IOCL Vocational Training Report

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Acknowledgement Indian Oil History Barauni Refinery: Introduction Present Configuration

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Basic Refinery Processes Primary Processing Units Atmospheric Distillation Unit Vacuum Distillation Unit

 Coker Unit  Catalytic Reforming Unit (CRU)  BXP Unit (RFCCU, DHDT, SRU, HGU)  Prime G+ (NHDT, ISOM, SHU)  Some Units IN Detail with PFD  Typical product pattern  Safety measures in Refinery

ACKNOWLEDGEMENT It’s a great for being a part of IOCL which is the world’s 98 th largest public corporation according to the FORTUNE GLOBAL’s 500 list and amongst the top companies of India by FORTUNE INDIA 500 IN 2011. This acknowldgement is a way by which I am getting the opportunity to show the deep semse of gratitude and obligation to all the people who hav e prov ided me with inspiration and guidance during the preparation of the training report. I would take this chance to thank Mrs.Krishna Kumari, Officer T&D , Mr. Kalyan Bagchi DM (T&D) ,Ms Nilu Rani (O.A, T&D) for prov iding us with this wonderful opportunity to interact with the experts in Barauni refinery. I would also like to express my sincere gratitude towards Mr. C.V.Ingle, Production Manager for mentoring us throughout the training period and all the learned employees who took pains to quench my curiosity and shared their knowledge. Last but not the least; I would like to thank my parents whose encouragement and motiv ation was a constant source of strength and without which it wouldn’t hav e been possible.

INDIAN OIL HISTORY Indian Oil, the largest commercial enterprise of India (by sales turn ov er), is India’s sole representativ e in Fortune's prestigious listing of the world's 500 largest corporations, ranked 189 for the year 2004. It is also the 17th largest petroleum company in the world. Indian Oil has a sales turnov er of 1, 20,000 crores and profits of 8,000 crores. Indian Oil has been adjudged second in petroleum trading among the 15 national oil companies in the Asia-Pacific region. As the premier National Oil Company, Indian Oil’s endeav or is to serv e the national economy and the people of India and fulfill its v ision of becoming an integrated, div ersified, and transnational energy major. 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 ev ery Indian’s heart by keeping the v ital oil supply line operating relentlessly in ev ery nook and corner of India. I t has the backing of ov er 33% of the country’s refining capacity as on 1 st April 2002 and 6523 km of crude/product pipelines across the length and breadth of the country. IOCL’s v ast distribution network of ov er 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 & Bongaigaon with a current combined rated capacity of 49.30 million metric tonnes per annum (MMTPA) or 990 thousand barrels per day (bpd). Indian Oil’s world-class R&D Centre has won recognition for its pioneering work in lubricants formulation, refinery processes, pipeline transportation, and bio-fuels. It has dev eloped ov er 2,100 formulations of SERVO brand lubricants and greases for v irtually all

conceiv able applications - automotiv e, railroad, industrial and marine – meeting stringent international standards and bearing the stamp of approv al of all major original equipment manufacturers. The centre has to its credit ov er 90 national and international patents. The wide range of brand lubricants, greases, coolants, and brake fluids meet stringent international standards and bear the stamp of approv al of all major original equipment manufacturers. Indian Oil operates 17 training centres throughout India for upskilling, re-skilling, and multi-skilling of employees in pursuit of corporate excellence. Among these, the foremost learning centres are Indian Oil Institute of Petroleum Management at Gurgaon, Indian Oil Management Centre for Learning at Mumbai, and Indian Oil Management Academy at Haldia, hav e emerged as world-class training and management academies. Indian Oil Institute of Petroleum Management, the Corporation's apex center of learning, conducts adv anced management dev elopment programs in collaboration with reputed institutes. It also offers a unique mid-career International MBA programs in Petroleum Management. Indian Oil aims at maintaining its leadership in the Indian hydrocarbon sector by continuous assimilation of emerging Information Technology and web-enabled solutions for integrating and optimizing the Corporation's hydrocarbon v alue chain. It is has implemented an IT re-engineering project titled Manthan, which includes an Enterprise Resource planning (ERP) package which will standardize and integrate the Corporation's business on a common IT platform through a robust hybrid wide area network with appropriate hardware.

