Vocational Training Report

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This report was submitted to Indian Oil Corporation Limited, Mathura Refinery after completing the vocational training. The training was a month long. The report contains description of various units at Mathura Refinery followed by project report. The following projects were completed:PROJECT 1: CALCULATION OF REFORMER EFFICIENCY IN HGU UNITPROJECT 2: DESIGN OF E-07 SHELL AND TUBE HEAT EXCHANGER IN DHDT UNIT





(16th May – 12th JUNE 2014)

Submitted By:

B.Tech (Chemical Engineering)
SCHOLAR NO. 111116313

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Industrial training is the beginning of students’ journey in the corporate
world. Not onl y does it provide insights about the industry concerned, it also
bridges the gap between theory and practical knowledge. We were fortunate
that we were provided with an opportunit y of undergoing Industrial training
at INDIAN OIL CORPORATION Ltd ., Mathura, one of the leading
refineries in India.
The experience gained during this short period was fascinating to say the
least. It was a tremendous feeling to observe the operation of different
equipments and processes. It was overwhelming for us to notice how such a
big refinery is being monitored and operated with proper co -ordination to
obtain desired results.
During our training we realized that in order to be a successful process
engineer one needs to possess a sound theoretical base along with the acumen
for effective practical application of the theory.
Thus, we hope that this industrial training serves as a stepping -stone for us
and helps to be successful in future.

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I hereby declare that this project report is the record of authentic work carried out by us during
the period from 16.05.2014 to 12.06.2014 and has not been submitted to any other factory or
industry for the award of any certificate. I also assure that this report doesn’t contain any
confidential information of IOCL.

(Prashant Yadav)
Date : 12/06/2014

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I feel immense pleasure and privilege to express my deep sense of gratitude, indebtedness and
thankfulness towards those who generously helped me colour the mosaic of this training with
their knowledge, expertise and memories. I shall remain ever grateful to all the persons of
I.O.C.L, who have helped, inspired and encouraged me and above all made me an ever more
experienced person.
I am greatly indebted to my Industry guide Mr. VINOD KUMAR, Senior Production Manager
who inspired, encouraged and guided me throughout my summer training.
For their invaluable guidance, kind cooperation, inspiration and encouragement during all the
stages of my training, I would like to thank Mr. Yogendra Kumar, Shift Incharge (DHDT)
and Mr. Manoj Bhala, Mr. MAYANK JOSHI, Mr. Gaurav Bajaj Shift Incharge (HGU1)
who all has been of immense help during my training period and thousands of other I.O.C.L
employees whose name I could not mention just for the lack of space. Last but not least, I would
like to convey my hearty and blossom thanks to my friends and fellow mates who have directly
or indirectly helped me in the compilation of this report
I would also like to express our deep sense of gratitude to Mr. J. N. Bhilware (Senior Training
and Development manager) for granting us permission to undergo training at IOCL, Mathura
refinery over a period of one month and for providing us with necessary inputs as and when
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. At the end, I again express my
gratitude to all those who helped me in any way to complete my training successfully.


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This is to certify that Mr. PRASHANT YADAV, 111116313, 3rd year (6th sem), MANIT,
Bhopal, has successfully completed her vocational training from 16/5/14 to 12/06/14 at “Indian
Oil Corporation Limited, Mathura Refinery” in partial fulfillment of her course during the
degree of Bachelor of Technology in Chemical Engineering from Maulana Azad National
Institute of Technology, Bhopal.

Mr. Vinod Kumar
(Senior Production Manager)
Mathura Refinery

Mr. J.N. Bhilware
(Senior training and
development officer)
Mathura Refinery

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The oil and gas sector is life line of the country’s rapid economic growth it contributes over 15%
to the Gross Domestic Product (GDP).Oil is extremely crucial commodity; it accounts for 34%
of India’s total energy consumption and has been growing gradually .The consumption of oil is
increasing rapidly but the production is more or less constant. (Refer exhibit 1, 2) This means
that oil marketing companies have huge scope to capitalize this gap by tapping more reserves
and producing hydrocarbons because India has 26 sedimentary basins covering an area of 3.14
million km2, of which only 20 per cent has been moderately to well explore. Exploration efforts
have been initiated in 44 per cent and 36 per cent remains poorly to completely unexplore. Oil
and gas industry of India is broadly classified as Upstream, Downstream and Industry bodies.

An oil refinery is an industrial process plant where crude oil is processed and refined into more
useful petroleum products, such as gasoline, diesel fuel, and asphalt base, heating oil, kerosene,
and liquefied petroleum gas. Oil refineries are typically large sprawling industrial complexes
with extensive piping running throughout, carrying streams of fluids between large chemical
processing units.

1. Barauni Refinery
2. Bina Refinery
3. Bongaigaon Refinery
4. Chennai Petroleum Corporation Limited
5. Digboi Refinery
6. Essar Oil refinery
7. Gujarat Refinery
8. Guwahati Refinery
9. Haldia Refinery
10. Jamnagar Refinery
11. Kochi Refineries
12. Mangalore Refineries and Petrochemicals Limited
13. Mathura Refinery
14. Mumbai Refinery

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15. Mumbai Refinery Mahaul
16. Nagapattnam Refinery
17. Numaligarh Refinery Limited
18. Panipat Refinery
19. Visakhapatnam Refinery

Raw or unprocessed crude oil is not generally useful in its raw or unprocessed form, as it comes
out of the ground. Although "light, sweet" (low viscosity, low sulfur) crude oil has been used
directly as a burner fuel for steam vessel propulsion, the lighter elements form explosive vapors
in the fuel tanks and so it was quite dangerous, especially in warships. Instead, the hundreds of
different hydrocarbon molecules in crude oil are separated in a refinery into components which
can be used as fuels, lubricants, and as feedstock in petrochemical processes that manufacture
such products as plastics, detergents, solvents, elastomers and fibers such as nylon and
polyesters. Petroleum fossil fuels are burned in internal combustion engines to provide power for
ships, automobiles, aircraft engines, lawnmowers, chainsaws, and other pieces of power
equipment. Different boiling points sallow the hydrocarbons to be separated by distillation. Since
the lighter liquid products are in great demand for use in internal combustion engines, a modern
refinery will convert heavy hydrocarbons and lighter gaseous elements into these higher value
Crude oil is separated into fractions by fractional distillation. The fractions at the top of the
fractionating column have lower boiling points than the fractions at the bottom. The heavy
bottom fractions are often cracked into lighter, more useful products. All of the fractions are
processed further in other refining units

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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
 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 12 for over
48% petroleum products market share, 34.8% national refining capacity and 71% downstream
sector pipelines capacity in India.

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It has a portfolio of powerful and a much-loved energy brand that includes Indane LPG as,
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. IndianOil 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 country wide 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 LPG as bottling plants, Indian Oil 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 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,
IndianOil 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

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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
· 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 .
Organizational Set-Up and Network of Marketing Division
The Marketing Division, with its headquarters at Bombay and headed by Director (Marketing),
has four regional offices located at Bombay, Delhi, Calcutta and Madras. All regional offices are
headed by either Executive Directors or General Managers. There are 44 Divisional Offices,
including two of the Assam Oil Division. As on 31 March, 1995, the Company had 39 bulk
storage installations (including 3 of AOD) and 117 storage depots, which fed 5995 retail outlets.
In addition, there were 2898 kerosene/light diesel oil dealers who also move these products from
the depots to 4379 consumer outlets for sale. The Company had a total product tankage of 3.93
million kilo liters at its installations and depots. Being the major producer and distributor of LPG
to various types of consumers in India, the Company has 32 area offices to deal with LPG
marketing, as on 31 March, 1995, the Company had 33 LPG bottling plants with a total bottling
capacity of 11.92 lakh ones per annum. Indane cooking gas (LPG) is distributed to 12 million
 Auto LPG
 Aviation Turbine Fuel (ATF)
 Bitumen
 High Speed Fuel
 Industrial Fuels
 Liquefied Petroleum Gas
 Lubricants and Greases
 Marine Fuels
 MS/Gasoline
 Petrochemicals

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 Refining
 Pipelines
 Marketing
 Training
 Research & Development
Location of various I.O.C Refineries:
 Digboi Refinery,
 Guwahati Refinery,
 Barauni Refinery
 Gujarat Refinery
 Haldia Refinery
 Mathura Refinery
 Panipat Refinery
 Bongaigon Refinery

