions:

Refining reactions involve the removal of heteroatoms, namely sulfur, nitrogen

and oxygen. It also includes the saturation reactions of olefins and di-olefins.

Treating reactions:

Metal removal Olefin saturation Sulfur removal Nitrogen removal Oxygen removal Aromatic saturation(cetane number improvement)

Desulfurisation reactions:

The aliphatic sulfur compounds, namely mercaptants, sulphides and di-sulphides

react easily leading to the corresponding saturated or aromatic compounds.

Thiophenes sulfur is most difficult to react. The reaction is exothermic.

47

Mechanism:

Sulfur removed first, and then the olefin is saturated. Three mole of hydrogen

consumed per mole of sulfur. 560 kcal of heat liberated per Nm3 of H2 consumed.

Mercaptant

R-SH + H2 RH + H2S

Sulphides

R-S-R + 2H2 2RH + H2S

DENITROFICATION REACTIONS:

These reactions lead to ammonia formation and are exothermic in nature.

The hydro – denitrogenation reactions are slower than the hydro

desulfurisation reactions, and generally require more severe conditions

especially for components having nitrogen as a part of an aromatic ring

such as pyridine.

Mechanism:

First saturation of the rings to which nitrogen is attached and then carbon

nitrogen bond scission. Five mole of hydrogen consumed for per mole of nitrogen.

632 to 705 Kcal of heat liberated per Nm3 of hydrogen consumed.

Amine

CH3-CH2-CH2-CH2-CH2-NH2 +H2 CH3-CH2-CH2-CH2-CH3 + NH3

SULFUR RECOVERY UNIT (SRU)

6.1. INTRODUCTION

48

The unit consists of three identical units A, B and C. One of them is kept standby. The process design is in accordance with common practice to recover elemental sulfur known as the Clause process, which is further improved by Super Clause process. Each unit consists of a thermal stage, in which H2S is partially burnt with air, followed by two catalytic stages. A catalytic incinerator for incineration of all gases has been incorporated in order to prevent pollution of the atmosphere.

SRU (Sulfur recovery unit)

This unit is basically low pressure (slightly above then atm) unit having throughput of 60 tons/day.

The Sulfur Recovery Unit is designed to recover sulfur from the sour vapors originating from the following sources:

1) The Amine Regenerator Unit

2) The Sour Water Stripper Unit

49

Feed SpecificationsThe feedstock of the SRU is a mixture of the “Acid gas ex ARU” and the “Acid gas ex SWS”, 50% of the feed to the SRU is to be processed in the two of the three trains.The quantity and quality of H2S feed to the unit will vary depending on the shutdown of the various preceding units. The unit should be capable of converting 99% wt. of the H2S contained in the feed streams to sulfur in all the following cases:

Case 1: When all units are running with HCU on 70% IMP HVGO.

Component Acid gas ex-ARU Acid gas ex-SWS Total feed

H2

H2S

H/S*

CO2

NH3

H2O

2.2

4805.0

11.3

338.3

122.7

-

560.7

-

-

137.0

309.9

2.2

5365.7

11.3

338.3

137.0

432.6

Total kg/hr 5279.5 1007.6 6287.1

* H/C will be a mixture of C1, C2, C3, C4 having an average molecular wt. of 30.

Case 2: When HCU is down and DHDS is feed-2 operation

Component Acid gas ex-ARU Acid gas ex-SWS Total feed

H2

H2S

H/S*

0.3

1727.2

11.3

-

545.9

-

0.3

2273.1

11.3

50

CO2

NH3

H2O

338.3

48.1

-

218.3

364.8

338.3

218.3

412.9

Total kg/hr 2125.2 1129.0 6287.1

* H/C will be a mixture of C1, C2, C3, C4 having an average molecular wt. of 30.

Battery limit conditions

Component Gas ex-SWS Gas ex-ARU

Temperature, oC 90 40

Pressure, kg/cm2g 0.7 0.7

Design Criteria and Requirements

Capacity

The unit consists of three parallel SRU trains, each with a sulfur production capacity of 60 metric tons/day, a tail gas incinerator and a sulfur degassing system. Two SRU trains are normally in operation and one SRU train is in the hot stand-by mode.

Sulfur Recovery Rate

The unit is capable of a sulfur recovery efficiency of 99.0 wt.% based on the operation of the unit at a capacity and acid gas composition corresponding to one of the cases as defined under Para 2.1.

