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VOCATIONAL TRAINING REPORT
GUJARAT REFINERY
Training period: 9th June to 8th JULY 2018
Submitted by
MOHAMMEDSAHIL.Z. KADIWALA-16BE01008
CHEMICAL ENGINEERING DEPARTMENT
FACULTY OF ENGINEERING AND TECHNOLOGY
GSFC UNIVERSITY
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PREFACE
Though it has been said that best friend a man can ever get is a book but we at
this juncture realize that only books cannot give all the information a person
seeks. When any student is unable to understand a particular topic, he is advised
to imagine the whole matter and then try to understand it. Normally, this method
succeeds.
But in engineering stream considering the study of wide range of process and
equipments involved in it, it is hard to understand the unit operations and
processes just through books or even with imagination. Unless one happens to
see the process, equipments he is like a soldier who knows to fire the gun but is
yet to face a war.
Industrial training is one of the most vital parts of a syllabus of chemical
engineering, which not only teaches one the industrial unit operations,
equipments and other technical aspects, but also teaches discipline, interaction
with various people irrespective of their posts, the importance of teamwork, etc.
This report contains a brief introduction to GUJARAT REFINERY and
knowledge gathered about various units in refinery during the training.
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ACKNOWLEDGEMENT
I would like to express my gratitude to all those who gave me the possibility to complete this training. I want to thank the department of training and management of Gujarat refinery for giving me permission to commence this training. I have furthermore to thank the officers of production who giving me such knowledge of about the plant and production process. It is really great opportunity for me by which I had learned here many more of refinery. I am deeply indebted to Gujarat Refinery who given such opportunity to students by which they complete their vocational training which is the parts of the course. Without any moral support and help I was not able to visit the plant and learn about the refinery. I would like to give my special thanks to the person who supported me through the training at the day of starting to the end of the training.
My special thanks to –
VENKATESH SIR
MR. PIYUSH DIWAKAR
ABHISHEK OZA
MANISH SAGAR
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INDEX
SR.NO TOPIC PG.NO 1.0 IOCL (INDIAN OIL CORPORATION
LIMITED) OVERVIEW 05
2.0 GUJARAT REFINARY OVERVIEW 09
3.0 DCU (DELAYED COKER UNIT) 14 – 29
3.1 INTRODUCTION 14
3.2 PROCESS CHEMISTRY 15
3.3 PFD (PROCESS FLOW DIAGRAM) 16 – 17
3.4 PROCESS DESCRIPTION 18 – 23
3.5 EQUIPMENT LIST 24 – 28
3.6 MASS BALANCE 29
4.0 VGO-HDT (VACCUM GASOLINE OIL –
HYDRO TREATING) 30 – 45
4.1 INTRODUCTION 30
4.2 PROCESS CHEMISTRY 30 – 32
4.3 PFD (PROCESS FLOW DIAGRAM) 33 – 34
4.4 PROCESS DESCRIPTION 35 – 37
4.5 EQUIPMENT LIST 38 – 44
4.6 MASS BALANCE 45
5.0 HAZARDOUS 46 - 50
6.0 CONCLUSION 51
7.0 REFERANCES 52
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➢ INTRODUCTION ABOUT IOCL (INDIAN OIL
CORPORATION LIMITED): -
Indian Oil, the largest commercial enterprise of India (by sales turnover), is
India’s sole representative in Fortune's Prestigious listing of the world's 500
largest corporations, ranked 161 for the year 2016.
It is also the 18th largest petroleum company in the world. Indian Oil has a sales
turnover of Rs. 3,99,601 crore and profits of Rs. 10,399 crores. Indian Oil has
been adjudged first in petroleum trading among the 15 national oil companies in
the Asia-Pacific region.
As the premier National Oil Company, Indian Oil’s endeavour is to serve the
national economy and the people of India and fulfil its vision of becoming “An
Integrated,Diversified And Transnational Energy Major.”
➢ HISTORY OF IOCL (INDIAN OIL CORPORATION
LIMITED): -
Beginning in 1959 as Indian Oil Company Ltd, Indian Oil Corporation Ltd. Was
formed in 1964 with the merger of Indian Refineries Ltd. (Est. 1958). As India's
flagship national oil company, Indian Oil accounts for 56% petroleum products
market share,42% national refining capacity and 67% downstream pipeline
throughput capacity.
IOCL touches every Indian’s heart by keeping the vital oil supply line
operating relentlessly in every nook and corner of India.
It has the backing of over 33% of the country’s refining capacity as on 1St April
2002 and 6523 km of crude/product pipelines across the length and breadth of
the country.
IOCL’s vast distribution network of over 20000 sales points ensures that essential
petroleum products reach the customer “at the right place and at the right Time”.
Indian Oil controls 10 of India's 18 refineries – at Digboi, Guwahati, Barauni,
Koyali, Haldia, Mathura, Panipat, Chennai, Narimanam and Bongaigaon. - with
a current combined rated capacity of 49.30 million metric tons per annum
(MMTPA) or 990 thousand barrels per day (bpd).
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➢ VISION: -
Indian Oil’s ‘Vision with Values’ encompasses the Corporation’s new
aspirations – to broaden its horizons, to expand across new vistas, and to infuse
new-age dynamism among its employees.
Adopted in the company’s Golden Jubilee year (2009), as a ‘shared vision’ of
IndianOilPeople and other stakeholders, it is a matrix of six cornerstones that
would together facilitate the Corporation’s endeavours to be ‘The Energy of
India’ and to become ‘A globally admired company.’
More importantly, the Vision is infused with the core values of Care,
Innovation, Passion and Trust, which embody the collective conscience of the
company and its people, and have helped it to grow and achieve new heights of
success year after year.
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➢ HEALTH, SEAFTY AND ENVIROMENT: -
Indian Oil accords topmost priority to conducting its business with a strong
environment conscience, ensuring sustainable development, safe workplaces and
enrichment of the quality of life of its employees, customers and community at
large. All refineries are certified to ISO:14064 standards for sustainable
development as well as for the Occupational Health & Safety Management
System (OHSMS/OHSAS018001), besides having fully equipped occupational
health centres. Compliance with safety systems, procedures and environment
laws I monitored at the unit, division and corporate levels.
As India’s leading oil & gas corporate, Indian Oil remains steadfast in its
commitment to excellence in Safety, Health and Environmental (S, H&E)
performance. This publication showcases how Indian Oil People are relentlessly
pursuing multiple commitments – at the operations, social and environmental
levels – to fully realize Indian Oil’s potential as the prime mover of a resurgent
India
1. Safety Management at Indian Oil: -
Indian Oil is committed to safety and demonstrated leadership in the field of
Safety, Health and Environment. The Safety, Health & Environment (S, H&E)
policy of Indian Oil demonstrates this commitment. Indian Oil has a well-defined
Safety, Health & Environment (S, H&E) Policy that gives direction for various
safety, occupational health and environment protection related activities. The
safety & fire protection measures at Indian Oil encompass a well-sensitised
Management, focus on imparting regular training and a culture of safety
throughout the Company.
2. Occupational Health At Indian Oil: -
At Indian Oil, a focus on employee health is a priority. All programmes are
designed with an eye to ensure to improve the health status, well-being and
productivity of employees by creating a workplace environment that actively and
consistently reinforces, promotes and supports healthy behaviours.
All refineries are certified to Occupational Health & Safety Management System
(OHSMS/OHSAS018001), besides having fully equipped occupational health
centres. Doctors and paramedics are specially trained to monitor the health of
employees working in hazardous areas. The healthcare personnel regularly
interact with shop floor managers and staff.
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Various media of communication such as house journals, posters, films, etc. are
extensively used for creating awareness.
In addition, personnel working in hazardous areas are subjected to periodical
medical examination to study the effect of hazards. Theme-based preventive
health programmes are regularly being organized to protect the health of the
employees.
3. Environment Management at Indian Oil: -
In the course of refinery operations, waste water, flue gases and fugitive
emissions and solid wastes are generated. Refineries are also significant
consumers of scarce resources like water and energy. Thus, pollution control and
resource conservation activities are a priority area for environment management
at Indian Oil. Effective treatment of wastewater and recycling, energy
conservation and pollution abatement are examples of integrated activities that
result in both pollution control and resource conservation.
Our refineries continuously strive to –
• Minimize adverse environmental impact from refinery activities, products
and services by using processes, practices, materials that avoid, reduce or
control pollution;
• Conserve scarce natural resources their consumption is continually
optimized
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➢ GUJARAT REFINERY: -
The Gujarat Refinery is an oil refinery located at Koyali (Near Vadodara) in
Gujarat, Western India.