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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 sulphur crude from Bombay High,imported low sulphur
crude from Nigeria, and high sulphur 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 was laid by Indira Gandhi, the former prime
minister of India. The FCCU and Sulphur 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), Visbreaker 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
Desulphurisation Unit (DHDS) licensed from Axens, France was commissioned in 1999 for
production of HSD with low Sulphur 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 EuroIII grade HSD & MS w.e.f. 1st April 2005 as per Auto Fuel Policy of Govt. of India. Project for
FCC Gasoline Desulphurization (FCCGDS) and Selective Hydrogenation Unit (SHU), the
Prime-G technology of Axens, France was commissioned in February 2010 and supply of EuroIV 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 Sulphur Recovery Units (SRU) was replaced with
new Sulphur Recovery Units with 99.9 % recovery in the year 1999. Additional Sulphur
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 upgradation, 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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Mathura Refinery received the prestigious Oil Industry Safety Award 2008-09 for Best
Overall Safety Performance among Refineries. Shri J.P. Guharay, ED Mathura Refinery
received the award from Shri Murli Deora, Minister of Petroleum and Natural Gas at a
glittering function held in Oct’ 09 at Delhi.
Mathura Refinery received Gold Award in Petroleum Refinery sector from Greentech
Foundation, New Delhi, for outstanding achievement in Safety Management in 2008. The
award was presented by Shri R.K. Srivastava, Director General, Ministry of Health & Family
Welfare, Govt. of India, New Delhi on 4th May 2009 at Goa.
Received British Safety Council Award’08 in May’09 for excellence in Health, Safety and
Environment Management.
Received Safety Innovation Commendation-2009 award from Institution of Engineers in
Sep’09 for innovation in Safety for 2008-09.


Received Best Corporate Security Trophy (Refinery Category) for two consecutive years i.e.
2008 & 2009.

Energy Conservation:

Mathura Refinery received First Prize of 'Oil and Gas Conservation Fortnight - 2009' for
lowest Steam Consumption Performance amongst Refineries having steam consumption
<= 0.5 MT/MT and same was received by ED, MR during 15th RTM at Mahabalipuram
on 5th Nov.’09.
Received 'Jawaharlal Nehru Centenary Award 2008-09' - second prize for Specific
Energy Consumption Performance amongst all refineries in the public sector. ED, MR
received coveted award during 15th RTM held at Mahabalipuram on 5th Nov-09


Received ‘Gold Award-2009’ from Greentech Foundation for outstanding achievement in
Environment Management in Oct’09.


Received the “Sammaan Patra” for the year 2009-10 in the category of Large Scale Units, by
Central Excise Dept., Lucknow Circle in recognition of the highest levels of compliance with
regard to Indirect Taxes apart from contribution to the exchequer. The trophy was received
by GM(F)-MR at Lucknow on 24th February, 2010.

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Mathura Refinery TPM health checkup was carried out by CII on 23rd December’09
thereby approving the nomination of Mathura Refinery for final audit on Excellency
Certification in TPM activities by JIPM.
Propylene bulk truck loading facility completely shifted to new location outside refinery
premises at Marketing Terminal in Oct’09.
In land matters, the search certificates as well as Non-encumbrance Certificates for
1199.49 acres of land of Mathura Refinery received from District Revenue Officer. The
UP Gov. has also provided the NOC for 1199.49 acres of land enabling appropriate
mortgage with State Bank of India.
70 cases with Customs were settled and refund of Rs 55.12 crores received from Customs
Department in Mar’10.
Various PFIs of Business Improvement Program with M/s Shell Global were successfully

At Mathura refinery, technology and ecology go hand in hand with continuous endeavour for
product quality up-gradation, energy conservation and environmental 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 in 1998.

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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)

3. Lube Oil Products:

Inter Neutral, Heavy Neutral & Bright Neutral HVI Grades

3. Other Products:

Slack Wax
Carbon Black Feed Stock

-reliance defining technology, Mathura
refinery is poised for a bright future. All out action have taken for capacity augmentation,
increase in distillate production, value addition, cost reduction for obtaining higher margins and
improving productivity. All environmental friendly products with latest technology is being
incorporated to meet the challenge of change. Mathura refinery will continue to play a significant
role in meeting the vital needs of petroleum products in the country.

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Safety, Health & Environment (S, H&E) Policy
Indian Oil Corporation is committed to conduct business with strong environment conscience
ensuring sustainable development, safe workplaces and enrichment of quality of life of
employees, customers and the community. We at Indian Oil believe that good safety, health &
environment performance is integral part of efficient and profitable business management.
We shall:
Establish and maintain good standards for safety of the people, the processes and the
Comply with all rules and regulations on safety, occupational health and environment
Plan, design, operate and maintain all facilities, processes and procedures to secure
sustained safety, health and environmental protection.
Remain trained, equipped and ready for effective and prompt response to accidents and
Welcome audit of our safety, health & environment conduct by external body, so that
stakeholder confidence is safeguarded.
Adopt and promote industry best practices to avert accidents and improve our safety,
health & environment performance.
Remain committed to be a leader in safety, occupational health and environment
protection through continuing improvement.
Make efforts to preserve ecological balance and heritage.

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Crude oil is a complex mixture of thousands of hydrocarbons. (i.e paraffins, napthenes &
aromatics). It is brownish black in colour and colloidal in nature. It contains small amounts
of non-hydrocarbon impurities in the form of organic compounds of sulphur, oxygen,
nitrogen, metals, water and salts.

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AVU consists of following sections:

Crude Desalting section

Atmospheric Distillation section

Stabilizer section

Vacuum Distillation section


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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 proportionated quantity of demulsifier into the unit crude pumps
suction header with the help of dosing pump is available.

Before treating the crude it is necessary that the salts and sediments from it be removed
because the hydrolysis of salts in crude oil at high temperature produces hydrochloric acid
which corrodes the Column Internals and overhead system. The sediments in crude oil foul the
heat exchanger, furnace tubes and erode the pipelines by abrasive action. Desalting approaches
to reduce soluble salt content, to reduce suspended solids and to reduce residual water.
Desalting of crude oil is carried out in a vessel provided with electrodes under high potential
field(15000-18000 Volts)
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
The crude after leaving the desalter is preheated to 250 to 265 ºC. The preheated crude is
further heated and partially vaporized in Atmospheric Furnace (four furnaces with four pass

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.
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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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 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.

RCO from CDU is heavy, and the separation of this stream into various fractions would
normally require more energy and higher temperatures. Also higher hydrocarbons
promotes coking reactions at more than 380 deg c at atmospheric pressure fouls the
furnace tubes.
The vacuum condition reduces the boiling point of the RCO and the fractions are
separated relatively at lower temperature which lead to energy saving and reduces fouling
ofthe furnace tubes
Reduce the amount of energy input required, and to recover the valuable products from
RCU cracking, it is distilled under vacuum.

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The Visbreaker Unit is a thermal cracking unit, designed for processing a mixture of
Atmospheric and Vacuum Residue from 1:1 mixture of Light Arabian and North Rumila crudes
.It reduces the viscosity and pour point of heavy petroleum fractions so that product can be sold
as fuel oil. It reduces the viscosity and pour point of heavy petroleum fractions so that product
can be sold as fuel oil. The design capacity of the plant is 1000,000 TPA.

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 Thermalcracking reaction, heavy oil is kept at a high
temperature of 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 characterised 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-CH3 CH3-CH2-CH=CH2 + CH3- CH2-CH3
During the cracking operation, some coke is usually formed. Coke is the end product of
polymerisation reaction in which two large olefin molecules combine to form an even larger
olefinic molecule.
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 40 .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

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Soaker effluent after quenching enters fractionator. Temperature in the flash zone is around
420 (C. 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 stabiliser 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 4.5 kg/cm2 (g). Column overhead line is provided with working and
controlled safety valves.
The heavy naphtha at a temperature of about 170 (C 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 (C is withdrawn from the blind accumulator tray
under tray level controller. It is steam stripped in the stripper to maintain its flash point. Vapour
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 stripper 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 is used as heating media in
steam generator where it is cooled from 260 (C to 214 (C. The second stream supplies reboiling heat to stabiliser re-boiler and gets cooled from 260 (C to 215 (C. To protect column
bottom against coking, cooled VB tar at 225 ( C is injected into bottom as quench. Gas oil
vapours from top of stripper get 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 (C to 225 (C in feed exchangers and further cooling to 214 (C 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 VB tar is then cooled in boiler feed water
exchanger from 2320 C to 2100 C. It is further cooled to 900 C and sent to storage with gas oil.