 Barauni Refinery, the second Public Sector Oil refinery of the country, was built in collaboration with the erstwhile USSR & limited Romanian participation.  Inaugurated on 15 th Jan’65 by the then Hon’ble minister for Petroleum & Chemicals, Prof. Humayun Kabir  Located at a distance of approximately 120 km from Patna, Bihar. Facilities • 16 nos. of Process Plants • Offsite facilities including:  Storage tanks  Effluent Treatment Plant & Bio Treatment Plant  Product dispatch facilities, including 3 nos. of gantries • Captiv e Power Plant with:  6 Boilers

: 5 X 75MT/hr+1X150MT/hr

 4 TG’s

: 1x 5.5 MW + 1X 12 MW + 1 X 12.5 MW + 1 X 20 MW

 2 Gas Turbines : 2X 20MW with HRSG (48MT/hr)

Present Configuration

Basic Refinery Processes  Planning, Scheduling, Receipt & storage of crude oil  Separation Processes  Conversion Processes  Treatment Processes  Blending & Certification Processes  Product storage & Dispatch operations  Other refinery processes & Operations

Primary Processing Units  The purpose of Primary unit is to separate the crude in to different fractions through atm. & v ac. distillation.  Important operations of AVUs:  Crude desalting: Remov al of contaminants like salts, water etc. from crude and can be compared with human kidney.  Crude pretopping: Remov al of lighter (E-1 gasoline/ K-1 Hy naphtha from crude to reduce load on main fractionator.  Atm. Distillation: Distillation of crude at atmospheric pressure and remov al of lighter products up to gas oil.

 Vac. Distillation: Distillation of crude in v acuum to av oid thermal cracking at higher operating temperatures.

Atmospheric Distillation Unit Crude oil is sent to the atmospheric distillation unit after desalting and heating. The purpose of atmospheric distillation is primary separation of v arious 'cuts' of hydrocarbons namely, fuel gases, LPG, naptha, kerosene, diesel and fuel oil. The heav y hydrocarbon residue left at the bottom of the atmospheric distillation column is sent to v acuum distillation column for further separation of hydrocarbons under reduced pressure. As the name suggests, the pressure profile in atmospheric distillation unit is close to the atmospheric pressure with highest pressure at the bottom stage which gradually drops down till the top stage of the column. The temperature is highest at the bottom of the column which is constantly fed with heat from bottoms reboiler. The reboiler v aporizes part of the bottom outlet from the column and this v apor is recycled back to the distillation column and trav els to the top stage absorbing lighter hydrocarbons from the counter current crude oil flow. The temperature at the top of the column is the lowest as the heat at this stage of the column is absorbed by a condenser which condenses a fraction of the v apors from column ov erhead. The condensed hydrocarbon liquid is recycled back to the column. This condensed liquid flows down through the series of column trays, flowing counter current to the hot v apors coming from bottom and condensing some of those v apors along the way. Thus a reboiler at the bottom and a condenser at the top along with a number of trays in between help to create temperature and

pressure gradients along the stages of the column. The gradual v ariation of temperature and pressure from one stage to another and considerable residence time for v apors and liquid at a tray help to create near equilibrium conditions at each tray. The heav iest hydrocarbons are taken out as liquid flow from the partial reboiler at bottom and the lightest hydrocarbons are taken out from the partial condenser at the column ov erhead. For the in between trays or stages, the hydrocarbons become lighter as one mov es up along the height of the column. Various other cuts of hydrocarbons are taken out as sidedraws from different stages of the column. Starting from LPGat the top stages, naptha, kerosene, diesel and gas oil cuts are taken out as we mov e down the stages of atmospheric column.