Gujarat Refinery is designed to processes indigenous as well as imported crude
oil. On an average it processes approximately three lakhs eight thousand metric
tonnes crude per day. Out of the crude slot it receives, refinery processes
around 45% imported crude.
Gujarat refinery’s manufacturing and storage facilities consist of 26 major
process units, 28 product lines and crude storage tanks with capacity ranging
from 300 to 65,000 KLs.
South Gujarat Crude: 2.3MMTPA; supply from ONGC South Gujarat pipeline.
North Gujarat: 3.5MMTPA; supply from ONGC North Gujarat pipeline.
Imported low / high
Sulphur crude & Bombay high: 6.2 MMTPA Supply from Salaya - Viramgam -
Koyali pipeline.
SALIENT FEATURE OF REFINERY:
• First Riser Cracker FCCU in the country.
• First Hydro cracker in the country.
• First Diesel Hydro De-sulphurization Unit.
• First Spent Caustic Treatment Plant in refineries.
• First Automated Rail Loading Gantry.
• First LPG Mounded Bullets in Indian Refineries.
• Operates Southeast Asia’s biggest Centralized Effluent Treatment Plant
(CETP)
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➢ HISTORY: -
It is the Second largest refinery owned by Indian Oil Corporation after
Panipat Refinery. The refinery is currently under projected expansion to 18
MMTPA History Following the conclusion of the Indo-Soviet Treaty of
Friendship and Cooperation in February 1961, a site for the establishment of
a 2 million metric ton per annum (MMTPA) oil refinery was selected on 17
April 1961.Soviet and Indian engineers signed a contract in October 1961 for
the preparation of the project. Prime Minister Jawaharlal Nehru laid the
foundation stone of the refinery on 10 May 1963.
The refinery was commissioned with Soviet assistance at a cost of Rs.26 crores
began production in October 1965. The first crude distillation unit with a capacity
of 1 MMTPA was commissioned for trial production on 11 October 1965 and
achieved its rated capacity on 6 December 1965. Throughput reached 20%
beyond its designed capacity in January 1966.
President Sarvepalli Radhakrishnan dedicated the refinery to the nation with the
commissioning of second crude distillation unit and catalytic reforming unit on
18 October 1966.The third 1 MMTPA distillation unit was commissioned in
September 1967 to process Ankleshwar and North Gujarat crudes. In December
1968, Udex plant was commissioned for production of benzene and toluene using
feedstock from CRU. By 1974-75 with in-house modifications, the capacity of
the refinery increased by 40% to a level of 4.2 MMTPA.
To process imported crude the refinery was expanded during 1978-79 by adding
another 3 MMTPA crude distillation unit along with downstream processing
units including vacuum distillation, visbreaker and bitumen blowing units. By
1980-81 this unit started processing Bombay High crude in addition to imported.
To recover products from the residue, secondary processing facilities consisting
of fluidized catalytic cracking unit of 1 MMTPA capacity along with a feed
preparation unit of 1 MMTPA capacities, were commissioned in December
1982.
The refinery set up pilot distillation facilities for the production of n-Heptanes
and light aluminium rolling oils. To enable absorption of increased indigenous
crudes the refinery's capacity was further increased to 9.5 MMTPA. In 1993-
1994, Gujarat commissioned the country's first hydrocracker unit of 1.2 MMTPA
for conversion of heavier ends of crude oil to high value superior products.
India's first diesel hydrodesulphurization unit to reduce sulphur content in diesel
was commissioned in June 1999. A methyl tertiary butyl ether unit was
commissioned in September 1999 to eliminate lead from motor fuels. The facility
conceptualized and commissioned South Asia's largest centralized effluent
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treatment plant by dismantling the four old ETP's [expand acronym] in June
1999.
By September 1999 with the commissioning of an atmospheric distillation unit,
Gujarat Refinery further augmented its capacity to 13.7 MMTPA making it the
largest public sector undertaking refinery of the country.
A project for production of linear alkyl benzene from kerosene streams was
implemented in August 2004. It is the largest grassroots single train Kerosene to-
LAB unit in the world, with an installed capacity of 1.2 MMTPA. To meet future
fuel quality requirements, MS [expand acronym] quality improvement facilities
were commissioned in 2006.
The Residue Up gradation Project undertaken by the Gujarat Refinery was
completed by 2011 which increased the high sulphur processing capacity of
Gujarat refinery improved the distillate yield as well produce BS III & IV quality
of MS and HSD.
The Residue up gradation project came in two parts namely, the south block
which consisted of HGU-III, SRU-III, DHDT and ISOM units and the north
block consisted of VGO-HDT and DCU units. To support the new units a new
Co-Generation Plant (CGP) and Heat Recovery Steam Generation (HRSG)
were also commissioned.
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➢ IMPORTANT UNITS OFGUJARAT REFINERY: -
1) Gujarat Refinery Unit-1 (GR-1) • Atmospheric Distillation Unit-1 (AU-1)
• Atmospheric Distillation Unit-2 (AU-2)
• Atmospheric Distillation Unit-5 (AU-5)
• Catalytic Reforming Unit (CRU)
2) Gujarat Refinery Unit-2 (GR-2) • Atmospheric Distillation Unit-3 (AU-3)
• Universal Product Dow Chemical Extraction (UDEX)
• Food Grade Hexane (FGH) • Methyl Tertiary Butyl Ether (MTBE)
Butene-1
Pilot Distillation Fraction (PDF)
3) Gujarat Refinery Expansion Unit (GRE) • Atmospheric Distillation Unit-4 (AU-4)
• Vacuum Distillation Unit (VDU)
• Delayed Coker Unit (DCU)
• Bitumen Blowing Unit
4) Gujarat Refinery Secondary Process Functioning (GRSPF) • Feed Preparation Unit-1 (FPU-1)
• Fluidized Catalytic Cracker Unit (FCCU)
5) Gujarat Hydrocracker Unit (GHC) • Feed Preparation Unit-2 (FPU-2)
• Hydrogen Generation Unit-1 (HGU-1)
• Hydrocracking Unit (HCU)
• Hydrogen Generation Unit-2 (HGU-2)
• Diesel Hydro De-sulphurization Unit (DHDS)
• Sulphur Recovery Unit (SRU) • Nitrogen Unit
6) Power Generation Effluent Treatment • Cogeneration Plant (CGP)
• Thermal Power Station (TPS)
• Combined Effluent Treatment Plant (CETP)
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➢ Product and uses: -
PRODUCT USES
Fuel Gas Fuel for Industrial Furnaces
LPG Cooking Gas
Naphtha Raw material for Petrochemicals
Motor spirit Petrol for vehicles
Aviation turbine fuel (ATF) Fuel for jet aircrafts
Superior kerosene Illuminate domestic product
High speed diesel (HSD) Diesel for trucks, buses ships, etc.
Light diesel oil (LDO) Small engines attached to irrigation
pumps
Fuel oil Industrial furnaces/boilers
Bitumen Road surfacing
Benzene Raw material for Petrochemicals
Toluene Raw material for Petrochemicals
n-Heptane Used as solvent
ARO Used in aluminium rolling industries
Linear Alkyl Benzene (LAB) Detergent manufacturers
Butene Copolymer for producing
polyethylene and
polypropylene
Methyl Tertiary Butyl Ether (MTBE)
Blending in gasoline for
increasing octane number and
oxygen content
Food Grade Hexane (FGH) Solvent for oil seed extraction.
Glues/Adhesives for footwear.
Polymerization reaction in
industries like pharmaceuticals
and printing ink.
Sulphur Sulphuric acid and tyre manufacture
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➢ DELAYED COKER UNIT: -
Purpose of unit: To recover light end products by thermal cracking of
vacuum residue.
Feed: Vacuum residue & Residual cyclic oil
Products:LPG, NAPHTHA, LCGO, HCGO, COKE, FUEL GAS
Capacity: 3.7MMTPA
➢ INTRODUCTION:
Delayed coking gets its name from the fact the feedstock to the Coker is heated
above the temperature of coking point in the heater. But, the feed velocity in the
heater tubes is very high (residence time is minimized) and the coking reaction is
put off to the coking drum instead of the tubes in the heater. A Unit is designed
for three feed cases. The feed is different but the rate for each will be the same,
i.e. 11,100 metric tonnes per day. The Coker can be operated in two modes.