Un-stabilised gasoline from reflux drum is picked up by reflux pump and then it is pumped to
stabiliser through stabilised gasoline exchanger. In heat exchanger, feed is heated from 43 (C
to 120 (C while stabilised gasoline is cooled from 180 (C to 120(C. The column has 30 trays
and the feed enters on the 19th.
The overhead product at 60 (C 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

P a g e | 26

the drum is maintained around 8.4 kg/cm2 (g). In case FCC is shutdown, gas is burnt in furnaces
via gas knock out drum. Column overhead has working and controlling safety valves, which
release gas.

P a g e | 27


P a g e | 28

Fluidised catalytic cracking is a process for converting higher molecular weight hydrocarbons
into lighter, most valuable product through contact with a powdered catalyst at appropriate
Process conditions. Typically FCC process is used to
convert excess refinery gas oil
& heavier refinery stream into gasoline, C3 & C4, olefins and light cycle oil bringing
Refinery out more in line with product market demand. FCC is often the heart of a modern
refinery because of its adaptability to changing feed stocks and product demands and because
of the high margin that exists between FCC feed stock and converted FCC products.

PROCESS DETAILS:Originally Designed Capacity : 1.0 MMTPA
Capacity After Revamp : 1.34 MMTPA


P a g e | 29

FEED & PRE HEAT SECTION:1. HVGO Feed is received in feed surge drum (19V-4) from three different sources, viz.,
from feed tanks in cold feed, directly from VDU (Vacuum Distillation Unit) as hot feed and
directly from Hydro cracker Unit.
2. Hot feed from VDU and OHCU is received directly in 19V-4.
3. Balance amount of feed is fed by pumps at OM&S and received in 19V-4 (vessel) through
19 FRC-118, which can be cascaded with 19V-4 level controller in 19 LRC – 121.
4. From Feed surge drum (19V-4), feed is pumped by 19P-2A/B feed pumps through
pre heat exchanger train. Flow to both trains is regulated by 19FRC-292A/B.


5. Pre heated feed (275 – 310 C) is pumped by booster pumps 19P-25 A/B and
made to pass through 19F-1 (Furnace) into passes where it is heated up to 355 –


360 C.
6. Pre heated feed injected to reactor riser at the bottom through 4 No’s nozzles.
1- At riser bottom feed comes in contact with hot stream of regenerated catalyst and cracking
starts occurring. Flow of hot catalyst is regulated by slide value in order to control reactor
2- HCO and slurry recycles are injected into riser through 2 No’s Nozzle. Each of spray nozzle
is at two different elevations.
3- The cracking reactions are
gets deposited on the surface

endothermic. Coke generated in the cracking reaction
of the catalyst particles and thus the catalyst activity gets

4- The catalyst gets separated from cracked and uncracked HC vapours and steam at riser
termination and then at reactor cyclones.

(C) REGENERATOR SECTION:1- The spent catalyst gets accumulated at reactor stripper and HC
vapour enters 19C-1 for fractionation.
2- Oxidation of coke is highly exothermic reaction and it provides the necessary heat to reactor
for reaction in such a way that the unit remains in heat balance always.
3- Flue gases rich in CO pass through CO-boiler where CO is burnt and generated heat is used
for steam production.

P a g e | 30

(D) FRACTIONATOR SECTION:1- The super heated vapours from reactor enters 19C-1 below the bottom most tray and is


cooled down to 360 c for fractionation. Main column bottom (MCB) is circulated back to
column through two sets of exchanger (19 E-3 A/B/C/D, 19D-4 & 19 E -21) to de-super
heat the vapour coming from reactor.
2- A stream of MCB is taken to 19V-3 slurry settler where catalyst gets settled at circulating
reflux after supplying heat to reboiler 20 E-7 of stripper bottom and exchanging heat with
raw oil in 19-E-17. A stream of LCO is used as an absorbent in 20C-2 & is also returned
back to 19C-1 with other LCO reflux streams.
3- The de-super heated vapour rise up in the fractionation column. The first fraction accumulated
in draw off tray is HCO. The Heavy cycle oil circulating reflux transfers its heat to 20C-4 bottom
in reboiler 20 E-12 and in steam generator drum 19E-7 and in 19E-2 with raw oil. A part of the
HCO is recycled back to riser at HCO nozzle & a stream
injected at 19V-3 bottom cone to
dilute the catalyst mixed slurry.
4- LCO drawn from accumulator below 19


tray is sent back to column as a reflux.


5- Heavy naphtha cut is drawn from accumulator below 2
packing and return back to column
as a circulating reflux for the heat balance after exchanging heat is 18E-21 with hot water
and in 19E-15 with raw oil. Return stream after passing 18E-21 & 19E-15 further can be
cooled in air coolers on requirement.
6- A part of LCO & heavy naphtha draws are stripped in 19C-2& 19C-3 respectively and routed
to product tanks after exchanging heat in PRU and cooling as diesel component.
7- Overhead vapours from the top of column pass through air coolers 19 E – 13 A/B/C/D.
1- Some amount of liquid from 19 V-5 is pumped back to column as reflux to control the 19 C1 temperature and balance amount of net over head liquid is pumped out to 20 C-1.
2- Uncondensed vapours from 19 V-5 are sucked and compressed by WGC, cooled and
liquid is collected in HP receiver 20 V-3.
3- Liquid from 20 V-3 is fed to stripper where it is heated in 20E-8 & 20E- 7 to strip out
hydrogen sulfide, methane and ethane etc. before sending to debutanizer for stabilization. 4Stripped gases from 20C-3 top combined with WGC discharge, 20C-1 bottom liquid &
20V-1 bottom stream are cooled down to recover LPG.
5- Gases and H2S pass through absorber for the recovery of LPG & Gasoline and finally
routed to refinery fuel gas system after H2S absorption in 20C-6.
6- 20C-3 bottom material in fed to 20C-4 where it is separated into LPG & Gasoline. 7LPG is routed to merox unit for H2S and mercaptans removal.
8- Gasoline is routed to Gasoline splitter unit for preparation of MSQU feed. Top and bottom
material of GSU is routed to merox for mercaptans to disulphide oil.

P a g e | 31

FCC Feed Characterization
FCC feed characterization is one of the most important requirements of catalyst cracking.
Understanding feed properties and knowing their impact on unit performance is essential
in anything that has to do with FCC operation including troubleshooting,catalyst selection,
unit optimization and subsequent process evaluation. Feed characterization is a means of
relating feed quality to product yield and quality. Knowing the effect of a feed stock on
unit yields, a refinery can purchase the feed stock that would maximize profitability. It is
not uncommon for many refineries to purchase raw oil (crude oil or FCC feed stock)
without knowing their impact on unit operation At times, this lack of knowledge can
cause unit shutdowns for several weeks.

P a g e | 32

Mercaptans are undesirable in the final products because it effects their stability, sulfur content,
odour etc. Objective of merox treatment process is the conversion of Mercaptans to di-sulphides.
Feed used is ATF, Gasoline, VB Naphtha and
LPG. Reaction observed in the process is:


2RSH + /2O2 RSSR + H2O
Straight-run LPG, gasoline and kerosene fractions obtained from atmospheric distillation may
contain hydrogen sulphide and mercaptans. the extent of which mainly depends upon the type of
crude processed. Similar products from secondary processes such as FCC also contain hydrogen
sulphide and mercaptans to a greater degree compared to straight-run products. Hydrogen
sulphide is corrosive and should be remove in order to meet specifications on corrosion rate. The
specification for LPG, gasolene, Kerosene and ATF include copper strip corrosion test which is
a measure of rate of corrosion on copper containing materials.Mercaptans are substances with
obnoxious odour and, therefore, in order to handle and store them, mercaptan level will have to
be brought down to a acceptable odour level. Hydrogen- sulphide can be easily removed by
washing with dilute caustic solution. However, for reducing the mercaptans level many
processes are available like:
Strong alkali-wash Copper
sweetening Doctor

The removal of mercaptans may be either partial or full. The chemical treatment is based on
the ability of Merox catalysts to promote the oxidation of mercaptan to disulphide using air
as the source of oxygen. The overall reaction is as follows:


2RSH + /2O2 RSSR + H2O
The oxidation is carried out in the presence of an aqueous alkaline solution such as either
sodium hydroxide or potassium hydroxide. The reaction proceeds at an economical rate at
normal rundown temperature of refinery streams. Low molecular weight mercaptans are
soluble in caustic solution and therefore when treating LPG and light gasoline fractions, the
process can be used to extract mercaptan to the extent, they are soluble in caustic. Extraction of
ercaptan reduces the sulphur content of the treated product.