Vacuum Distillation Unit Crude oil is first refined in an Atmospheric Distillation Column. Fractions of crude oil such as lighter gases (C1-C4), gasoline, naphtha, kerosene, fuel oil, diesel etc. are separated in the atmospheric distillation column. The after taking out these lighter hydrocarbon cuts, heav y residue remaining at the bottom of the atmospheric distillation column needs to be refined. These heav y hydrocarbon residues are sent to a Vacuum Distillation Column for further separation of hydrocarbons under reduced pressure. Heav ies from the atmospheric distillation column are heated to approximately 400˚C in a fired heater and fed to the v acuum distillation column where they are fractionated into light gas oil, heav y gas oil and v acuum reside. Some heav y hydrocarbons cannot be boiled at the operating temperature and pressure conditions in the atmospheric distillation column. Hence they exit the bottom of the column in liquid state and are sent to the v acuum distillation column where they can be boiled at a lower temperature

when pressure is significantly reduced. Absolute operating pressure in a Vacuum Tower can be reduced to 20 mm of Hg or less (atmospheric pressure is 760 mm Hg). In addition, superheated steam is injected with the feed and in the tower bottom to reduce hydrocarbon partial pressure to 10 mm of mercury or less. Lower partial pressure of the hydrocarbons makes it ev en more easier for them to be v aporized, thus consuming less heat energy for the process. Two different cuts of hydrocarbons - 'light v acuum gas oil' and 'heav y v acuum gas oil' are separated in the v acuum distillation column at different stages of the column, based on the difference between their boiling point ranges. The liquid being drawn at low pressure needs to be pumped. Then it is heated and partially recycled back to the column. Part of it is taken out as v acuum distillation products - 'light v acuum gas oil' or 'heav y v acuum gas oil'. Light v acuum gas Oil is sent to a hydrotreater and then to a 'catalytic cracking' unit to obtain smaller chain hydrocarbons. Heav y v acuum gas oil is also sent for cracking using hydrogen in a 'hydrocracking unit' to produce smaller chain hydrocarbons. Heav y hydrocarbons which cannot be boiled ev en under reduced pressure remain at the bottom of the column and are pumped out as 'v acuum residue'. The v acuum distillation column bottom residue can only be used for producing coke in a 'coker unit' or to produce bitumen.

Coker Unit Coking is a refinery unit operation that upgrades material called bottoms from the atmospheric or v acuum distillation column into higher-v alue products and, as the name implies, produces petroleum coke—a coal-like material. Petroleum coke has uses in the electric power and industrial sectors, as fuel inputs or a manufacturing raw material used to produce electrodes for the steel and aluminum industries. In 2011, the refining industry supplied 132 million barrels of petroleum coke with most of it subsequently consumed as fuel. Two types of coking processes exist—delayed coking and fluid coking. Both are physical processes that occur at pressures slightly higher than atmospheric and at temperatures greater than 900 oF that thermally crack the feedstock into products such as naphtha and distillate, leav ing behind petroleum coke. Depending on the coking operation temperatures and length of coking times, petroleum coke is either sold as fuel-grade petroleum coke or undergoes an additional heating or calcining process to produce anode-grade petroleum coke. With delayed coking, two or more large reactors, called coke drums, are used to hold, or delay, the heated feedstock while the cracking takes place. Coke is deposited in the coke drum as a solid. This solid coke builds up in the coke drum and is remov ed by hydraulically cutting the coke using water. In order to facilitate the remov al of the coke, the hot feed is div erted from one coke drum to another, alternating the drums between coke remov al and the cracking part of the process. With fluid coking, the feed is charged to a heated reactor, the cracking takes place, and the formed coke is transferred to a heater as a fluidized solid where some of it is burned to prov ide the heat necessary for the cracking process. The remaining coke is collected to be sold. Like other secondary processing units, coking can play an important role in refinery economics depending on the type and cost of the crude oil run at a refinery. As the quality of crude oil inputs to a refinery declines, coupled with greater demands for transportation

fuels, coking operations will serv e to meet transportation fuel demands and also produce increasing quantities of fuel-grade and anode-grade or needle petroleum coke.