Case Feed Type Sulphur Quantity Days
Content (MTPA) Annum
1A Vacuum Low 1,700,000 153
Residue + RCO
1B Vacuum High 2,000,000 180
Residue
2 Vacuum High 3,700,000 333
Residue + RCO
The unit is designed to maximize production of middle distillate and LPG and
minimize production of coke and naphtha. Delayed coking is a thermal cracking
process, upgrading heavy petroleum residues into lighter gaseous and liquid
products and solid coke. The reaction is endothermic and requires a lot of heat
energy. The Properties of the products formed by this process are highly
unsaturated and hence need further treatment before they are sent to market.
These reactions are carefully controlled to minimize coke build up in heater tubes.
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The solid products (green coke) is retained in the coke drums. Coke drum effluent
vapour is quench to arrest further cracking reactions and then fractioned into
various distillates and light end products.
➢ Chemical Reaction of Carbonization: -
There are three types of chemical reaction for this process:
A) Dehydrogenation: - It involves the loss of hydrogen atom from aromatic
hydrogen and leads to the formation of an aromatic- free radical intermediate.
B) Rearrangement: - These are the most complicated reaction in
carbonization. They often make it impossible to predict from the starting structure
whether a given compound will produce a well graphitizing or disordered carbon.
Thermal rearrangement usually leads to more stabilizing aromatic ring system,
which can then become building block for graphite growth.
C) Polymerization of aromatic radicals: - The polymerization
reactions are initiated in the liquid phase and lead to aromatic polymers. Unlike
conventional polymerization, which rapidly increases the molecular size. The
aromatic polymerization appears to proceeds in steps.
Non-polar radical intermediates lead to disordered aromatic polymers which truly
never polymerize. Reaction taking place are both endothermic and exothermic.
Heat is applied to initiate the cracking reaction. As polymerization proceeds in
the coke drums. The exothermic (cracking) reaction provides the heat to continue
the dehydrogenation process. Exact mechanism of coking is so complex that it is
not possible to determine all the chemical reactions occurring, however three
distinct steps do take place:
a) Partial vaporization and mild cracking (Vis-breaking) of the feed as it passes
through the furnace.
b) Cracking of the vapour as it passes through the drum.
c) Successive cracking and polymerization of the liquid trapped in the drum
until it is converted to vapour and coke.
The yield and qualities of the product are directly related to three process
variables: -Temperature, Pressure and through-put ratio (ratio of fresh feed plus
recycle)
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➢ Process Flow Diagram Of DCU
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➢ PROCESS DESCRIPTION: -
Coker feed is delivered from battery limit by feed booster pump, from the feed
surge drum to the HCGO product/Feed Exchanger and then to the HCGO Pump-
around/Feed Exchanger. After being preheated by HCGO pump-around, the feed
enters the fractionators bottom under the shed section of the tower under flow
reset by level control. Recycle from the Coker Fractionator shed section
combines with the fresh feed in the bottom of the tower. The distribution is
through two distributors rings. The large ring is used to agitate the fractionator’s
walls and near the Heater Charge Pump, suction nozzle. The second ring is used
to agitate the area near the Fines Removal Pump, and suction nozzle. The
combined fresh feed and recycle flows to the Heater Charge Pump, which is
equipped with a coke crushing impeller.
The liquid is then pumped to the Coke Heater 1 & 2 where it is rapidly heated to
the desired temperature for coke formation in the coke drums. The Coker drums
are arranged in pairs with one heater dedicated to a pair of drums. The two Coker
heater are single-fired and designed for on-spalling, steam-air decoking and
pigging. Facilities have been provided for the injection of condensate into each
heater coil from the Condensate Booster Pump, to maintain the required velocity
and delay the process. MP steam is also provided with a superheat coil for
superheating the medium pressure steam generated in the generators. LCGO and
HCGO stripping steam are provided from the superheated steam line. Heater
effluent flows into one of each pair of coke drums where, under the proper time-
temperature-pressure condition, when a drum is filled the heater effluent is
directed through a Coker Switch Valve, into the empty drum of each pair.
The flow to each coke drums is maintained for 24 hours. The “full” drum is
decoked in 24 hours. Thus, each drum goes through a 48-hours cycle. An
Antifoam Injection package, is provided to prevent foam over of the Coke Drums
to the Fractionator and to allow more accurate level readings by the nuclear level
detectors. The antifoam is dosed on the top of the Coke Drums in coking service
by the Antifoam Injection Pumps. Light Coker gas oil, LCGO is used as a carrier
for the antifoam agent and is injected downstream of the Antifoam Injection
Pump. In addition, quench oil from the Quench Oil Strainer, is sent to the Coker
Drum quench oil injection header where it combines with the slop oil and wax
tailing from the Blow down System to quench the vapours leaving the Coke
Drums in coking service.
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➢ Fines Removal Section
After coke particles are removed by the Fines Removal Strainer, the stream is
pumped by the Fines Removal Pump, to the Heater Charge Pump, suction.
➢ HCGO Section
The Heavy Coker Gas Oil (HCGO) stream is drawn from the Fractionator above
the wash section. This stream draw is split into two streams. The first stream
flows by gravity from the Coker Fractionator to the top tray of the HCGO
Stripper. The light component are stripped out with superheated steam and
returned to the Coker Fractionator. The stripped HCGO product is pumped by
the HCGO Product Pump, through the HCGO Product Filter Package, and then
through the HCGO Product/Feed Exchanger, to preheat the Coker feed. HCGO
is then either sent directly to the VGO HDT unit outside battery limits, to storage
by way of the HCGO Product Cooler, to the HCGO seal Oil Drum, or to battery
limits.
The second stream serves as HCGO Pump-around and is pumped by the HCGO
Pump-around pump. From the discharge side of this pump, three split streams are
taken. One part of the split stream passes through the Wash Oil Strainer, is used
as reflux to the Coker Fractionator. Another part of the split stream passes
through the Quench Oil Strainer, and is used to quench the vapours leaving the
coke drums in coking services.
The third part of the original stream, the HCGO Pump-around is used to preheat
fresh in the HCGO Pump-around/Feed Exchanger, generate steam in the HCGO
Pump-around/MP steam Generator, and preheat the trap-out in the Debutanizer
Lower Reboiler, before returning to the Coker Fractionator.
➢ LCGO Section
A Light Coker Gas Oil (LCGO) draw taken from the Coker Fractionator is split
into two streams. The First stream flows by gravity to the top tray of the LCGO
Stripper, where the light components are stripped with superheated steam and
returned to the Coker Fractionator. The stripped LCGO product is pumped by
LCGO pump, to the LCGO Product Filter, to heat to the boiler feed water in the
LCGO Product/BFW Exchanger, and flows through the LCGO Product Cooler,
to be cooled LCGO from the LCGO Product Cooler bypasses the LCGO Product
Trim Cooler, under temperature control to mix with the hot heavy naphtha from
the Heavy Naphtha Product Cooler.
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This combined stream is now called middle distillate and flows to DHDT outside
battery limits for further processing. The rest of the LCGO is then cooled by the
LCGO Product Trim Cooler. The main disposition of the cooled LCGO stream
is to storage after mixing with heavy naphtha from the Heavy Naphtha Product
Trim Cooler. Cooled LCGO can also be used as diluents for the Antifoam
Injection Package, or as diluent in the Sludge Tank. Cooled LCGO can also be
sent to the heavy slop oil system. The second LCGO stream is the lean sponge
oil, which is pumped by the Sponge Oil Pump, to the Lean/Rich Sponge Oil
Exchanger, located in the gas plant.
After the Lean/Rich Sponge Oil Exchanger, it is further cooled by the Lean
Sponge Oil Cooler, and Lean Sponge Oil Trim Cooler, before being fed to the
top of the Sponge Absorber. The counter-current flow of the lean sponge oil
contacts light hydrocarbon vapours and absorbs the light end. Rich sponge oil
from the Sponge Absorber is heated in the Lean/Rich Sponge Oil Exchanger and
recycled back to the Coker Fractionator overhead vapour flows to the
Fractionator Overhead Condenser, where it is partially condensed.
The first stage of the Coker Gas Compressor, anti-surge vapour combines with
the fractionator overhead before the Fractionator Overhead Condenser. Wash
water from the Fractionator Sour Water Pump, is continuously injected into the
overhead stream before the Fractionator Overhead Condenser. Partially
condensed vapours from the condenser flow to the Fractionator Overhead Drum,
where the vapours are separated from the hydrocarbon liquid and water.