P a g e | 33


Pretreatment for kero/ATF consists of a coalescer and caustic prewash vessel, for removal of
suspended water and hydrogen sulphide, Naphthenic acid etc.
Sweetening is achieved in supported catalyst bed reactor. Two reactors in parallel have been
provided. Air requirement of all Merox units is supplied from a common compressor. Also,
storage tanks for receipt, dilution and storage of caustic and storage for methanol have been
Post treatment for kero/ATF consists of caustic settling. water wash to wash of any carry- over
caustic salt drier for drying and clay filters forimproving colour stability of treated product. Clay
adsorbs coloured nitrogen compounds.

P a g e | 34

Objective: To Upgrade the Naphtha to High Octane MS Component
(Reformate). Feed: 85-160 Deg C cut Naphtha / Visbreaker Naphtha
Catalyst: Ni-Mo Oxides for NHTU Reactor
Pt-Sn or Re for Reforming
Product Yields:
Sl. No.
Motor Spirit
Hydrogen rich gas
Operating Conditions:
Temperature range: 490-540 C
System Pressure: 2.0 -30 kg/cm2


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. Reformate
produced by this process has a very high octane rating. Significant quantities of hydrogen are
also produced as a by-product.
The whole CRU can be divided into three subunits as:
Naphtha Splitting Unit (NSU)
Naphtha Hydro-treater Unit (NHU)
Catalytic Reforming Unit
This unit has been designed to split SR naphtha (144 MT/hr for BH and 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 cut is raised to approximately 105 oC. NSU can be operated
with naphtha directly from AVU (hot feed) and from OM&S (Cold feed), it can also be operated
using both the feed simultaneously. For removal of benzene, the gasoline from storage tanks and
CDU is sent to a column, containing 40 valve trays, which is called naphtha splitter. The bottom
product of naphtha splitter is sent to the NHU.
The purpose of Naphtha hydrotreater is to eliminate the impurities (such as sulphur, nitrogen,
halogens, oxygen, water, olefins, di-olefins, arsenic and metals) from the feed that would
otherwise affect the performance and lifetime of reformer catalyst. This is achieved by the use of
selected catalyst (nickel, molybdenum) and optimum operating conditions except for water,
which is eliminated in stripper.
In this unit, the naphtha coming from the NSU is mixed with H2 which comes from the
reforming unit. This mixture is heated to 340 OC in the furnace and then passed to the
hydrotreater reactor at a pressure of 22 kg/cm2. In the reactor, there are two beds of catalyst. In

P a g e | 35

one bed, the unsaturated hydrocarbons are converted to saturated hydrocarbons and in the second
bed impurities like N, S, and O are converted to NH3, H2S and H2O respectively. The effluent
of the reactor is sent to stripper section to eliminate the light end, mainly the H2S and moisture
from the reformate feed. The light gases from the top of stripper are sent to amine wash unit.
There is a reboiler attached to the bottom of the stripper, which maintains the heat requirement.
The bottom product of the stripper is either sent to storage or the reforming unit.
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 91 oC to
451oC by the effluent from 3rd Reactor which gets cooled down from 497o C 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.

P a g e | 36

The Hydrogen Generation unit
To meet the Hydrogen requirement of DHDS unit the Steam Naphtha Reforming Process has
been considered. Naphtha is first De-Sulfurised in the Pre-Desulfurisation Section (PDS) by
converting Sulphur in the Raw Naphtha to H2S in presence of H2. The reaction is promoted by
Co-Mo Catalyst. The H2S in then stripped of in a stripper column.
The Sweet Naphtha is further De-Sulfurised in the Final De-Sulfurisation Section (FDS). Here
again Co-Mo Catalyst is used in presence of Hydrogen. The HCI formed is absorbed in the
K2CO3 (HTG-Bed) and the H2S is adsorbed in the ZnO (HTZ-Bed). The De-Sulfurised Naphtha
is mixed with Steam and sent to the Pre-Reformer at 500°C, for conversion of Naphtha to lower
Hydrocarbons, CO, CO2 & H2 in presence of Nickel Catalyst. The gases along with Steam enter
the Reformer at 630°C. The Reforming reaction is Endothermic. Heat is supplied through the
side-fired Reformer by burning off gases of PSA, Vaporized Naphtha/ Fuel gas.
The reformed gas at exit of Reformer is cooled from 930°C to 200°C for Medium Temperature
Shift Reaction (MT-shift). The MT-shift converts CO to CO2 in presence of Excess Steam. Cu
Catalyst promotes the reaction. Pre-Heating Naphtha, BFW and DM water cool the synthesis gas
leaving the Reactor.
The impurities like CO2, CH4, CO & water vapour are removed by high Pressure adsorption on
molecular sieve, activated Carbon and Alumina in the PSA system to give 99.99% pure
Hydrogen. The adsorbed impurities are removed during De-sorption & Regeneration of the beds
and used as Fuel in the Reformer.
The main sections in Hydrogen unit:










Different type of Catalysts are used in each of the above four sections. As Steam Reforming is
high Temperature Process and shift conversion is a low Temperature Process. The Waste heat is
used for Steam generation, the Steam generated meets Steam requirement of the unit and surplus
Steam is exported.
The PSA system designed by M/s UOP comprises of six Adsorbers, each Adsorber is having
three different types of adsorbents. The PSA purification system is Micro Processor based
control system supplied by M/s UOP.

P a g e | 37

The Nickel based Catalyst used in Reformer will be poisoned by the Sulphur present in the
Naphtha. In the Pre-De-Sulphurisation section Sulphur content in Naphtha is reduced to 5 ppm
wt (approx). In the De-Sulphurisation section Sulphur content in reduced to 0.05 ppm wt.
In the Pre-De-Sulphurisation section all Organic Sulphur is converted into H2S in a
Hydrogenator which contains TOPSOE TK-550 Catalyst (Co-Mo bed) and H2S formed is
removed in a stripper column. The reactions in Co-Mo bed are as follows:
RC1 + H2

RH + HC1

RSH + H2

RH + H2S

R1SSR + 3H2

R1H+RH+2 H2S

R1SR2 +2H2

R1H+R2H+ H2S


C4H10 +H2S

COS + H2

CO + H2S

Where R is a radical of HydroCarbon.
Besides above-mentioned reactions the Catalyst also hydrogenates olefins to saturated
Hydrocarbons and Organic Nitrogen compounds are to some extent converted to Ammonia and
saturated Hydrocarbons.
In the final De-Sulphurisation section all the remaining Organic Sulphur compounds are
converted into H2S in the second Hydrogenerator. HCl and H2S formed in second Hydrogenator
are absorbed in Chlorine guard bed containing HTG-1 Catalyst and in Sulphur guard bed
containing HTZ-5 Catalyst respectively.The reactions and Catalyst in the second Hydrogenator
are same as first Hydrogenator. In order to maintain the activity in the Co-Mo Catalyst Sweet
Naphtha should have minimum 2 ppm Sulphur.In the Chlorine guard bed which contains K2CO3
following reactions take place:



2KCI + H2O + CO2

The rate of all the above reactions depends on Temperature, Pressure and Diffusion properties.
Steam Reforming of Naphtha takes place in two Reactors, Adiabatic Pre-Reformer & Tubular
Reformer. Both Reactors are having Nickel based Catalyst.In the Adiabatic Pre-Reformer
having RKNGR Catalyst all heavier Hydrocarbons are converted to Hydrogen, Carbon

P a g e | 38

Monoxide, Carbon Dioxide & Methane.In the Tubular Reformer having Catalyst a R-67-7H
Hydrogen is produced from Methane & Steam by Reforming.
Reactions in Pre-Former are :

CnHm + nH2O (Steam)

nCO + [ n + m/2 ] H2

- heat



+ H2O (Steam)

CO + 3H2

- heat



+ H2O (Steam)

CO2 + H2

+ heat

Reactions are 1 & 2 strongly Endothermic while reaction 3 is Exothermic.