Catalytic Reforming Unit (CRU) Catalytic reforming is a major conv ersion process in petroleum refinery and petrochemical industries. The reforming process is a catalytic process which conv erts low octane naphthas into higher octane reformate products for gasoline blending and aromatic rich reformate for aromatic production. Basically, the process re-arranges or re-structures the hydrocarbon molecules in the naphtha feedstocks as well as breaking some of the molecules into smaller molecules. Naphtha feeds to catalytic reforming include heav y straight run naphtha. It transforms low octane naphtha into high-octane motor gasoline blending stock and aromatics rich in benzene, toluene, and xylene with hydrogen and liquefied petroleum gas as a byproduct. With the fast growing demand in aromatics and demand of high - octane numbers, catalytic reforming is likely to remain one of the most important unit processes in the petroleum and petrochemical industry. Basic steps in catalytic reforming involve 1) Feed preparation: Naphtha Hydrotreatment 2) Preheating: Temperature Control, 3) Catalytic Reforming and Catalyst Circulation and Regeneration in case of continuous reforming process 4) Product separation: Remov al of gases and Reformate by fractional Distillation 5) Separation of aromatics in case of Aromatic production REACTIONS IN CATALYTIC REFORMING Following are the most prev alent main reactions in catalytic reforming

Desirable Dehydrogenation of naphthenes to aromatics Isomerisation of paraffins and naphthenes Dehydrocyclisation of paraffins to aromatics Non-Desirable Hydrocracking of paraffins to lower molecular weight compounds Dehydrogenation & Dehydrocyclization: Highly endothermic, cause decrease in temperatures, highest reaction rates, aromatics formed hav e high B.P so end point of gasoline rises Dehydrogenation reactions are v ery fast, about one order of magnitude faster than the other reactions. The reaction is promoted by the metallic function of catalyst Methyl cyclohexane Toluene + H2 MCP Benzene + H2 Dehydrocyclisation: It inv olv es a dehydrogenation with a release of one hydrogen mole followed by a molecular rearrangement to form a naphthene and the subsequent dehydrogenation of the naphthene. i-paraffins to aromaticsof paraffins n-heptane , toluene + H2 Favourable Conditions: High temperature, Low pressure, Low space v elocity, Low H2/HC ratio Isomerisation: Branched isomers increase octane rating, Small heat effect, Fairly rapid reactions. Favourable Conditions: High temperature, Low pressure, Low space v elocity, H2/HC ratio no significant effect Naphthenes dehydro-Isomerisation: A ring re-arrangement reaction, Formed alkyl-cyclohexane dehydrogenate to aromatics.• Octane increase is significant, Reaction is slightly exothermic

BXP Units

RFCCU

A Residue FCC (RFCC) unit expands the versatility and profitability of an FCC to crack a wider variety of feedstock: 

Traditional FCC feedstocks

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Deeply Deasphalted Oil

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Atmospheric Residue

Vacuum Residue The quality of the feed is the main determinant of the yields and product properties. The yield of v aluable gasoline and LPG products in the FCC unit will be mainly influenced by the hydrogen content of the feed. Feed contaminants such as sulfur, nitrogen, Conradson Carbon Residue (ConC) and metals also impact the yield and/or product quality. As a result it is often adv antageous to either partially or fully hydrotreat the feedstock to improv e the hydrogen content and reduce the lev el of contaminants. When processing residues containing high lev els of metals (Ni, V and Na) and ConC v alues of 3-10 wt%, more sophisticated FCC designs are required. The reaction section will be designed to inject and efficiently crack heav ier molecules. The regenerator section is 

designed to burn more coke, minimize catalyst deactiv ation in the presence of high metals loading on the catalyst, and control the heat balance by using a two-stage regenerator design (R2R). For expanded product flexibility, the RFCC unit can be integrated with upstream units such as resid hydrotreating/hydrocracking to balance the gasoline and distillate products, or downstream units such as Polynaphtha (FlexEne™concept) in order to offer higher flexibility toward targeted products (Gasoline, Diesel or Propylene).