Uncondensed vapour flows from the Fractionator Overhead Drum to the
Compressor Suction Drum, and then to the Coker Gas Compressor. Condensed
liquid from the overhead drum is returned to the top of the Coker Fractionator as
reflux by the Fractionator Reflux Pump. The balance of the liquid is pumped by
the Un-stabilized Naphtha Pump, to the Absorber, located in the gas plant.
➢ Sour Water System
From the overhead drum it is pumped by the Fractionator Sour Water Pump, P-
07 A/B, to the Sour Water Stripper outside battery limits. Sour water can also be
pumped to the Inter-stage Condenser Spray Nozzle, M-18, to the Absorber
Stripper Feed Condenser Spray Nozzle, M-19, and to the inlet of the Fractionator
Overhead Condenser as mentioned above to fulfil the unit requirement.
➢ Coker Blowdown System
The Coker Blowdown System of the Delayed Coking Unit is designed to
minimize air pollution during normal operation. The Coker Blowdown System
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includes the Coker Blow down Tower the Blowdown Settling Drum, the Blow
down Condenser, the Blowdown Circulating Oil Cooler, Blowdown Drum
Heater and water Seal Drum. During the coke drum steaming and quenching
operation, steam and stripped oil vapour flow to the Coker blowdown tower when
the was tailing temperature is 177°C and rising.
If the tower, the steam is cooled and the oil vapour is partially condensed by
counter-current contact with the circulating oil stream. The condensed oil is
collected in the bottom of the tower, where it is diluted as required by stream of
makeup LCGO from LCGO Product Filter. After being filtered by the blowdown
circulating oil strainer, it is pumped by the blowdown circulating oil pump. A
portion of diluted oil is recirculated through the blowdown oil cooler back to the
Coker blowdown tower.
A purge stream of excess oil is sent hot to Coker fractionator and the remainder
is circulated through the blowdown to the quench oil strainer and back to the
Coker blowdown tower. Alternately, the purge can be cooled and sent to slop.
The blowdown tower heater uses medium pressure steam to maintain liquid
temperature in the bottom of the of the Coker blowdown tower at 157°C.
Steam entrained hydrocarbon and non-condensable vent vapours blowdown the
Coker blowdown tower to the blowdown condenser where the steam and the
entrained hydrocarbons are partially condensed. The vapour-liquid mixture flows
to the blowdown settling drum where traces of oil are separated from condensate.
To reduce the required settling time in the blowdown settling drum, a de-
emulsifier injection package is provided.
The oil that settles out is pumped by the blowdown slop oil pump back to the
Coker blowdown tower or to the light slop system outside battery limits. This
light oil is, however, normally recycle back to the Coker blowdown tower to keep
the lighter hydrocarbons in the system. The sour water from the blowdown
settling drum is pumped by the blowdown sour water pump to the sour water
stripper outside battery limits. Hydrocarbon vapours from the blowdown settling
drum combine with the partially condensed vapours from the fractionator
overhead condenser before the fractionators overhead drum.
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➢ Coker Drum Cycle
The Coking section is composed of two pairs of coke drums. One drum of each
pair will be in service/coking phase, while other will be in decoking phase. Four
Coke Drums have been provided in a two-drum module configuration. For each
module, one drum is coking service while the other drum is in various stages of
decoking. The length of operating cycle is 48 hours.
After one drum has been in coking service for 24 hours, feed is switched to the
second drum leaving 24 hours to decoke the first drum before returning it to
service. This applies for each pair of Coke Drums. The sequence of steps that
take place in decoking stage are mentioned below: -
1) Coking : 24 hrs
2) Switch Drum : 0.5 hrs
3) Stream out to Fractionator : 0.5 hrs
4) Steam out to Blowdown : 1 hrs
5) Slow water cooling : 1 hrs
6) Fast water cooling : 5 hrs
7) Drain coke drum : 2 hrs
8) Un-heading : 0.5 hrs
9) Hydraulic boring and cutting : 5 hrs
10) Re-heading and pressure testing : 1.5 hrs
11) Drum heating up : 7 hrs
The steam generated in the Coke Drums flows to the blowdown system through
the Coker Blowdown Tower, the Blowdown Condenser, where the vapour is
condensed, and the Blowdown Settling Drum. Quenching proceeds until the
Coker Drum overhead is cooled to approximately 176 ⁰C. Then to ensure that the
heavy oil collected in the Coker Blowdown Tower is essentially free of water,
the quenching steam is routed directly to the Blowdown Condenser and the
Blowdown Settling Drum by passing the Coker Blowdown Drum.
Operation in this manner permits the wax tailing carried over with the steam to
collect in the Coker Blowdown Tower. The oil from the Blowdown Settling
Drum is pumped by the Blowdown Slop Oil Pump, back to Coker blowdown
23 | P a g e
tower or to battery limits as light slops. Water from the Blowdown Settling Drum
is pumped by the Blowdown Sour Water Pump, to the Sour Water Stripper
outside battery limit. Final cooling of the Coke Drums is accomplished using the
maximum flow of water from the Quench Water Pump to fill the Coke Drum
with water.
➢ Water Drain and Un-head
The Coke Drum is vented to atmosphere through the Coke Drum Vent Silencer
and drained.
Once the drum is drained, the top and bottoms heads are removed.
➢ Decoking Operation
When the top and bottom heads have been removed from the Coke Drum, the
Coke Cutting Pump and Hydraulic Decoking Equipment are commissioned, and
the decoking operation begins. First, a small pilot hole is drilled through the coke
bed with a special combination boring and cutting tool. After this, the coke boring
and cutting tool uses jets of high pressure water to cut the coke from drum in the
layers. The coke then drops into the coke pit adjacent to the drums. Decoking
water flows into the coke settling maze located at the end of the coke pit. The
coke fines are removed from the decoking water, utilizing the coke bed in the pit
(as a filter medium) and a maze. Final cleaning of decoking water occurs in the
coke settling maze. Clean water is then pumped by the water pumps, through
hydro clones, to the decoking water tank, for reuse. Fines from the coke pit flow
back to the coke pit.
➢ Re-head and Test
After decoking, the top and the bottom heads are replaced. The drum is purged
and pressure tested with steam.
➢ Preheat
After pressure testing the coke drum, the cleaned drum is preheated by vapor
from other drum, which is in the final stage of coking operation. By throttling the
vapor line leading to the fractionator, sufficient back pressure is obtained to force
hot vapor through cold drum. The condensate formed in the cold drum flows to
the coke condensate drum. After being filtered by coke condensate strainer, the
condensate is pumped by the coke condensate pump. The liquid is sent either to
the coke fractionator or the Coker blowdown tower.
24 | P a g e
➢ Coking
The preheated coke drum is returned to the coking service, and the decoking
cycle is repeated for the other drum.
➢ EQUIPMENT LIST: -
➢ Compressor First stage: -
Vapour from Fractionator overhead drum, enters the compressor suction drum
and the two-stage Coker gas compressor. Naphtha wash from the total naphtha
pump, acts as a compressor wheel wash and is injected on an intermittent basis
to reduce/eliminate deposits on compressor wheel that might hinder compressor
performance.
Any entrained liquid from the compressor suction drum, is pumped to the second
stage compressor discharge by the compressor suction liquid pump. Vapor from
the compressor first stage discharge mixes with the wash water stream in the
condenser spray nozzle. This combined stream flows to the compressor inter-
stage condenser and the compressor inter-stage trim condenser, where it is cooled
and partially condensed. The resulting vapor-liquid hydrocarbon-water mixture
flows to the compressor inter-stage drum.
➢ Compressor second stage: -
Vapor from the compressor inter-stage drum flows to the compressor second
stage inlet. Sour water from the compressor inter-stage drum is pumped by the
inter-stage sour water pump, to the fractionator overhead drum, where it is
degassed. Hydrocarbon liquid from the compressor inter-stage drum is pumped
by the compressor inter-stage pump to the compressor second stage discharge.
The compressor second stage discharge is combined with a wash water stream in
the absorber stripper feed condenser spray nozzle.
This then mixes with vapor from the stripper, hydrocarbon liquid from the
compressor inter-stage pump and bottoms from the absorber. The combined flow
enters absorber stripper feed condenser, where it is cooled and partially
condensed. Cooled vapor-liquid hydrocarbon-water mixture from the condenser
flows to the absorber stripper feed drum.
25 | P a g e
Hydrocarbon liquid from the absorber stripper feed drum is pumped by the
stripper feed pump, to the top tray of the stripper. Sour water from the absorber
stripper feed drum flows back on level control to the fractionator overhead drum.