Reactions in Tubular Reformer are as follows:
Reforming Reactions:
CH4 + H20 (Steam)

H=219 KJ/MOL

CO + 3H2

Shift Reaction:
CO + H20

Co2 + H2

H= -41 KJ/MOL

Ci is the partial Pressure of components in Atm.(absolute).
Reaction equilibrium is controlled by the partial Pressure of CH4, H2, CO & CO2. The
Reforming reactions are strongly Endothermic hence forward reactions are favored by high
Temperature as well as by low Pressure while the shift reaction is Exothermic and is strongly
favored by low Temperature and is largely unaffected by Pressure.To maximise overall
efficiency of the conversion for higher yield of Hydrogen, reformers are operated at high
Temperature and relatively lower Pressure.
This is followed by shift conversion, which permits the Shift Reaction to be brought to
equilibrium at a lower Temperature in a Medium Temperature Shift converter, which contains
LK-811 Catalyst. This Catalyst consists of oxides of Copper, Zinc and Chromium.
The reaction taking M.T Shift converter is:
CO + H20

CO + H2

H= -41 KJ/MOL

P a g e | 39

The PSA system is designed for full automatic operation with respect to variations in the process
gas flow.Variations in the composition (especially the CO content), pressure or temperature of
the process gas may require a variation of the adsorption time period of the adsorbed.The desired
purity of the Hydrogen determines the adsorption time of the Adsorbers. This time should be as
long as possible to obtain a high efficiency of the PSA system.
The temperature of the inlet gas to the PSA must be maintained at design temperature or below.
Too high a temperature will result in too high moisture content in the inlet gas, and less
adsorbent efficiency. Too high a temperature inlet the PSA (above 40o C) indicates bad cooling
efficiency upstream.

P a g e | 40

· To reduce low sulphur (<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.

BHARAT STAGE III 350 ppm 51(min)
Cetane number:
· A rating on a scale use to indicate the tendency of a fuel for diesel engines to 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
The main reactions taking place in the process are refining and hydrogenation reactions, in
addition some hydrocracking reactions takes place as well.
Refining reactions:
Refining reactions involve the removal of heteroatoms, namely sulphur, nitrogen and oxygen.
It also includes the saturation reactions of olefins and di-olefins.
Treating reactions:
3.1.Metal removal
3.2.Olefin saturation
3.3.Sulphur removal
3.4.Nitrogen removal
3.5.Oxygen removal
3.6.Aromatic saturation(cetane number improvement)
Desulphurisation reactions:
The aliphatic sulphur compounds, namely mercaptants, sulphides and di-sulphides react
easily leading to the corresponding saturated or aromatic compounds. Thiophenes sulphur is
most difficult to react. The reaction is exothermic.

P a g e | 41

Sulphur removed first, and then the olefin is saturated. Three mole of hydrogen consumed per
mole of sulphur. 560 kcal of heat liberated per Nm3 of H2 consumed.
R-SH + H2 RH + H2S
R-S-R + 2H2 2RH + H2S

denitrogenation reactions are slower than the hydro desulphurisation reactions, and
generally require more severe conditions especially for components having nitrogen
as a part of an aromatic ring such as pyridine.
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.
CH3-CH2-CH2-CH2-CH2-NH2 +H2 CH3-CH2-CH2-CH2-CH3 + NH3

Process flow description:
The Diesel Hydro treating Unit (DHDT) is a new unit of capacity 1.8 MMTPA. The unit has
been designed using IFP licensed hydro treating technology to treat a mixture of straight run
distillates, cracked feed stocks, and a partially hydro treated diesel from an existing DHDS
unit. The straight run distillate comprises of Heavy Kerosene, LGO, HGO, LVGO, and ATF
streams derived from the processing of a 65/35 blend of Arab Light and Arab Heavy crudes.
It also includes an AGO stream that is derived from the Nigerian crudes. The cracked feed
streams comprise of TCO from the FCC unit and a Heavy Naphtha stream from the
Visbreaker unit. The unit is designed for deep desulfurization and significant cetane number
improvement. The product gas oil would be blended into the High Speed Diesel (HSD) pool.
The wild naphtha produced in the DHDT unit is processed in a Stabilizer together with an
external wild naphtha stream from the existing DHDS unit, and the combined stabilized
naphtha product is sent to storage. The sweet Low Pressure Off-Gas stream is sent to the fuel
gas system.
The hydro treating reactions are carried out using two specific catalysts in two reactors
connected in series containing a total of five catalytic beds. The operating conditions are
chosen to meet the desired product qualities, and to obtain a longer cycle length for the
catalyst. The unit is comprised of the following sections:

The feed consists of straight run distillate and cracked streams supplied from the battery
limits. The DHDT feed blend is supplied from a common storage, except for the TCO and the
Visbreaker, Naphtha streams that are supplied directly from the FCC and the Visbreaker
units, respectively. The feed mixture could also enter the unit directly, while bypassing the
storage. The gas oil blend flows to the Feed Surge Drum through a feed filter. The feed drum

P a g e | 42

is fuel gas blanketed and the drum pressure is controlled using a split range control scheme.
Gas oil feed is pumped to the reactor circuit on flow control using the Reactor Feed Pumps.
The feed drum level is controlled by varying the DHDT feed supply from storage. Make-up
hydrogen is supplied at 19 Kg/cm2 (G), to the Make-up Compressor, and then is compressed

by the Make-Up Hydrogen Compressors. The make-up compressor has two stages and the
interstage gas cooling is done with cooling water.
The make-up hydrogen flow rate to the reaction section is controlled by means of a
compressor spillback to the K.O. Drum. An additional compression stage is eliminated for the
Make-up Hydrogen Compressor, by utilizing the Recycle Compressor, to achieve the final
compression requirement. The recycle gas stream containing the make-up hydrogen is
combined with the oil feed, and the total feed mixture is heat exchanged against the reactor
effluent in the Reactor Feed/Effluent Exchanger. A by-pass is provided on the feed side to
facilitate the Reactor Feed Heater operation at the minimum turndown situation. The
preheated oil and hydrogen mixture is heated to the reactor inlet temperature in the Reactor
Feed Heater. An air preheater is used in the convection section of the reactor feed heater to
enhance the overall heater efficiency.
The Hydrotreater Reactor contains two reactors in series, with the 1st reactor containing three
catalytic beds, and the 2nd reactor containing two catalytic beds. Recycle hydrogen is used as
the quench gas, for maintaining the desired WABT in each of the catalytic beds. The top
catalyst layer of the first bed in the 1st reactor operates at a lower temperature, and this bed
saturates the feed olefins and diolefins. The inlet temperature to the Reactor is adjusted so
that the required inlet temperature is obtained for the subsequent HDS catalyst in the same
catalytic bed. The effluent from the first catalytic bed is quenched to control the inlet
temperature of the second catalytic bed. In the remaining two catalytic beds, the targeted
average WABT is about the same to complete the remaining reactions. Quench gas is also
used for controlling the 2nd reactor inlet temperature and the temperature of the two catalytic
beds. The quench gas is supplied on flow control, reset by the catalytic bed inlet temperature.
The reactor effluent is cooled by preheating the stripper feed, and by preheating the
oil/hydrogen feed in the feed/effluent exchangers. Wash water is injected into the reactor
effluent at the outlet of the final feed/effluent exchanger shell, in order to prevent any deposit
of ammonium salts. The wash water is a mixture of recycled water from the Stripper reflux
Drum and Coalescer water, plus make-up stripped sour water supplied from the Sour Water
Stripping Unit. Additional water injection facilities are provided for the last two shells of the
feed/effluent exchanger to wash out any salt deposits, and this injection is normally not
The wash water is pumped from the Wash Water Drum on flow control to the reactor effluent
upstream of the air cooler to avoid ammonium salt deposit and the risk of corrosion. Reactor
effluent leaving the Reactor Effluent Air Cooler is collected in the HP Cold Separator Drum.
The vapor phase from this drum consists of the recycle and quenches gas circulated by the
recycle compressor. The hydrocarbon/water separation obtained in this drum is not sharp, and
hence both the hydrocarbon rich and water rich streams are let down and combined in the
downstream MP Cold Separator. The MP Separator Drum is equipped with a water boot, and
adequate residence time is provided for obtaining a good separation of the liquid and sour
water streams. Sour water is separated from the hydrocarbon liquid phase, and is routed to the
battery limits on HC/water interface level control from the settling zone of the separator. The
hydrocarbon liquid flows on level control to the stripping section. The separator also contains