Turndown

The turndown of the unit is 30% on the “normal” feed gas rate (case 1) and composition as defined under Para 2.1.

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Product Specifications

The product sulfur will meet the following specification after degassing.

State : liquid sulfur

Color : bright yellow (as solid state)

Purity : min. 99.9 wt% on dry basis

H2S : 10 ppm weight max

6.2. PROCESS DESCRIPTION The sulfur recovery process applied in the present design, which is known as the Clause process, is based upon the combustion of H2S with a ratio controlled flow of air which is maintained automatically in sufficient quantity to evolve the complete oxidation of all hydrocarbons and ammonia present in the sour gas feed and to burn one third of the hydrogen sulfide to sulfur dioxide and water. H2S + 3/2 O2 SO2 + H2O + Heat The major percentage of the residual H2S combines with the SO2 to form Sulfur, according to the following equilibrium reaction 2 H2S + SO2 3S + 2H2O + Heat

Sulfur is formed in vapour phase in the main combustion chamber. The primary function of the waste heat boiler is to remove the major portion of heat involved in the combustion chamber. The secondary function of waste heat boiler is to condense the sulfur, which is drained to a sulfur pit. At this stage 60% of the sulfur present in the sour gas feed is removed. The third function of the waste heat boiler is to utilize the heat liberated there to produce LP steam (4 kg/cm2). The process gas leaving the waste heat boiler still contains a considerable part of H2S and SO2. Therefore, the essential function of the following equipment is to shift the equilibrium by adopting a low reactor temperature thus removing the sulfur as soon as it is formed. Conversion to sulfur is reached by a catalytic process in two subsequent reactors containing a special synthetic alumina catalyst. Before entering the first reactor, the process gas flow is heated to an optimum temperature by means of a line burner, with mixing chamber, in order to achieve

52

a high conversion. In the line burner mixing chamber the process gas is mixed with the hot flue gas obtained by burning fuel gas with air. In the first reactor the reaction between the H2S and SO2 recommences until equilibrium is reached. The effluent gas from the first reactor passes to the first sulfur condenser where at this stage approximately 29% of the sulfur present in the sour gas feed is condensed and drained to the sulfur pit. The total sulfur recovery after the first reactor stage is 89% of the sulfur present in the sour gas feed. In order to achieve a figure of 94% sulfur recovery the sour gas is subjected to one more stage. The process gas flow is once again subjected to preheating by means of a second line burner then passed to a second reactor and the sulfur condensed in a second condenser accomplish a total sulfur recovery of 94%. A sulfur coalescer is installed downstream the last sulfur condenser to separate entrained sulfur mistfter the first reactor stage is 89% of the sulfur present in the sour gas feed. In order to achieve a figure of 94% sulfur recovery the sour gas is subjected to one more stage. The process gas flow is once again subjected to preheating by means of a second line burner then passed to a second reactor and the sulfur condensed in a second condenser accomplish a total sulfur recovery of 94%. A sulfur coalescer is installed downstream the last sulfur condenser to separate entrained sulfur mist. The heat released by the subsequent cooling of gas and condensation of sulfur in waste heat boiler and, sulfur condensers results in the production of low-pressure steam.

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PROJECT- I

MATERIAL BALANCE AROUND REACTOR – REGENARATOR SECTION

In any industrial plant, mass balance over the plant and/or over any particular unit is a very important part for the daily operation of the plant. Material balances

54

are fundamental to the control of processing, particularly in the control of yields of the products. Ideally, by the Law of Conservation of Mass, the amount of feed going inside the plant should be equal to the amount of products leaving the plant. But this usually doesn’t happen and we encounter many losses during the process.

Mass In = Mass Out + Mass stored.

Feed + Air + Steam = Products + Coke formed + Losses.

Flow rate (m3/hr) Specific Gravity

Feed 185 0.91

Air 76000 1.21

Atomising Steam 5.0 tonnes/hr

HCO Steam 0.4 tonnes/hr

Slurry Steam 0.3 tonnes/hr

Stripping Steam 3.0 tonnes/hr

Y Steam 130 kg/hr

Dome Steam 500 kg/hr

Dry Gas 6.0 tonnes/hr Molecular Weight – 27

LPG 72 0.52

Gasoline 75 0.73

HN 33 0.88

LCO 18 0.95

CLO 19 1.03

Flue Gas

O2 2.7%CO2 14.8%

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CO 0SO2 0N2 + Argon 82.5%

Ambient temperature = 320C.