Diesel Hydrotreating Unit (DHDT) Objective : To meet the Euro –III/IV diesel quality requirement ( 350/50 ppm‘S’and Min. 51 Cetane No.)  Feed : Straight run diesel / FCC diesel component/ Coker and Visbreakerdiesel components.  Catalyst : Ni-Mo oxides  Chemical reactions: Desulphurisation and Denitrification In Dieselhydrodesulfurization / hydrotreating process, diesel feed is mixed with recycle Hydrogen ov er a catalyst bed in a trickle bed reactor at temperature of 290-400°C and pressure of 35-125 bar. The main chemical reactions in DHDS/DHDTare hydrodesulphurization(HDS), hydrodenitrification (HDN), and aromatic and olefin saturation. These reactions are carried on bifunctional catalysts. Reactor effluent is separated into gas and liquid in a separator. Gas is recycled back to the reactor after amine wash along with make-up Hydrogen and liquid is sent to the stripper for remov al of light gases and H2S. Advantages:  Indigenous Process design& technology • Capable of producing ultra low Sulfur meeting BS-IV diesel specifications

• Proprietary Reactor internals. • Competitiv e with foreign licensors • Proprietary DHDS/DHDT catalyst system so as to offer a complete package. • Design and Engineering experiences of EIL

Sulphur Recovery Unit (SRU) Sulphur remov al facilities are located at the majority of oil and gas processing facilities throughout the world. The sulphur recov ery unit does not make a profit for the operator but it is an essential processing step to allow the ov erall facility to operate as the discharge of sulphur compounds to the atmosphere is sev erely restricted by env ironmental regulations. The basic Claus unit comprises a thermal stage and two or three catalytic stages. Typical sulphur recov eries efficiencies are in the range 95-98% depending upon the feed gas composition and plant configuration H2S + 1½O2 > SO2 + H2O (1) 2H2S + O2 3/x Sx + 2 H2O (2) Some of the H2S in the feed gas is thermally conv erted to SO2 in the reaction furnace of the thermal stage according to reaction (1). The remaining H2S is then reacted with the thermally produced SO2 to form elemental sulphur in the thermal stage and the subsequent catalytic stages according to reaction (2). Claus reaction (2) is thermodynamically limited and has a relativ ely low equilibrium constant for reaction (2) ov er the catalytic operation region. As the feed acid gas normally contains other compounds, which could include carbon dioxide, hydrocarbons, mercaptans and ammonia, the actual chemistry in the furnace is v ery complex.

 The hot combustion products from the furnace at 1000- 1300°C enter the waste heat boiler and are partially cooled by generating steam. Any steam lev el from 3 to 45 bar g can be generated.  The combustion products are further cooled in the first sulphur condenser, usually by generating LP steam at 3 – 5 bar g. This cools the gas enough to condense the sulphur formed in the furnace, which is separated from the gas and drained to a collection pit.  In order to av oid sulphur condensing in the downstream catalyst bed, the gas leav ing the sulphur condenser must be heated before entering the reactor.  The heated stream enters the first reactor, containing a bed of sulphur conv ersion catalyst. About 70% of the remaining H2S and SO2 in the gas will react to form sulphur, which leav es the reactor with the gas as sulphur v apour.  The hot gas leav ing the first reactor is cooled in the second sulphur condenser, where LP steam is again produced and the sulphur formed in the reactor is condensed.  A further one or two more heating, reaction, and condensing stages follow to react most of the remaining H2S and SO2.  The sulphur plant tail gas is routed either to a Tail Gas treatment Unit for further processing, or to a Thermal Oxidiser to incinerate all of the sulphur compounds in the tail gas to SO2 before dispersing the effluent to the atmosphere