P a g e | 43

a coalescing pad closer to the feed inlet nozzle. In addition to coalescing the small water
droplets, the coalescing pad also helps to streamline the HC/H2O flow in the settling zone.
The recycle hydrogen stream leaving the HP Separator Drum is routed to the HP Amine
Absorber for H2S removal. The flow of recycle gas to the HP Amine Absorber is controlled
by manually diverting a part of the recycle gas to bypass the absorber, for maintaining a
desired H2S content in the recycle gas stream. The lean amine is a 25 Wt.% DEA solution,
supplied on flow control to the HP Amine Absorber using the HP Lean Amine Pumps. The
rich amine from the HP absorber bottoms is sent to the LP Amine Absorber on level control,
for flashing off the dissolved light ends. Recycle gas leaving the HP Amine Absorber is
combined with the bypass vapor, and the total recycle gas is routed to the Recycle
Compressor, through the Recycle Compressor K.O.Drum. The hot make-up hydrogen from
the Make-up Hydrogen Compressor discharge is cooled in the Make-up H2 Cooler, 301-AC04, and the make-up H2 is combined with the recycle gas upstream of the Recycle
Compressor K.O. Drum. Therefore, the make-up hydrogen is compressed together with the
recycle and the quench hydrogen in the Recycle Compressor.
There is a provision to remove a small amount of the sweetened gas stream leaving the HP
absorber on flow control as a high pressure purge, to provide added flexibility during
operation. However, the unit is designed based on no purge gas flow, and hence normally
there is no high pressure purge gas leaving the unit. The recycle compressor is driven by a
back pressure turbine using HP Steam. The reactor circuit pressure is controlled at the HP
cold separator. The pressure is controlled through a split range control adjusting the make-up
hydrogen supply to the reactor circuit and the HP purge gas. Recycle Compressor discharge
is split into the recycle and the quench gas streams. The recycle gas containing the make-up
hydrogen is combined with the gas oil feed, and the total feed enters the reactor circuit. The
recycle plus make-up hydrogen flow is controlled by diverting the excess gas to the reactor
effluent air cooler, if that is required by pressure drop or heater firing limitations.
The Diesel Stripper fractionates the diesel product from the reactor effluent liquid stream
supplied from the MP Cold Separator Drum. The wild naphtha product from the stripper
overhead is stabilized and H2S stripped in the Stabilizer. Liquid feed from the MP Separator
is preheated by heat exchange with the stripper bottoms in the Stripper Feed/Bottoms
Exchanger, followed by the final heating by heat exchange with the reactor effluent in the
Stripper Preheater. The stripper feed temperature is controlled by varying the feed flow
through the Stripper Feed Preheater and the exchanger bypass streams.
The feed is stripped of H2S and light ends from the diesel product using the MP steam. The
Stripper overhead vapor is condensed in an air-cooled condenser, and the trim condenser. The
pressure control. The water condensate containing dissolved H2S and traces of NH3 is
removed from the Stripper Reflux Drum water boot on interface level control. This sour
water is recycled to the Wash Water Drum, for water injection upstream of the Reactor
Effluent Air cooler. The stripper reflux is returned to the tower on flow control, and the Wild
Naphtha overhead product is sent to the stabilizer on flow control, reset by the reflux drum
level. The stripped diesel product is pumped to the battery limits on level control of the
stripper bottoms. Heat is recovered from the diesel product by preheating the stripper feed.
The diesel product is further cooled in the gas oil air cooler, and gas oil trim cooler. The
dissolved water in the diesel product settles out as free water as the product stream is cooled.
The entrained water is removed in the Coalescer, before the diesel product is routed to the
battery limits. The wild naphtha product from the stripper overhead is combined with the

P a g e | 44

wild naphtha from the existing DHDS unit, and the total naphtha feed is stabilized and H2S
stripped in the stabilizer.
The stabilizer is reboiled with MP stream on temperature control. Stabilized naphtha product
is pumped on flow control reset by the stabilizer bottoms level control to the battery limits.
Naphtha product is cooled in the stabilizer feed/bottoms exchanger and a trim cooler with
cooling water before routing to storage. The stabilizer overhead vapor is condensed with
cooling water in a condenser. Off-gas product from the stabilizer reflux drum containing
H2S, butanes and lighter components, is sent for amine scrubbing to the LP amine absorber
on pressure control. The specified operating pressure for the stabilizer enables maximum
recovery of butanes in the off-gas product. The entire liquid product from the stabilizer reflux
drum is returned to the stabilizer as a reflux stream on flow control. The stabilizer reflux
drum level is controlled by resetting the reflux flow to the stabilizer.
Facilities are provided for intermittent wash water injection if required upstream of the
condenser, 301-E-12, to wash out any ammonium salt deposits. There are two amine
scrubbers, namely, HP Amine Absorber, and LP Amine Absorber. Lean amine is supplied to
the unit in two separate streams, to take advantage of the lean amine supply pressure when
routing to the LP Amine Absorber. Lean amine for the LP Absorber is boosted to the required
pressure with the LP Lean Amine Pumps, 301-P-08 A/B. The lean amine supply for the HP
Absorber is collected separately in a surge drum, 301-V-12, and then pumped to the HP
Absorber on flow control. The amine surge drum level is controlled by varying the lean
amine feed flow rate. The surge drum pressure is controlled using a split range controller with
N2 blanketing. Individual steam heaters are specified on the lean amine supply to both the LP
and the HP absorbers, for heating up the lean amine to a temperature few degrees hotter than
the feed gas, to avoid any hydrocarbon condensation and subsequent foaming of the
The HP Amine Absorber was already discussed in the Recycle Gas section. The LP Amine
Absorber, 301-C-03, scrubs the sour off gas mixture from the Diesel Stripper, the Stabilizer,
and the MP Separator. The absorber operating pressure is selected high enough to obtain
sufficient H2S scrubbing with a lean amine H2S loading as high as 0.02 mole per mole. The
sour off-gas is routed to the LP Absorber through the K.O. Drum, 301-V-10. The sweet offgas
product from the LP Amine Absorber is leaving the unit on pressure control to fuel gas.
The rich amine from the HP Amine Absorber is let down to the LP Absorber for flashing off
the dissolved H2 and light ends. The total rich amine leaves the LP Absorber bottom on level
control to the battery limits.
Facilities are provided in the flow scheme for insitu regeneration of the reactor catalyst per
the client request. The reactor circuit equipment as designed is used for this intermittent
procedure, except for the additional fresh caustic storage facility.
The catalyst regeneration is performed at a sufficiently high reactor operating pressure within
the mechanical design limits of the reactor circuit, specifically the reactor. The catalyst is
regenerated by circulating nitrogen containing a small amount of oxygen (up to 1 vol%)
through the reactor. The make-up nitrogen required for the initial system fill-up, and the
subsequent plant air make-up required during the regeneration is supplied by the make-up H2
compressor. The make-up H2 compressor is utilized for boosting the plant air and nitrogen
pressure to the recycle hydrogen compressor. The recycle compressor suction pressure is
controlled during regeneration using a separate pressure control valve that had been specified
only for the regeneration step. At the desired N2 circulation rate, if the recycle hydrogen

P a g e | 45

compressor discharge pressure is much higher than the maximum allowable reactor pressure,
the excess pressure is dropped across a hand control valve that has been specified in the
regeneration circuit at the inlet to the Feed/Effluent Heat Exchanger.
The regeneration gas is preheated against the reactor effluent in the exchanger shells. The
remaining shells are not used during the regeneration procedure to avoid excessive cooling of
the effluent stream that could lead to salt deposit in the exchangers. A portion of the gas is by
passed around the Feed/Effluent Exchanger to control the furnace inlet temperature, and also
to avoid excessive cooling of the effluent stream. The same bypass is also used during the
cooling phase of the regeneration procedure. The required reactor inlet temperature is reached
in the hydrotreater reactor feed heater. At the reactor outlet, the effluent is neutralized by
injection of anhydrous ammonia to neutralize traces of SO3 formed in the reactor. Then it is
cooled down in feed/effluent exchanger, and the reactor effluent air cooler. A caustic soda
solution is injected at the outlet of the reactor effluent air cooler, and a static mixer is
provided to obtain good contacting between the acid gases and caustic.
The caustic soda is supplied as an 8 wt. % solution, utilizing one of the Wash Water Pumps.
The spare wash water pump could be utilized for washing any salt deposits during
regeneration by injecting wash water simultaneously to the Effluent Air Cooler Inlet. The
spent caustic from the Separator Drum is routed to the battery limits for treatment.
Reaction section and feed preheat section offer great hazard due to presence of large quantity
of Hydrogen at high temperature and pressure. Failure of flange leak result in jet flame.
Stabilizer reflux drum, handle large inventory of highly volatile compounds, thus contribute
to hazard value of the plant. This unit has source of ignition due to the presence of heater
which may ignite passing through hydrocarbon flammable mixture.