From the graph, dry air is 95.5%. (as Relative humidity 70%)

Wet air = 76000 m3/hr.

Dry air = Wet air * (0.955 * 1.21) / (27).

= 3240656.83 moles/hr.

Using N2 + Argon balance, flue gas out of Rg is calculated on dry basis:-

Flue Gas Rate = 3103174.42moles/hr.

Total coke formed = 6.0535 tonnes/hr.

ENERGY BALANCE AROUND REGENERATOR

56

As mass is conserved, so is energy conserved in unit operations. The combustion of coke in the regenerator satisfies the following heat requirements:

Heat to raise air from the blower discharge temperature to the regenerator dense phase temperature.

Heat to raise the temperature of the stripping steam to the reactor temperature.

Heat to raise the coke on the catalyst from the reactor temperature to the regenerator dense phase temperature

Heat to raise the coke products from the regenerator dense temperature to flue gas temperature

Heat to compensate for regenerator heat losses. Heat to raise the spent catalyst from the reactor temperature to the

regenerator dense phase temperature

ASSUMPTION:

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1) Coke is completely burnt up.2) Nitrogen doesn’t react, act as inert.3) Entrained catalyst particle heat is neglected.4) Sulfur burning isn’t considered.5) Heat losses in regenerator in 4% of combustion reaction and in reactor it is 2% of cracking reaction.6) Ambient temperature assumed -250C

GIVEN DATA:

MOLAR SPECIFIC HEAT OF FLUE GASES:

∆HCO = 16.18 Btu/kgmole 0F =17703.8229 joule/kgmole 0C

∆Hco2= 24.71 Btu/kgmole 0F =26070.41 joule/kgmole 0C

∆Ho2=16.78 Btu/kgmole 0F =17703.823 joule/kgmole 0C

∆HH2O=19.5 Btu/kgmole 0F =20573.5725 joule/kgmole 0C

∆HN2= 17.2 Btu/kgmole 0F =18146.946 joule/kgmole 0C

T (reaction) =4940C (reactor temperature at which spent catalyst enter into the regenerator)

T (region 2) = 6800C ,T (region 1) = 6700C

AT 1375 0F

HEAT OF COMBUSTION REACTION

2C +O2 2CO 48,237 BTU/lbmole =112,197284 J/kgmol

C+ O2 CO2 169,822 BTU/lbmole = 394,999000 J/kgmol

2H2 +O2 2 H2O 106,725 BTU/lbmole =248,237974 J/kgmol

SPECIFIC HEAT CAPACITY:

CP air = 0.26 BTU/ lb 0F =1088.55 J/kg 0C

CP coke= 0.4 BTU/ lb 0F =1674.69 J/kg 0C58

CP catalyst=0.275 BTU/ lb 0F = 1151.3502 J/kg 0C

VOLUME FLOW RATE OF AIR =67000 Nm3/hr

FLUE GAS CONTENT (DRY BASIS)

CO – 7%

O2—1%

CO2—9.2%

N2—82.8%

AIR CONTENT : N2 -79% , O2--21%

H/C RATIO IN COKE IS : 14%

CALCULATION:

Density of air:

PM=ρRT

105×10−3×28.87=ρ×8.314×298

ρ=1.165254kg /m3

Air flow rate ¿78071.99 kg/hr

N2 balance

Nitrogen in air required for regenration = nitrogen in flue gases

0.79×78071.9928.87

=.828×x

0.79×78071.9928.87× .828

=x

x=2580.1516 kgmole/hr

We have,

CO – 7% =180.61kgmole /hr59

O2—1% =25.801516kgmole /hr

CO2—9.2%=237.374 kgmole/hr

N2—82.8% =2136.365kgmole /hr

AIR CONTENT : N2 -79% , O2--21%

O2 in air = 567.895kgmole /hr

O2 in flue gases = 25.8015kgmole /hr

O2 consumed in reaction :

2C +O2 2CO :O2 consumed = 237.374 kgmole/hr

C+ O2 CO2 :O2 consumed =90.305kgmole /hr

2H2 +O2 2 H2O :O2 consumed : what ever the O2 left =214.414 kgmol/hr

H2O formed= 428.828 kgmol/hr

Heat of combustion:

(∆HCO)rxn = 20264063.66 KJ/hr

(∆Hco2)rxn =93762492.63 KJ/hr

(∆HH2O)rxn = 106477950.2 KJ/hr

Heat content of flue gases:

∆HCO= 3197505.158 J/hr 0C

∆Hco2=6188437.503 J/hr 0C

∆HH2O= 8822523.948 J/hr 0C

∆Ho2= 456785.4724 J/hr 0C

∆HN2 = 38768500.29 J/hr 0C

ENERGY EQUATION USED:

(Energy in + energy generated)-(energy out )-(energy consumed)=

60

[rate of accumulation of energy]

rate of accumulation of energy=0 (assume)

Mcoke Cpcoke(Trx-Ta)+ Mcat Cpcat(Trx-Ta)+ Mair Cpair(Tair-Ta)+ heat of combustion = ∆H flue

gas (Trg2-Ta) +Mcat Cpcat (Trg1-Ta)+loss

CALCULATING LEFT HAND SIDE:

#:Mcoke Cpcoke(Trx-Ta)

Mcoke : Carbon content in CO 180.611 kgmol/hr

: Carbon content in CO2 237.374 kgmol/hr

: H content in H2O 857.676 kgmol/hr

H/C RATIO CACULATED : 857.676/5015.82 =0.17099 (for cross check)

Mcoke =5873.496 kg(C+H)

Mcoke Cpcoke(Trx-Ta)= 5873.496×1674.63× (494−25 )

¿4613217673 J /hr

#:Mair Cpair(Tair-Ta)=78071.99×1088.55× (250−25 )

¿1.9121684566×1010 J /hr

# heat of combustion= 220477950.2 KJ/hr

# Mcat Cpcat(Trx-Ta)

Mcat ? (We need to determine)

Cpcat =1151.3502 J/kg 0C, (Trx-Ta) = (494-25)

CALCULATING RIGHT HAND SIDE:

61

#:∆H flue gas (Trg2-Ta)

∆H flue gas= 57433752.4 J/hr 0C, (Trg2-Ta) = 680-25

¿57433752.4× (680−25 )=3.761910782×1010 J /hr

#:Mcat Cpcat (Trg1-Ta)

Mcat ? (We need to determine)

Cpcat =1151.3502 J/kg 0C , (Trg1-Ta)= 670-25

#: loss: 4% heat of combustion

¿0.04×220477950.2KJhr

¿8819118×103 J /hr

NOW, substituting above value in our energy balance equation:

Mcoke Cpcoke(Trx-Ta)+ Mcat Cpcat(Trx-Ta)+ Mair Cpair(Tair-Ta)+ heat of combustion =

∆H flue gas (Trg2-Ta) +Mcat Cpcat (Trg1-Ta)+loss

We get,

2.06381×1011=M cat×202637.6352

M cat=1018472.69Kghr

=1018.42 tonnes /hr

REACTOR HEAT BALANCE

62

Given:

Flow rates :

Feed: 160200 kg/hr

Feed steam: 4 ton/hr

HCO nozzle steam : 300 kg/hr

Slurry steam : 2.5 ton/hr

Stripping steam : 2.5 ton/hr

Lift steam : 180 kg/hr

Wye steam : 100 kg/hr

Heat content :

Feed : 276.64 btu/hr

Feed vapors going out of the reactor :726 btu/hr

CPSTEAM :0.55 kcal/0C

Temperatures :

Steam inlet : 2500C

Steam outlet : 4940C63

Heat balance :

Heat in – Heat out = Heat of reaction ---------------------------(1)

Heat in :

Feed: Mass flow rate of feed * Heat content of feed

= 160200 * 643.897

=103152321.5 J/hr

Steam : Mass flow rate of steam * CPSTEAM * ∆T

= (4000+300+200+2500+180+150) * 0.55 *1000*4.186*(250-25)

= 3797068275 J/hr

Regenerated catalyst : Mass flow rate of catalyst* CP cat * ∆T

=1018472.69*1151.3502*(670-25)

=7.56339*1011 J/hr

Heat out:

Reacted vapor: Mass out flow rate of the reactor*Heat content of vapor

= 160200*1691676.159

= 2.7*1011 J/hr

Spent catalyst: Mass flow rate of catalyst* CP cat * ∆T

= 1018472.69*1151.3502*(494-25)

= 5.499582*1011 J/hr

Coke : Mass flow rate of coke* CP coke * ∆T

= 5873.496*1674.69*(494-25)

= 4613217673 J/hr

Losses : 0.02*Heat of reaction

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Total heat in = 8.25279*1011 J/hr

Total heat out =8.632883898*1011 J/hr + 0.02* heat of reaction

Putting above values in equation 1.