➢ Wash Water System: -
The main source of wash water used in the gas plant section is sour water from
the fractionator overhead drum. Sour water is pumped from the fractionator
overhead drum by the fractionator sour water pump, where a portion of the sour
water is used as a wash water to the compressor inter-stage condenser and
absorber stripper feed condenser. Boiler feed water is available as a back-up
source of wash water, when required. Ammonium polysulphide from the
ammonium polysulphide drum is pumped by ammonium polysulphide pump,
into the wash water system to prevent cyanide corrosion and hydrogen blasting
in vapor lines. Continuous injection of polysulphide solution in wash water
lowers the cyanide content of the condensates and also reacts with the sulphide
corrosion products to produce a protective film on steel surfaces.
➢ Stripper: -
In the stripper, the hydrocarbon liquid from the absorber stripper feed drum is
stripped to remove light hydrocarbons. Stacked reboilers are used on this tower.
The stripper lower reboiler, uses stabilized naphtha from the debutanizer, as a
heating medium. The stripper upper reboiler, uses de-superheated high-pressure
steam as a heating medium. Vapor from top of the stripper flows back to the
absorber stripper feed condenser inlet. Liquid from the bottom of the stripper
flows to the debutanizer. The stripper is equipped with a water draw off pan and
the stripper water collected flows to the stripper water separator. Sour water from
the bottom of this drum flows to the fractionator overhead drum.
➢ Absorber: -
In the absorber, vapor from the absorber stripper feed drum is contacted in
counter-current flow with lean oil. Lean oil consists of un-stabilized naphtha from
the fractionator overhead drum, pumped by un-stabilized naphtha pump, located
in the Coker section, and a stream of cooled stabilized naphtha recycle from
bottom of the debutanizer. The cooled stabilized naphtha is pumped by total
naphtha pump. Rich oil from the bottom of the absorber flows to the absorber
stripper feed condenser inlet.
➢ Sponge Absorber: -
26 | P a g e
Vapor from the top of the absorber flows to the bottom of the sponge absorber,
where it is contacted with counter-current flow with cool lean sponge oil. Lean
sponge oil consists of unstripped LCGO from the sponge oil pump. Lean sponge
oil is cooled first in the lean/rich sponge oil exchanger, then the lean sponge oil
cooler and finally in the lean sponge oil trim cooler, before entering the sponge
absorber, Rich sponge oil from the bottom of the sponge absorber flows through
the lean/rich sponge oil exchanger, to regain some heat which would otherwise
be lost, and is returned to the Coker fractionator. Vapor from the top of the sponge
absorber is cooled by the sour gas cooler and flows to the sour gas K.O drum,
where entrained liquid is removed. This liquid is returned to the Coker
fractionator, via the rich sponge oil line from the sponge absorber bottoms.
Vapor from the sour gas K.O drum section flows to the bottom of the Coker
product gas amine scrubber, where it is contacted with lean amine for removal of
hydrogen sulphide. Gas from the Coker product gas amine scrubber is sent to fuel
gas product K.O drum. This drum is provided to collect any entrained liquid in
the Coker product gas before being exported to the refinery fuel gas header.
Lean amine is supplied to delayed coking unit by the lean amine booster pump
and preheated by lean amine heater, before entering the Coker product gas amine
scrubber. Rich amine from the bottom of the scrubber is combined with the rich
amine from the bottom of the amine contactor, before it is sent to amine
regeneration. Similar to coking section, an antifoam injection package is provided
to prevent foam-over of the Coker product gas amine scrubber to the fuel gas
product K.O drum. Antifoam agent is injected with the lean amine coming from
the lean amine heater.
➢ Debutanizer: -
The debutanizer separates C4s and lighter components from naphtha. Stacked
reboilers are used on this tower. Debutanizer lower reboiler uses HCGO pump-
around from the HCGO pump-around/MP steam generator, as a heating medium.
The stabilized naphtha from the bottom of the debutanizer flows by pressure to
the stripper lower reboiler.
The partially cooled stabilized naphtha is then split into two streams. One part is
sent as feed to the naphtha splitter. Another is further cooled in total naphtha
cooler, then pumped by the total naphtha pump and combined with the un-
stabilized naphtha from the from the fractionator overhead drum, to form lean oil.
Lean oil is then fed to top of the absorber. A slipstream of recycled stabilized
27 | P a g e
naphtha from total naphtha pump I used as a compressor wheel wash on the first
stage of the Coker gas compressor.
Vapour from top of the debutanizer is totally condensed in debutanizer overhead
condenser and enters the debutanizer overhead drum. Part of the liquid in the
overhead drum is pumped as a reflux by debutanizer reflux pump, back to top
tray of debutanizer. The balance of the liquid is pumped by the debutanizer
overhead product pump, to the C3/C4 amine contactor, where H2S is removed.
Any sour water that may collect in the debutanizer overhead drum is returned to
the fractionator overhead drum, located in the Coker section.
The sweetened C3/C4 liquid from top of the C3/C4 amine contactor flows to the
C3/C4 amine water wash drum, where any entrained amine in C3/C4 liquid is
removed. Any amine that is collected in C3/C4 amine settler drum is routed to
rich amine stream which is a combination of rich amine from the bottom of the
Coker product gas amine scrubber and from the C3/C4 amine contactor that
returns to the battery limit. The C3/C4 liquid from the C3/C4 amine water wash
drum is cooled by LPG cooler, before being sent to the battery limits for further
treatment.
➢ Naphtha Splitter: -
Stabilized naphtha stream from the bottom of the debutanizer flows to the
naphtha splitter, after passing through the stripper lower reboiler. The naphtha
splitter fractionates the feed into two streams: light naphtha overhead and heavy
naphtha bottoms. Naphtha splitter reboiler uses de-superheated HP steam as a
heating medium. Vapor from top of the naphtha splitter is totally condensed in
naphtha splitter overhead condenser and enters the naphtha splitter overhead
drum. Liquid is then pumped by light naphtha product/splitter reflux pump, with
a portion of this being refluxed to the top tray of the naphtha splitter. Remainder
of this stream is then cooled by the light naphtha product cooler.
Light naphtha product can either go to tank or to the hydrogen plant outside
battery limits. Heavy naphtha product from the bottom of the naphtha splitter is
pumped by the heavy naphtha product pump, to heavy naphtha product cooler for
cooling. A portion of the heavy naphtha product bypasses the heavy naphtha
product trim cooler, to produce hot heavy naphtha mixing with LCGO from the
LCGO product cooler, to produce middle distillate before being sent to DHDT.
Remainder of the heavy naphtha product trim cooler, is then mixed with cooled
LCGO from the LCGO product trim cooler, in the Coker section to produce
middle distillate before being sent to storage.
28 | P a g e
➢ Coke Handling: -
The coke and water being discharged out of the coke drum, through a chute, is
sent to a large coke pit. Coke pit will allow water to drain off from the coke to a
series of ports. These ports will filter out most of the coke fine parts before
discharging into the maze. Maze provides more settling time for the coke fines in
the water. Water is discharged from the maze over a weir into a clear water sump.
From the sump, water is recycled back by clean water pump, through the hydro
clone, into the decoking water tank, for reuse.
Dewatered coke is moved from the coke pit by a bucket crane to a coke hopper.
The sieve on the coke hopper separates the large coke from smaller coke
materials. From the hopper, the coke product is discharged onto a coke feeder for
better coke distribution. From the coke feeder, the coke product is discharged to
a conveyor. The coke product is then fed to a coke crusher that allows the coke
to be crushed into smaller particles for better handling. From the crusher the coke
product will be discharged into a hopper and finally dropped onto a conveyor
where it is taken to a loading site.
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MASS BALANCE: -
TOTAL FEED = 8901.76 TPD (TONE PER DAY)
TOTAL PRODUCT = 296.8 + 224.7 + 248 + 678.7 + 2742.7 +2431 +151.3
= 6173.2 TPD (TONE PER DAY)
RESIDUE = 2128 TPD (TONE PER DAY)
INPUT = OUTPUT
F = P + R
8901.78 = 6173.2 + 2128
8901.78 = 8901.2 (APPROX)
30 | P a g e
VGO-HDT (VACUUME GASOLINE OIL-HYDROTRETING)
➢ INTRODUCTION: -
Vacuum gas oil unionfining process is typically designed to either upgrade the
feed quality for further processing so that it could be used as an environmentally
friendly fuel oil.
This unit is design to process a blend of vacuum gas oil from vacuum unit and
Coker gas oil from Cokerunit.
The capacity of this unit is 2.1 MMTPA. the unit is designed to be able to process
upto 50% of the cold feed from storage, when unit is operate at turn down mode.