MSQ UNIT It consists of: 1. PRIME G+ 2. NHDT 3. ISOM

Prime G+ The Prime-G+ process relies on unriv alled expertise to prov ide the most appropriate catalytic solution based on simple and robust designs that can achiev e the following targets:  Very high desulfurization rate with good octane retention 

Excellent gasoline yield retention without RVP increase (no cracking reactions)

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Minimum hydrogen consumption

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High operational reliability through a tailor-made conv entional hydrotreatment

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Low capital cost inv estment through a simple fixed bed technology

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High catalyst cycle length that keeps the unit running 100% of the FCC turnaround

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Fully regenerable catalysts (in-situ or ex-situ) at low contaminant lev els

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Ability to co-process other sulfur-rich streams such as light coker, v isbreaker, straight run or steam cracker naphthas

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Ability to retrofit existing assets Axens Prime-G+ offer is particularly flexible allowing different process configurations (schemes with or without splitter, 1st stage or 2nd stage selectiv e HDS unit) to best fit the gasoline pool requirement and also maximize refinery profitability. Although the naphtha splitter may be optional depending on the required HDS sev erity, the preferred arrangement for minimization of octane loss is a scheme with the association of a Prime-G+ selective hydrogenation unit (SHU) and a splitter, the so called the "Prime-G+ 1st Step" for light naphtha desulfurization and sweetening. It ideally complements the selectiv e HDS on the heav ier fraction that outperforms all other processes.

All Prime G+ catalysts present a low sensitivity to impurities and excellent stability suitable for the processing of cracked feedstock due to their optimized metal content and highly neutral carrier. Specific grading materials dev eloped by Axens are often installed at the top of reactor catalytic beds in order to extend catalyst cycle lengths when processing highly reactiv e cracked feedstocks. Depending on the crude, FCC gasoline can contain arsenic which is a poison for all hydrotreatment catalysts. In the case of sev ere contamination, Axens can offer to install as part of the grading material a dedicated trapping mass which deliv ers v ery high arsenic retention without olefin saturation to preserv e the octane of the desulfurized FCC gasoline product.

Selective Hydrogenation Unit (SHU) Unsaturated LPG cuts from FCC and coker or Steam Cracking units contain unwanted dienes and/or acetylenes that need to be remov ed before further treatment. It’s used for upgrading unsaturated LPG cuts; by conv erting butadiene and MAPD, it greatly enhances the performance of downstream units. Here treatment of unsaturated LPG is required. Depending on the downstream utilization of LPG cuts it can be used  at low sev erity for selectiv e butadiene/MAPD hydrogenation  at higher sev erity to promote Hydroisomerization of 1-butene to 2butene. Whatev er the application, special attention is paid during design to minimize losses of v aluable olefins. A series of catalysts is av ailable to ensure high activ ity and optimum selectiv ity throughout the run cycle. It is important to make the

choice of catalyst in conjunction with the contaminants (e.g. sulfur) that are often present in cracked feedstock. This technology can be used to treat C3, C4 or combined C3 and C4 olefinic cuts.

Naphtha Hydrotreatment Unit (NHDT) Naphtha hydrotreatment is important steps in the catalytic reforming process for remov al of the v arious catalyst poisons. It eliminates the impurities such as sulfur, nitrogen, halogens, oxygen, water, olefins, di olefins, arsenic and other metals presents in the naphtha feed stock to hav e longer life catalyst.. * Sulphur: Mercaptans, disulphide, thiophenes and poison the platinum catalyst. The sulphur content may be 500 ppm. *Maximum allowable sulphur content 0.5 ppm or less and water content