Heat of reaction inside the reactor is 3.73*1010 J/hr or 35.3 mbtu/hr

65

PROJECT -II

NPSHa CALCULATION OF FEED PUMP

PROBLEM STATEMENT: NPSHa (net positive suction head) available calculation of running feed pump (301-P-01 A/B) of DHDT unit . This pump is a feed pump which is pumping GAS OIL (diesel with sulfur impurity) from feed surge drum to preheater exchangers.

Given data:

66

Surge drum pressure: 2.5 kg/cm2(atm)

Length of pipeline: 20m

Inner diameter of pipe line: 12 inches = 0.3048m

Height of surge drum from ground= 7m

Height of impeller eye from ground= 1.5m

Difference in height= 6.5 m

Number of bends in pipeline network = 9 all are elbow (900C) KL =1.5

Valve= shut down valve KL =0.26 & isolation valve KL=2

Mass flow rate through pump=225 tonnes\hr

Fluid property @ 400C

Density of fluid= 831 kg/m3

Viscosity= 2.3 x 10-3 poise

Vapor pressure of GAS OIL =2.5 kg/cm2(ata)

Vapor pressure is based on dissolved blanketing gas at the drum operating pressure of 1.5 kg/cm2 (g), true vapor pressure of pumped liquid is 0.01 kg/cm2 (a)

ASSUMPTIONS:

1) Ideal case is considered so that we can apply Bernoulli’s principle for the system.

2) Velocity of fluid in surge is 0.

3) All type of losses are considered (major+ minor loss).

4) Impeller eye dia= pipe line diameter.

Calculations:

Step 1) applying Bernoulli’s equation between points 1 and 2, that is from surge drum to impeller eye.

67

P1

ρg+V 1

2

2g+z1=

P2

ρg+V 2

2

2 g+ z2+H L

V 1❑=0,z1=7 , z2=1.5 ,

P1

ρg=30.70371m ,V 1

2

2g=0 , z1−z2=6m

V 2❑= m

ρ A= 225000×4

3600×831×π×(0.3048)2=1.031287m / s

V 22

2g=0.052617m

Step 2) losses calculation:

a) Major losses =4 f L v2

D 2g, where f is Darcy’s friction factor and a function of

Reynolds number

f=0.079

ℜ0.25

ℜ= ρ v dμ

=831×1.031287×0.3048

2.3×10−3=113572

f=0.004303

H Lmajor=4 f L v2

D 2g=0.06123m

b) Minor losses:

1) Due to 9 elbow joints (threaded):(k¿¿ l v2

2g)×9=¿¿0.731802m

2) Due to shut down valve:(k¿¿ l v2

2g)¿=0.014094m

3) Due to isolation valve (k¿¿ l v2

2g)¿=0.108415m

Note: a) losses due flanges and nozzles are neglected because the value of losses is very less.

68

b) T joint is counted as elbow bend.

Total minor losses: H Lminor=0.854311m

Total losses: H Lmajor+H Lminor=0.854311+0.06123=0.91554m

Step 3) calculating suction side:P2

ρg=P sρg, where PS is suction side pressure of

impeller eye.V 22

2g=V s

2

2g, where Vs is velocity at the suction.

P2

ρg=P1

ρg+V 1

2

2g+z1−( V 2

2

2 g+ z2+H L)

P2

ρg=36.2355m

Step 4) NPSHa calculation:

Net positive suction head available = P sρg

−Pvρg

+V s

2

2g, where Pv vapor pressure of gas

oil+N2

NPSHa= 5.51 m

Conclusion:

1. The calculated NPSH available is greater NPSH required i.e., 4m. So the pump is working on cavitation free condition.

2.3. Our calculated value of NPSHa is almost consistent with verified

value.

69

Submitted By:SWEETY CHANDAK

B.TECH, CHEMICAL ENGINEERING

MNNIT, ALLAHABAD

70