➢ PROCESS CHEMISTRY
Hydro treating reaction is catalyzed by the metal sites on the catalyst. The
primary hydro treating reaction are sulfur & nitrogen removal as well as olefin
saturation. The products of these reaction are the corresponding contaminant
free hydrocarbon, along with H2S & NH3. Other treating reactions includes
oxygen, metal, & halide removal & aromatic saturation in each of these
reaction, hydrogen is consumed & heat is liberated. Some of these reactions is
outlined below.
◆ Sulphur removal Sulphur Removal compound are easily converted to H2S.
Desulphurization of these compounds proceeds by initial ring opening &
sulphur removal followed by salutation of the resulting olefin.
1. Mercaptan
2. Sulphide
3. Disulphide
A. Mercaptan
C-C-C-C-SH + H2 → C-C-C-C + H2S
B. Sulphide
C-C-S-C-C +2H2 → 2C-C + H2S
C. Disulphide
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C-C-S-S-C-C + 3H2 → 2C-C + 2H2S
◆ Nitrogen Removal A. Denitrogenation is generally more difficult than desulphurization. Side
reaction may yield nitrogen compound more difficult to hydrogenate
than the original reactant saturation of heterolyclic nitrogen containing
ring is also hindered by large attached groups.
B. The reaction mechanis seps are different compared to
desulphurization. The denitrogenation of pyridine proceeeds by
aromatic ring saturation, ring hydrogenolysis & finally
denitrogenation.
◆ Oxygen Removal
• Organically combined oxygen is removed by hydrogenation of the
carbon hydroxyl bond folzming water and the corresponding
hydrocarbon.
◆ Olefin Sturation • Olefin saturation reaction procced very rapidly and have a high
need of reaction.
A. Linear olefins
C-C=C-C-C-C + H2 → C-C-C-C-C-C
B. Cyclic olefins
◆ Aromatic saturaion - Aromatic saturettion reaction are the most difficult. The reaction are
influnced by process condition and are often quolibrium limited unit
design parameters would consider degree of saturation for each specific
unit. The saturation reaction is very exothemic.
◆ Metals Removal - The mechanism of the decomposition of organo-metalic compounds is
not well understood. However it os know that metal are retainaed on the
catalyst by a combineination of adsorption and chemical reaction. The
H2
32 | P a g e
catalyst has a certain maximum toierance or capacity for retaining
metals. Removal of metals nor many occurs in plug flow fashion with
respect to the eatalyst bed typical organic metals native to most crude
oils are nicked and velnadium iron can be found concentruted at the top
of corresion dropucts of contact of the fled with salt water or additive
to protect fractionator overhead systems from corrosion or to control
foaming can account for the presence of phosphorus and silicon. Lead
may also deposit on the hydrotreeting eatelyst from reprocessing leaded
gesoline through the erude unit.
33 | P a g e
➢ Process Flow Diagram of VGO-HDT : -
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35 | P a g e
➢ PROCESS DESCRIPTION: -
The unit consist of mainly three sections
1. Reactor section
2. Fractionation section
3. OFF gas scrubbing section
➢ Reactor section: -
Fresh feed from Coker and vacuum unit enter at SR-FEED surge drum.
The combine stream is pumped by feed booster pump and then passing
through back wash filter.
After passing through back wash filter, the combine stream enters at main feed
surge drum operating at pressure of 3.5 KG/cm2 (g).
The charge pump with discharge pressure of 109 KG/cm2 (g) takes the suction
from feed surge drum and adding toreactor. recycle gas heated to around 426
C in the recycle gas heater, is mixed with gas oil upstream of the reactor.
The combine feed stream enters the top of reactor at a temperature around
385oC. the rector is divided into 4 individual catalyst beds and cold recycle
gas at about (40-65 oC) is brought into the reactor at the inter –bed quench –
point in order to cool the reactants and control the reaction rate.
The reactor effluents passes through the shell side of effluent recycle gas hot
exchanger (E-01), effluent feed exchanger (E-02), effluent recycle cold
exchanger (E-03) to recover heat of reaction and then enter the hot separator
operating at pressure of 84 KG/cm2 (g).
Hot separator is installed for liquid and vapour separation. heavier
hydrocarbon material from reactor effluent is send to hot flash drum operating
at pressure of 33 KG/cm2 (g)
And then passes through the stripper.
The overhead vapour from hot separator flow through the shell side of hot
separator vapour feed exchanger (E-04) , hot separator vapour recycle gas
exchanger (E-05) and hot separator vapour condenser (EA-02) into the cold
separator which is operating at pressure of 81 KG/cm2 (g)
36 | P a g e
Sulphur and nitrogen contained in the feed are converted to H2S and NH3 in
the reactor. hence wash water is injected to prevent deposition ammonium salt
that can corrode and foul the cooler. flashed vapour from the hot flash drum
is cooled in the hot flash vapour condenser (EA-01) and send to cold flash
drum operating at pressure at 32 KG/cm2 (g)
Liquid hydrocarbon from cold separator passes through cold flash drum ,tube
side of stripper feed exchanger (E-15),shell side of product fractionator bottom
stripper feed exchanger (E-12) into the stripper .the flashed vapour from the
cold separator is send to recycle gas scrubber .the flashed vapour from cold
flash drum is routed to the OFF GAS KNOCKOUT DRUM (V-06) via OFF
gas cooler (E-06) , condensable are routed to the liquid hydrocarbon stream
living the cold flash drum and non-condensable are routed to MP OFF gas
scrubber , water is collected in boot attached to cold separator and removed
on level control and send to sour water stripper .
The recycle gas from the cold separator enters the scrubber from the bottom
via recycle gas knockout drum (V-07) and contacted with amine counter
current to remove H2S from gas stream, H2S reduce the partial pressure and
also decrease the activity of catalyst, hence its removal become essential . the
scrubber gas leaves from the top of scrubber and is send to recycle gas
compressor (K-01).
Make up hydrogen is fed from HGU unit at pressure of 19.8 KG/cm2 (g). this
hydrogen is added upstream of recycle gas compressor.
Hence pressure needs to be boosted upto 81 KG/cm2 (g).in order to achieve
this pressure, to stage make-up gas compressor (K-02) is added.
➢ Fractionation section: -
Liquids from hot flash drum and cold flash drum go to stripping column which
operates at pressure of 8 KG/cm2 (g)
The purpose of stripper is to remove H2S. steam is used to strip naphtha and
lighter material in the stripper. the vapour leaving the stripper are condensed
in stripper condenser and stripper trim condenser and flow into the overhead
stripper receiver. the stripper receiver separates the non- condensable vapour
contain with H2S, hydrocarbon liquid and sour water. overhead liquid is
refluxed to the stripper and the balance amount is routed to the debutanizer to
tray no.20 operating at pressure of 11.43 KG/cm2 (g).
The overhead vapour from debutanizer is routed debutanizer receiver where
non-condensable vapour contain with H2S is separated from liquid
37 | P a g e
hydrocarbon. overhead liquid is refluxed to the debutanizer. stripping vapour
is provided by thermosiphon reboiler and light naphtha product is removed
from bottom of the debutanizer. the overhead vapour from the stripper receiver
and debutanizer receiver is routed to LP OFF gas scrubber.
Stripper bottom liquid is pumped out and heated first in the product
fractionator feed bottom exchanger and then heated to 385 C in product
fractionator feed heater and then send to product fractionator on tray no.10
which operating at pressure of 1.43 KG/cm2 (g)
LP stripping steam is added to the bottom section of product fractionator to
remove light hydrocarbon from bottom product. the overhead vapour from
product fractionator is routed to the product fractionator receiver via product
fractionator condenser. the liquid hydrocarbon is pumped out to naphtha
storage. a fuel gas push pull pressure control system is provided to maintain
receiver pressure of 0.7 KG/cm2 (g)
Diesel product is withdraw from below tray no.27 of product fractionator and
is routed to diesel stripper where steam is used to provide stripping vapour.
diesel product is removed from the bottom and cooled in MP steam generator,
product cooler and trim cooler. Most of water is removed in diesel coalescer
and diesel product is send to storage via salt drier.
Kerosene product is withdrawn from below tray no. 40 of the product
fractionator. Kerosene is then routed to Kerosene stripper where thermosiphon
reboiler is used to provide the stripping vapour.Kerosene product is then send
to storage.
Desulfurised vacuum gas oil is withdraw from the bottom of product
fractionator and cooled in series of exchangers including – E-11, E-12,E-18,E-
23,E-13,E-20,E-26 AND then routed to FCC unit.