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Hydro cracking is an extremely versatile catalytic process in which feed stock ranging from
naphtha to vacuum residue can be processed in presence of h2 and catalyst to produce almost
any desired products lighter than the feed. Thus if the feed is naphtha it can be converted into
LPG and if the feed is vacuum gas oil, it can produce LPG, naphtha, ATF, diesel and FCCU
feed in varying proportions as per design.
Primary function of hydrocracking unit is to reduce sulphur emission and maximize middle
distillate production. Feed to the unit consists of vacuum gas oil (VGO) from atmospheric
distillation unit (AVU) 70% high sulphur and 30% low sulphur.
Primary products:

FCC feed
Hydrocracking is an extremely versatile catalytic process in which feedstock ranging from
Naphtha to Vacuum Residue can be processed in presence of Hydrogen and catalyst to
produce almost any desired products lighter than the feed. Thus if the feed is Naphtha, it can
be converted into LPG and if feed is Vacuum Gas Oil as in Mathura Refinery, it can produce
LPG, Naphtha, ATF, Diesel and FCCU feed in varying proportions as per design
requirement. Residue up gradation into middle distillates and light distillates is currently
being done in the Indian Refineries primarily by employing FCC process, delayed Cocking
process & Visbreaking. The quality of products obtained from FCC, delayed Cocker &
Visbreaker are relatively poor in quality with respect to stability, & sulphur and have to be
blended with other straight run products to be able to market them. In view of these problems
hydrocracking process is gaining more and more popularity for upgrading residues into
higher value products since the products are stable & contain very low percentage of sulphur.
Make up hydrogen section:
This section supplies pure H2 for the hydrocracking reactions & making up the lost hydrogen
in the reactor from the hydrogen generation unit & membrane separation unit. The pump used
in this section in a three stage centrifugal compressor. Pump takes suction at a pressure of 20
kg/cm2 discharges at a pressure of 198 kg/cm2.There are three pumps of such kind out of
which two are in line.
This section also consists of the recycle gas compressor which is a centrifugal compressor
operating on steam turbine. It sucks the recycle gas at the system pressure & discharges at a
pressure of around 190 kg/cm2.The two streams combine before mixing with the feed & help

P a g e | 47

in maintaining the high pressure in the reactor.
Feed supply:
Feed is supplied by the feed booster pumps located in the off-site area taking suction from the
storage tanks. Feed is passed through a series of heat exchangers exchanging heat with the
product streams. The hot feed passes through the feed filter which retains any foreign
particles in the feed & gets collected in the feed surge drum. The feed booster pump located
in the plant takes suction from the surge drum & discharges at a pressure of 235 kg/cm2.Then
the feed passes through the preheat exchangers exchanging heat with the reactor effluent
getting heated up to 347 oC. The combined stream from the compressor house joins the feed
at this point. The combined feed goes into the reactor furnace getting heated up to 365 oC.
Then the feed enters the reactor.
Reactor section:
There are two reactors operating in series. The hydro treating & hydrocracking reactions take
place in the reactors under high pressure of 185 kg/cm2 & high temperature of 365-441 oC. A
high hydrogen partial pressure is required in the reactor to promote the reactions & prevent
the coking of the catalyst. The first reactor consists of three beds of catalyst & the second
rector consists of two beds of catalyst. Between all the catalyst beds & at the inlet of the
second reactor quench recycle gas is supplied to reduce the temperature rise across the bed
since all the reactions are exothermic. In the reactor nitrogen & sulfur are converted to NH3

& H2S.The higher hydrocarbons are broken into small chain hydrocarbons to increase the
productivity of the middle distillates.
Hot high pressure separator:
After the effluent stream cooled, it sent to the HHPS (34 kg/cm2). In this separator the reactor
products are separated into gases (mainly hydrogen,H2S & NH3) & hydrocarbon. The
effluent inlet temperature should not be more than 210 0C.The gases from the separator pass
through the exchangers & then air coolers. Before entering the air cooler water is mixed so
that the ammonia gets dissolved in it. Then it goes into the cold high pressure separator.The
bottom product goes into another vessel.
Cold high pressure separator:
In the cold high pressure separator (34 kg/cm2) the effluent gets separated into three layers,
gas (mainly H2 & H2S), hydrocarbon layer & the sour water. The gases are sent to the amine
absorber to absorb the H2S.The gases coming from the absorber is mainly hydrogen is sent to
the membrane unit for purification. Sour water is drained from the bottom & hydrocarbon is
sent with the other hydrocarbon separated earlier.
The hydrocarbon is sent via exchangers to the fractionator furnace where the temperature is
raised to 350 oC. After this the feed is sent to the fractionating tower having 52 trays.
Medium pressure stripping is sent from the bottom of the fractionator. The overhead product
in LPG & light naphtha is sent to the gas recovery section. The next side cut is heavy naphtha
is sent to the naphtha stripper. The temperature stripper bottom is maintained using the
reboiler. The bottom of the stripper is sent to storage tanks & top product is sent for reflux.
The next side cut is kerosene/ATF is sent to the stripper. The temperature of the stripper
bottom is maintained using the reboiler. The bottom product of the stripper is sent to the
storage tanks & top product is sent to the reflux in the fractionator. The next side cut is high
speed diesel which is sent to the stripper. The stripper bottom temperature is maintained
using steam. The stripper bottom is sent to the storage tanks & top is refluxed. All the

P a g e | 48

reboilers are heated using hot diesel. The fractionator bottom is sent as FCC feed.
Light end recovery section:
Light end gases from the fractionator are sent to the deethanizer, where the gases are removed
& sent to the amine absorber. The bottom of the deethanizer is sent to the debutanizer, for the
recovery of LPG.LPG is taken out as the top product sent to the caustic removal section to get
pure LPG. The stabilized naphtha is taken as the bottom product & sent to the storage tanks.
Product routing:
Hydrocracker unit produces fuel gases, LPG, Naphtha, ATF/SK, HSD and unconverted oil as
products. Routing of these products is as follows.
Fuel gas from KOD of H2S absorber is routed to fuel gas system in MEROX unit.
Light naphtha is routed to naphtha storage.
It will be normally blended with HSD at HCU. However it can be routed to Naphtha
along with light naphtha.
4.) LPG
LPG product in the HCU can be routed to Horton sphere in the LPG area of existing
5.) SK/ATF
SK/ATF from HCU goes to existing SK/ATF tanks. Hock ups are provided to route it
either ATF run down tanks or to SK rundown tanks. It can also be blended to diesel at
6.) HSD
HSD from FCCU goes to existing diesel fuel through a 6” diameter line.
Unconverted oil (hot FCC feed) can be routed directly to FCCU by passing air cooler
or can be routed to FCCU feed tank after air cooler feed.
All the product lines (except LPG and Gas) are connected to a 8” dia slope line at the
battery limit which is going to slope tank.

P a g e | 49


A furnace is essentially a thermal enclosure and is employed to process raw materials at high
temperatures both in solid state and liquid state. Several industries like iron and steel making,
nonferrous metals production, glass making, manufacturing, ceramic processing, calcination in
cement production, refineries etc. employ furnace.
The principle objectives are:
a) to utilize heat efficiently so that losses are minimum.
b) to handle the different phases (solid, liquid or gaseous) moving at different velocities for
different times and temperatures such that erosion and corrosion of the refractory are minimum.
Burners, Heat exchangers, Draft inducer and venting, Controls and safety devices, Air

Gas furnace have the basic components: A gas burner where fuel is burned, an ignition device to
start the fire, one or more heat exchangers where the heat from combustion gases is transferred to
the house air, a circulation blower to circulate air to and from the house, and a small second
induction blower to draw flue gases through the furnace. As the hot exhaust gases from the gas
burner pass through the heat exchanger, they are cooled by the circulating house air which
carries the heat throughout the unit. Gas furnace technology has progressed during the past
decade and efficiencies have jumped from about 65% to as high as 95%.
Oil furnaces are similar to gas furnaces and share many of the same high efficiency features. The
most important difference is in the firing apparatus. Oil furnaces have power burners that
atomize the fuel oil, mix it with combustion air, and force it through the combustion chamber.

