report - sweety
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REPORTTRANSCRIPT
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
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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)
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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
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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
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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
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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)=
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[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:
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#:∆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
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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
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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:
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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.
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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.
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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.
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Submitted By:SWEETY CHANDAK
B.TECH, CHEMICAL ENGINEERING
MNNIT, ALLAHABAD
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