➢ OFF gas scrubbing section: -
LP and MP OFF GAS scrubber use amine to absorb H2S from OFF gas
stream.removal of H2S in OFF gas scrubber increases the hydrogen partial
pressure in off gas before it is being send to hydrogen recovery. Lean amine
from the lean amine discharge pump is sent to the top tray of OFF gas
scrubber.
38 | P a g e
➢ EQUIPMENT LIST: -
➢ FEED BOOSTER SYSTEM: -
Purpose: - To provide cold VGO from tank farm in situation of non-
availability of feed.
➢ Back wash filter: -
Purpose: - To remove particulates which stick on catalyst and create high
pressure drop across reactor.
Backwash filter have 3 banks
1. Bank A
2. Bank B
3. Bank C
One bank is master mode and remaining to sequence mode.
Total filtration area is 55.2 m2.
Each filter housing contains 28 nossel and design for filtering degree of 25
micron.
Backwash filter cycle duration is 4 hours.
When pressure drop rich 1.8 kg/cm2, backwash cycle of 1 filter bank start and 2
remaining in line.
➢ RECYCLE GAS HEATER: -
Purpose: - To preheat recycle gas from 336c to 485c.
◆ Convection Section: -
It includes 27 convection tubes with 6 pass horizontal convection section.
◆ Radiant Section: -
It includes 96 radiant tube with 6 pass vertical radiant section.
39 | P a g e
Amount of heat release in recycle gas heater is 17.52 mmkcal/hr .
Efficiency of recycle gas is 92%.
➢ Reactor: - • Operating Pressure – 10g Kg/cm2 (g)
• Operating Temperature – 454oC
➢ Factor of Reactor design: - • Seismic activity
• Weight limitation
• Rector height which depend on,
I. Amount of Catalyst
II. No. of tray
➢ An exothermic reaction takes place in reactor. There, for maintaining
temperature. We cold recycle gas at 80 oC as a quenching.
➢ The reactor has 4 beds with separate support system. The reason behind
it,
• Gas & liquid flow is ideally distributed
• Catalyst in lower bed still work effectively
◆ Material of Construction
• 1.25% of chromium & 0.5% MO or
• 1% chromium & 0.5% MO or
• 2.25% chromium & 1% MO
With base metal KCS.
➢ Because of chloride attack & polyphonic acid attack crack corrosion &
inter granule corrosion take place, which can prevent by,
1. Using austenitic stainless steel neutralize with 5% soda Solution.
2. By keeping minimum amount of chloride
3. Temperature above dew point of H2O
1) Inlet diffuser
• It is situated in inlet nozzle
• Purpose: -
I. Reduce velocity
II. Ideal distribution of liquid
2) Top liquid distribute tray
40 | P a g e
• It is fabricated on vessel
• Purpose: -
I. To increase the performance of catalyst
II. To optimize contact between reactor & catalyst
3) Distribution tray raiser
• Purpose: -
I. The level of liquid in top liquid distributor tray in maintained
by distribution tray raiser.
4) Bed section
• It includes 4 beds
• Purpose: -
I. To increase the activity of catalyst
• Catalyst: - Nickel / CO + MO
• Base: - Al2O3
• Corrosion product collected at top bed.
5) Quench mixing section
• It contains 3 quench sections.
• Purpose: -
I. To maintain the temperature of exothermic reaction
• Each quench section includes
I. Support grid
II. Quench distributor
III. Mixing chamber
IV. Rough distributor
V. Final distributor tray
6) Collector section
• Purpose: -
I. For collecting migrate catalyst through outlet nozzle situated
after last bed.
➢ WASH WATER INJECTION HEATER: - Purpose: - To remove undesirable product such as NH4CL by
dissolving into wash water.
Flow of water 28.6 m3/hr.
41 | P a g e
➢ Hot separator (High Pressure – High
Temperature): - • It is vertical vessel with baffle to reduce carry over.
• Operating pressure: - 85 Kg / Cm2g
• Operating temperature: - 288 oC
• Purpose: -
I. To remove heavy material
➢ Hot flash drum (Low pressure – High
Temperature): - • Purpose: -
I. To reduce the pressure up to 53.5 Kg / cm2g
II. To separate vapor & dissolved gas
➢ Cold separator (High pressure-low
temperature): - • Operating Pressure – 81.57, Operating Temperature – 53 oC
• It is horizontal vessel with water boot.
• Purpose: -
I. To separate Hydrocarbon liquid
II. To separate gas
III. To separate sour water, contain with NH3 & H2S
• To protect form corrosion, we use Monel layer with 3 mm thickness.
• To coalesce water, drop late in hydrocarbon phase we use mesh blanket
with 3.00 mm thickness.
➢ Cold flash drum (low pressure-low
temperature): - • Operating pressure: - 3235 kg / cm2g
• Operating temperature: - 55 oC
• Purpose: -
I. To separate the vapor
• To protect form corrosion, we use Monel layer with 3 mm thickness.
• To coalesce water, drop late in hydrocarbon phase we use mesh
blanket with 3.00 mm thickness.
➢ STIPPER: -
42 | P a g e
• Stripper is a vertical vessel constructed of KCS containing 32 nos. of valve
trays.
• Stripper is designed for 10 kg/cm2g pressure and temp of 330c.
• The purpose of stripper is to remove approximate 0.05 wt.% H2S present
so that the environment in the product fractionators fired heater and product
fractionators will be sulphur free.
• Stripper steam is injected below the bottom tray.
• This stripper steam is provided to strip off H2S and lighter components
from the stripper bottoms product.
• Stripper overhead vapours leaving the top of the stripper are cooled in
stripper overhead condenser.
➢ STRIPPER RECEIVER: -
Purpose: - To separate, 1) non-condensable vapor 2) hydrocarbon liquid 3)
sour water21
Top section of stripper contains sour water and H2S that leads to corrosion.
For minimizing corrosion in stripper, inhibitors diluted with naphtha is used.
➢ DEBUTANIZER: -
It is a vertical vessel with 20 no. of valve at bottom and random packing at top.
Purpose: - To separate, 1) non-condensed vapor 2) hydrocarbon liquid 3) sour
water
Sour water collected at bottom of debutanizer receiver.
To prevent the corrosion of debutanizer, we use inhibitors.
Bottom liquid used as heating medium in re-boiler.
➢ PRODUCT MAIN FRACTIONATOR (C-03):- • Product Fractionator is a vertical vessel constructed of KCS.
• Containing 49 no of valve trays.
Purpose:-
• Product Fractionator separates the full range naphtha, kerosene, diesel and
VGO product present in the column feed.
• Entering temperature is 383 0c. out temperature is maintained at 135-1400c.
43 | P a g e
➢ DIESELSTRIPPER: - • Diesel stripper is vertical vessel constructed of KCS.
• Containing 6 no of valve trays.
• Designed for 4 kg/cm2 and 305 .c & full vacuum at 272 0c.
Purpose:-
• It is use to remove any key material that is present in the diesel material,
withdrawn from the product fractionator.
• Entering temperature is 268 .c & out temperature is 253 0c.
➢ Kerosene stripper: -
Purpose: - It is remove the lighter material that are present in the kerosene.
Kerosene product from kerosene stripper bottom is withdraw by kerosene bottom
pump.
Kerosene product is cooled to 40 c by kerosene product cooler and kerosene
product trim cooler in series.
Kerosene stripper is top on the diesel stripper Colum.
Kerosene stripper Is Vertical Vessel,Constructed by KCS material andcontaining
10 no. of valve trays.
From product fractionator Columbetween tray 39 and 40 is fed to the kerosene
stripper on the top tray at 190 c via fed.
Thermosyphon kerosene stripper reboiler is provided for heat input the kerosene
stripper Colum. Product fractinor bottom liquid is used as heating media in the
reboiler approx 33% water vaporized in the reboiler and send back to the kerosene
stripper.
Lighter component is stripper of from the kerosene stripper and send back to 40th
tray below of the product fractionator.
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➢ SCRUBBING SECTION: -
Purpose: - For decreasing the quantity of H2S, we use lean amine from ARU.
Recycle gas contain with 3.4-12.5% H2S.
H2S decreases the activity of catalyst.
Recycle gas (with H2S) + lean amine Recycle gas (without H2S) + rich
amine
It includes, 1) KOD 2) SCRUBBER
i. KOD
It consists of 316 stainless steel.
Purpose: - To recycle HC liquid from recycle gas, we use mesh blanket at
the top of KOD.
ii. SCRUBBER
It contains 9 trays.
