gomey iocl

Vocational Training Report

Chemical Engineering Department

Sardar Vallabhbhai National Institute of Technology

AMIT KUMAR GOMEY

U12CH026

Training Period:

15 June- 11 July 2015

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CERTIFICATE FROM COMPANY

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ACKNOWLEDGEMENT

I’m immensely thankful to Mr. Hemant Bhati, Senior Instrumentation Engineer, IOCL

Digboy to give me opportunity to interact with professionals at the IOCL Gujarat Refinery

plant, Vadodara. I thank my mentor and guide Mr. M M Parmar (CPMN) and all other

employees to guide me throughout the training course and helping me to understand the

working of various units, their processes and equipment etc. I would like to thank my

college to motivate me to undergo the training.

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TABLE OF CONTENTS

CERTIFICATE FROM COMPANY…………………..1

ACKNOWLEDGEMENT .................................................... 2

INTRODUCTION .................................................................. 5

COMPANY OVERVIEW..................................................... 6

AU (ATMOSPHERIC UNIT) V – INTRODUCTION .. 7

CHAPTER 1: AU V – PROCESS DESCRIPTION ........ 8

1.1: CRUDE CHARGING INTO UNIT ............................ 10

1.2: FURNACE ...................................................................... 13

1.3: MAIN FRACTIONATING COLUMN ....................... 14

1.4: PRODUCT STRIPPERS .............................................. 17

1.5: HEAVY NAPHTHA STRIPPER ................................. 17

1.6: KERO/ATF STRIPPER ................................................ 18

1.7: NAPHTHA STABILISER ............................................. 19

1.8: LPG-AMINE ABSORPTION SECTION .................. 19

1.9: CHEMICAL INJECTION FACILITIES ................... 20

CHAPTER 2: DEMAND AND SUPPLY DATA ......... 23

2.1: FEED: CRUDE ............................................................. 23

2.2: PRODUCTS ................................................................... 24

Specification ........................................................................... 24

Value ........................................................................................ 24

2.3: PRODUCT AND THEIR END USES ....................... 26

MARKETING – REACH IN EVERY PART OF INDIA . 27

CHAPTER 3: Pumps and Valves ...................................... 28

3.1: PUMPS ............................................................................ 28

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3.2: VALVES ........................................................................... 31

CHAPTER 4: LINE SIZING .............................................. 42

CHAPTER 5: INSTRUMENTATION POWER SYSTEM 44

CHAPTER 6: SAFETY MEASURES ADOPTED ....... 45

6.1: FIRE PREVENTION ACTIVITIES: .......................... 45

6.2: SOUND ENGINEERING: ........................................... 45

6.3: GOOD HOUSE KEEPING: ....................................... 45

6.4: INSTRUCTION TO PERSONNEL ............................ 45

6.5: REGULAR TRAINING OF EMPLOYEES .............. 45

6.6: FIRE PROTECTION SYSTEM IN THE UNIT ....... 46

6.7: WORK PERMIT SYSTEM ........................................... 46

6.8: CORRECTIVE ACTION TO BE TAKEN TO PREVENT HAZADOUS SITUATION FROM

ESCALATING ........................................................................ 49

6.9: SAFETY SYSTEM AND THEIR FUNCTIONS ....... 50

CHAPTER 7: ENVIRONMENTAL ISSUES ................ 52

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INTRODUCTION

Indian Oil Corporation (Indian Oil) is India’s largest

Commercial enterprise, with a sales turnover of Rs. 4,

50,756 crores (US$ 73.7 billion) and profits of Rs. 5,273

crores for the year 2014-15. It is also the leading Indian

corporate in Fortune’s prestigious 'Global 500' listing of

the world’s largest corporates, ranked at the 96th

position for the year 2014.

As India’s flagship national oil company, with a

33,000- strong work-force currently, Indian Oil has been

meeting India’s energy demands for over half a century.

With a corporate vision to be 'The Energy of India' and

to become 'A globally admired company,' Indian Oil’s

business interests straddle the entire hydrocarbon value-

chain – from refining, pipeline transportation and

marketing of petroleum products to exploration & production of crude oil & gas, marketing

of natural gas and petrochemicals, besides forays into alternative energy and globalization

of downstream operations.

IndianOil accounts for nearly half of India’s petroleum products market share, 31%

national refining capacity (together with its subsidiary Chennai Petroleum Corporation

Ltd., or CPCL), and 71% downstream sector.

The IndianOil Group owns and operates 10 of India’s 22 refineries with a combined

refining capacity of 65.7 MMTPA (million metric tonnes per annum), i.e., approx. 1.31

million barrels per day. The 15-MMTPA refinery under commissioning at Paradip on the

east coast will raise the capacity to over 80 MMTPA.