P a g e | 50

The Auto Switch Dual Fuel Burners embody the best features of both Gas and Oil Burners. The
Burner is supplied with a dual gas and oil combustion head giving the burner the capability of
firing on either fuel. The burner management system to change from one fuel to another is
operated by a switch.
An industrial furnace or direct fired heater is equipment used to provide heat or can serve as
reactor which provides heats of reaction. Furnace designs vary as to its function, heating duty,
type of fuel and method of introducing combustion air; however, most process furnaces have
some common features.
Fuel flows into the burner and is burnt with air provided from an air blower. There can be more
than one burner in a particular furnace which can be arranged in cells which heat a particular set
of tubes. Burner can also be floor mounted, wall mounted or roof mounted depending on design.
The flame heat up the tubes, which in turn heat the fluid inside in the first part of the furnace
known as the radiant section or firebox. In this chamber where combustion takes place, the heat
is transferred by radiation to tubes around the fire in the chamber. The heating fluid passes
through the tubes and is thus heated to the desired temperature. The gases from the combustion
are known as flue gases. After the flue gas leave the firebox, most furnace designs include a
convection section where more heat is recovered before venting to the atmosphere through the
flue gas stack.
Fuel flows into the burners and air flows from air blowers for burning. There are tubes in the
furnace. Flames heat up the tubes and thus heats the feed flowing through the tubes.
There are two sections in the furnaceConvection section
Radiation Section
This is first part of the furnace. This is also called firebox. Combustion takes place in this
section. Heat is transferred mainly by radiation gases from combustion of flue gases. The
radiation section is where the tubes receive almost all its heat by radiation from the flame. In the
vertical cylindrical furnace the tubes are vertical. Tubes can be vertical or horizontal, placed
along the refractory wall, in the middle etc. or arranged in cells. Studs are used to hold the
insulation together and on the wall of furnace. The tubes are distant away from the insulation so
radiation can be reflected to the back of the tubes to maintain a uniform tube wall temperature.
Tube guides at the top, middle and bottom hold the tubes in place.

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Convection Section
Convection Section is next to radiation section where it is cooler to recover additional heat. Heat
transfer takes place by convection here. And tubes are finned to increase heat transfer. The tubes
(without fins) located at the top of the radiation section are known as shield section, so named
because they are still exposed to plenty of radiation from the firebox and they also act to shield
the convection section tubes, which are normally of less resistant material from the high
temperatures in the firebox.. The area of the radiant section just before flue gas enters the shield
section and into the convection section called bridge zone. Crossover is the term used to describe
the tube that connects from the convection section outlet to the radiant section inlet. The
crossover piping is normally located outside so that the temperature can be monitored and the
efficiency of the convection section can be calculated. The slight glass at the top allows
personnel to see the flame shape and pattern from above and visually inspect if flame
impingement is occurring. Flame impingement happens when the flame touches the tubes and
causes isolated spots of very high temperature.
The burner in the vertical, cylindrical furnace as above is located in the floor and fires upward.
Some features have side fired burners. The burner tile is made of high temperature refractory and
is where the flame is contained. Air registers located below the burner and at the outlet of the air
blower are devices with movable flaps or vanes that control the shape and pattern of the flame,
whether it spreads out or even swirls around. Flames should not spread out too much, as this will
cause flame impingement. Air register is classified as primary, secondary and if applicable
tertiary, depending on when their air is introduced. The Primary air register supplies primary air,
which is the first to be introduced in the burner. Secondary air is added to supplement primary
air. Burners may include a premix to mix the air and fuel for better combustion before
introducing into the burner. Some burners even use steam as premix to preheat the air and create
better mixing of the fuel and heated air. The floor of furnace is mostly made of a different
material from that of the wall, typically hard cast able refractory to allow technicians to walk on
its floor during maintenance.
A furnace can be lit by a small pilot flame or in some older models, by hand. Most pilot flames
now days are lit by an ignition transformer (much like a car’s spark plugs). The pilot flame in
turn lights up the main flame. The pilot flame uses natural gas while the main flame can use both
diesel and natural gas. When using liquid fuels, an atomizer is used; otherwise, the liquid fuel
will simply pour onto the furnace and become hazard. Using a pilot flame for lighting the
furnace increases safety and ease compared to using a manual ignition method (like a match).

P a g e | 52



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Excess Oxygen Calculations:

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Purge gas composition and moles of O2 consumed:

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Thus the efficiency of the reformer as per our calculations from the excel
sheet comes out to be 69.54%.

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Classification of heat exchangers
Transfer of heat from one fluid to another is an important operation for most of the chemical
industries. The most common application of heat transfer is in designing of heat transfer
equipment for exchanging heat from one fluid to another fluid. Such devices for efficient transfer
of heat are generally called Heat Exchanger. Heat exchangers are normally classified depending
on the transfer process occurring in them.
Amongst of all type of exchangers, shell and tube exchangers are most commonly used heat
exchange equipment. The common types of shell and tube exchangers are:
Fixed tube-sheet exchanger (non-removable tube bundle): The simplest and cheapest type of
shell and tube exchanger is with fixed tube sheet design. In this type of exchangers the
tube sheet is welded to the shell and no relative movement between the shell and tube bundle is
Removable tube bundle: Tube bundle may be removed for ease of cleaning and replacement.
Removable tube bundle exchangers further can be categorized in floating- head and U-tube
Floating-head exchanger: It consists of a stationery tube sheet which is clamped with the
shell flange. At the opposite end of the bundle, the tubes may expand into a freely riding
floating-head or floating tube sheet. A floating head cover is bolted to the tube sheet and the
entire bundle can be removed for cleaning and inspection of the interior.
U-tube exchanger: This type of exchangers consists of tubes which are bent in the form of a “U”
This means that it will omit some tubes at the centre of the tube bundle depending on the tube
arrangement. The tubes can expand freely towards the „U‟ bend end.

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U Tube HE
Given data:
Hot fluid inlet temperature (T1)= 228°C
Hot fluid outlet temperature (T2) = 109.2°C
Cold fluid inlet temperature (t1) = 66.2°C
Cold fluid outlet temperature (t2) = 189.6°C
Fouling factor of hot fluid (Rdg) = 0.0005 (for HC+H2S)
Fouling factor of cold fluid (Rdk) = 0.0005 (for HC)
Pinlet (for hot fluid) = 12.730 Kgf/cm2
Pinlet (for cold fluid) = 11.830 Kgf/cm2
Δpmax (for hot fluid) = 0.900 Kgf/cm2
Δpmax (for cold fluid) = 1.800 Kgf/cm2
Mass flow rate of cold fluid (mk) = 226.028 Kg/hr

Fluid properties

μhcs= 0.8cp
μhc = 0.5 cp
ρhcs=717.85 kg.m-3
ρhc=740.05 kg.m-3

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Thermal conductivity:
Specific heat capacity:
Chcs = 0.562
Chc = 0.6
Energy balance
Assume no heat loss to the surrounding.

=15772.90 Kcal/hr
Calculation of heat transfer area and tube numbers:
Iteration #1:
The first iteration is started assuming 1 shell pass and 2 tube pass shell and tube
exchanger with following dimensions and considerations.

HC+H2S is placed in tube side because it has the higher
fouling tendency
The log mean temperature correction factor (FT) for 1-2 shell and tube exchanger:

FT= 0.88

LMTD= 40.65 0C

P a g e | 60

Determining the heat transfer area (‘A’):
The value of overall heat transfer coefficient (Uo,assm) of 300 W/m2 0C is
assumed to initiate the design calculation for the kerosene and gasoline heat

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References for Heat Exchanger design:
[1]. Indian Standard (IS: 4503-1967): Specification for Shell and Tube Type Heat
Exchangers, BIS 2007, New Delhi.
[2]. R. K. Sinnott, Coulson & Richardson‟s Chemical Engineering: Chemical
Engineering Design (volume 6), Butterworth-Heinemann, 3rd ed. 1999.
[3]. D. Q. Kern, Process Heat Transfer, McGraw-Hill Book Company, Int. ed.
[4] Dutta B.K. „Heat Transfer-Principles and Applications‟, PHI Pvt. Ltd., New
Delhi, 1st ed. 2006.

The report includes process description of all units (AVU, FCCU, VBU, MEROX treatment,
DHDT, OHCU, HGU). A detailed analysis of the DHDT and HGU1 unit is enclosed which
includes finding the furnace efficiency in OHGU and design of shell and tube HE in DHDT
unit. These operational parameters were found by applying mass balance and heat balance
across the furnace section. Furnace efficiency of duplex furnace which is the largest 216 pair of
burner furnace of the plant in HGU unit was calculated and the result came out to be 69.54 %.
Efficiency can be increased by decreasing the excess air supply and decreasing the stack
temperature i.e flue gas outlet temperature.

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