Purpose: - to remove H2S from recycle gas, we use mesh blanket at the top
of scrubber.
To prevent foaming in scrubber, we maintain temperature difference
between lean amine and recycle gas at 5c.
To remove skim in scrubber we use skimming nozzle.
45 | P a g e
MASS BALANCE: -
TOTAL FEED = FEED (RAW GAS OIL) + UTILITY(H2)
= 262270 (Kg/hr) + 4090 (Kg/hr)
= 266360 (Kg/hr)
TOTAL PRODUCT = 894 + 1934 +1289 +1075 +9559 +44423 +202524 + 2618
= 264316(Kg/hr)
RESIDUE = 2044 (Kg/hr)
INPUT = OUTPUT
F = P + R
26630 = 264316 + 2044
26630 = 26630
46 | P a g e
➢ MAJOR HAZARDS: -
The information in this section must be thoroughly understood by the reader
before reading the rest of this manual or operating the plant. It could save your
life.
Poisonous Gas
Hydrogen sulphide (H2S): -
A matter of utmost concern for all operation personal is the presence of H2S in
streams. H2S is a colourless gas slightly heavier than air. H2S is highly
flammable and a dangerous fire risk. Hydrogen sulphide is an explosive gas
which will explode in concentrations of 4.31 to 46% by volume in air. Hydrogen
sulphide explosions may occur in the vapor space over liquid sulphur, because as
liquid sulphur is cooled or agitated. It releases H2S into the vapor space above it.
Such vapor exists above the liquid sulphur in the sulphur pit, which must be swept
with air to prevent a build-up of H2S. H2S is easily identified in very low
concentration by the strong pungent odor of egg’s. Higher concentrations of H2S
is present in the feed from the Coker fractionators overhead system to the Coker
gas compression system and in many lines and vessel in plant.
NOTES: -
1. H2S is extremely poisonous and breathing any concentration must be
avoided. Symptoms of poisoning very with the concentration and length of
exposure consult the MSDS or your plant industrial hygienist regarding
exposure limitation.
2. H2S leaks should never be approached without self-contained breathing
apparatus and back up personnel also equipped with as SCBA on site and
available to assist. The unit is equipped with H2S monitors to detect H2S
leaks up to 50 PPM. A warning alarm sounds when a concentration of 10
PPM is defected and a danger alarm sounds when a concentration of 15
PPM is detected.
PRECAUTIONS TO AVOID DANGER FROM HYDROGEN SULFIDE
GAS
Working in any concentration of hydrogen sulphide is not desirable. The
material safety data sheet or your plant industry hygienist will define the
concentration and duration exposure limits.
47 | P a g e
Because of the dangers from the release of hydrogen sulphide gas, the
following precautions must be strictly observation
1. Do not work or permit anyone to work in suspected of containing
hydrogen sulphide gas without first having the area tested by a qualified
gas tester using an approved H2S detector.
2. Report leakage of gas or any suspicious gaseous area as soon as
discovered.
3. Keep out of contaminated areas and keep others out.
4. Stay on the wind wall side of the contaminated area as long as the
condition exists.
5. When necessary to vent equipment containing hydrogen sulphide
bearing material, use a vent or relief system, if provided. Avoid venting
this gas directly to the atmosphere.
6. Assure adequate ventilation in maintained for any enclosed space where
leakage of gases might occur. Prevent a accumulation of H2S.
7. Use a self-contained breathing apparatus if it should become necessary
to enter and area where there is any possibility of hydrogen sulphide gas
being present, especially in enclosed locations where gas could
accumulate. Have properly quipped backup personnel standing by in a
safe location. Wear a safety harness and lifeline if necessary.
ANTIFOAM
EYE/FACE PROTECTION
SKIN PROTECTION
HAND PROTECTION
VCARSOL
GT-10
USE SAFETY
GLASSES
WEAR CLEAN
BODY-
COVERING
CLOTHING
USE GLOVES
CHEMICALLY
RESISTANT TO
THIS
MATERIAL
WHEN
FREQUENTLY
REPEATED
CONTANT
COULD OCCUR.
UCARSOL
GT-8715
GLASSES WEAR CLEAN
BODY
COVERING
CLOTHING
USE GLOVES
CHEMICALLY
RESISTANCE
TO THIS
MATERIAL
48 | P a g e
WHEN
PROLONGED
OR
FREQUENTLY
REPEATED
CONTACT
COULD OCCUR.
NALCO WEAR
CHEMICAL
SPASH
GOGGLES
WEAR
IMPERVIOUS
APRON AND
BOOTS.
NITRILE
GLOVES,
VITRON
GLOVES,
POLYVINYL
ALCOHOL
GLOVES
➢ DE-EMULSIFIER
SKIN PROTECTION: - Wear standard protective clothing
EYE PROTECTION: - Wear chemical splash goggles.
HAND PROTECTION: - Nitrile gloves, PVC gloves, Vitron gloves
MSHA/NIOSH
EYE PROTECTION: - Chemical goggles and full face shield
SKIN PROTECTION: - Gloves, boots
PETROLEUM COKE
EYE PROTECTION: - Safety glasses, chemical type goggles, face shield
recommended to prevent eye contact.
SKIN PROTECTION: - To prevent repeated skin contact, wear impervious
clothing.
HAND PROTECTION: - Gloves resistant to chemical and petroleum distillates
may be used.
PROTECTIVE CLOTHING: - Protective clothing such as lab coats should be
wear. Launder or dry clean when soiled.
DEBUTANIZER BOTTOMS
RESPIRATORY PROTECTION: - Airborne concentration should be kept to the
lowest levels possible. If vapor, mist or dust is generated and the occupational
49 | P a g e
exposure limit of the product , or any component of the product, is exceeded use
appropriate NIOH approved air purifying or air supplied respirators after
determining the airborne concentration of the contaminant. Air supplied
respirators should always be contaminant or oxygen content is unknown.
EYE PROTECTION: - Avoid eye contact, safety glasses, chemical type goggles,
or face shield recommended to prevent eye contact.
HAND PROTECTION: - Gloves resistant to chemicals and petroleum distillates
may be used. Gloves should be worn while handling large quantities.
PROTECTIVE CLOTHING: - Protective clothing such as coveralls or lab coats
should be worn. Launder or dry clean when soiled, while handling large quantities
impervious suits, gloves, and rubber boots must be worm.
NAPHTHA: -
EYE PROTECTION: - Wear safety glasses or goggles where contact with liquid
or mist may occur.
SKIN PROTECTION: - Wear impervious gloves where contact with skin may
occur. Use face shield where splashing may occur.
LCGO: -
EYE PROTECTION: - Safety glasses, chemical type goggles, or face shield
recommended to prevent eye contact.
HAND PROTECTION: - Gloves resistant to chemicals and petroleum distillates
may be used. Gloves should be worm while handling large quantities.
PROTECTIVE CLOTHING: - Protective clothing such as coveralls or lab coats
should be worn. Launder or dry clean when soiled. While handling large
quantities impervious suits, gloves and rubber boots must be worn.
HCGO: -
EYE PROTECTION: - Chemical type goggles should be worn.
SKIN PROTECTION: - Impervious gloves and clothing must be worm if contact
is required.
PROTECTIVE CLOTHING: - Protective clothing such as coveralls or lab coats
should be worn. Launder or dry clean when soiled. While handling large
quantities impervious suits, gloves and rubber boots must be worn.
CORROSIVE MATERIALS: -
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Consult the material safety data sheet before handling any potentially hazardous
material.
Proper PPE should be worn whenever handling toxic or corrosive materials.
A safety shower is present where corrosive chemicals such as ammonia, chlorine,
caustic soda, sulfuric acid, etc. are handled. Water may also be used to reduce the
spread of toxic vapours.
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➢ CONCLUSION: -
▪ As we have been there we have experienced and gained the
knowledge about the proper industry. In books we acquire
only theoretical knowledge, but in actual, the pragmatic
implementation of the same, can be grasped only by visiting
an industry.
▪ The visit was highly educational and helped one to given us
a depth understanding of manufacturing of various product
of IOCL.
▪ We understood the difficulties that is faced by difficult
weather and also studies the ways they save the difficulties
and problems.
▪ We have gained lots of knowledge and experience needed
to be successful in a great engineering challenge, as in our
opinion Engineering is after all a Challenge, and not a Job.
52 | P a g e
➢ REFERANCES: -
• UNIT MANUAL
• www.iocl.com
• www.wikipedia.org