The Corporation has a portfolio of leading energy brands that includes Indane LPG

cooking gas, SERVO lubricants, XTRAPREMIUM petrol, and XTRAMILE diesel,

PROPEL petrochemicals, etc. Besides IndianOil, both SERVO and Indane have earned the

coveted Superbrand status.

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COMPANY OVERVIEW

The Gujarat Refinery is an oil refinery located at Koyali (Near Vadodara) in Gujarat,

Western India. It is the Second largest refinery owned by Indian Oil Corporation after

Panipat Refinery. The refinery is currently under projected expansion to 18 MMTPA.

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 refinery’s facilities include five atmospheric crude distillation units. The major

secondary units include:

1. Catalytic Reforming Unit (CRU),

2. Fluidized Catalytic Cracking Unit (FCCU) and

3. The first hydrocracking unit of the country.

Through a pipeline to Ahmedabad and a pipeline connecting to the BKPL pipeline and also

by rail and truck, the refinery primarily serves the demand for petroleum products in

western and northern India. When commissioned, the refinery had an installed capacity of

2 MMTPA and was designed to process crude from Ankleshwar, Kalol and Nawagam

oilfields of ONGC in Gujarat. The refinery was modified to handle imported and Bombay

High crude. The refinery also produces a wide range of specialty products such as benzene,

toluene, MTO, food grade hexane, solvents and LABFS. The Gujarat Refinery is the first

refinery in India to have completed the diesel hydrodesulphurization project in June 1999,

when the refinery started production of HSD with low sulfur content of 0.25% wt. (max).

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AU (ATMOSPHERIC UNIT) V – INTRODUCTION

The atmospheric Unit AU-V of Gujarat Refinery is designed to process 3.0 MMTPA

of Arab Mix Crude (50:50 by weight of Light and Heavy Arab Crude).

This unit was commissioned in the year 1997.

The unit was revamped during August/Sept ’02 to increase the on stream factor and

flexibility of operation by providing additional heat exchanger train and increase in the

number of pumps for different products & circulating refluxes.

The unit comprises of:

Crude Preheat Train,

Crude Desalting,

Atmospheric Distillation,

Naphtha Stabilization,

LPG Amine wash and Caustic wash,

Light Naphtha Caustic wash, and

Kerosene/ATF caustic wash.

The main products from the unit are:

LPG,

Light Naphtha,

Heavy Naphtha,

Kerosene,

Gas Oil and

Long residue.

Provision is also there for with drawl of ATF (boiling range 140-240) during alternate

mode of operation. During ATF mode of operation Kerosene will not be withdrawn and

the material boiling in the range of 240-370° C will be withdrawn as Gas Oil stream.

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CHAPTER 1: AU V – PROCESS DESCRIPTION

In Atmospheric Unit, Crude Oil is separated into various fractions in fractionation column

based on relative volatility, boiling point and condensation temperature ranges of the

various components. These fractions have different properties. Most of them are lighter

then crude accepting the bottom product LR (Long Residue).

Basic operations involved in AU are as follows:-

Crude Preheating and Desalting

Crude heating in Charge Heater

Atmospheric Distillation

Naphtha Stabilization

LPG Amine and Caustic washing

Light Naphtha Caustic washing

Kero/ATF Caustic washing

For the sake of simplicity in process description, Atmospheric Unit is divided into a

Number of subsections as given below:

Crude Preheat Train I (old and new)

Crude Desalter

Crude Preheat Train II (old and new)

Crude Charge Heater

Atmospheric Distillation Column

Naphtha Stabilizer

Product Cooling and Run Down system

LPG Amine wash system

LPG Caustic wash system

Light Naphtha Caustic Wash system

Kero/ATF Caustic wash system

Chemical Injection system.

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Flow Diagram of AU-V

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1.1: CRUDE CHARGING INTO UNIT

Crude from crude storage tanks in GRE crude offsite area is pumped into Atmospheric

Unit. In the battery limit of AU double block valve and a spectacle blind is provided for

positive isolation. Crude is received at 9.5 Kg/cm2 g pressure and ambient temperature.

The following instruments are provided in the crude inlet line to the Unit within Unit

battery limit.

Local pressure gauge

Pressure Transmitter with DCS indication

Crude Booster take suction and deliver crude to the preheat Train-I through a discharge

header. The following connections are provided in the suction line of booster pumps inside

battery limit.

1” Caustic solution line in order to maintain pH of Desalter effluent.

2” demulsifier solution line to break crude and water emulsion.

10” LR circulation line for start-up purpose.

2” service water line for unit flushing.

3” slop line from CBD Pump Discharge for reprocessing the slop.

The crude booster pumps have a capacity of 261 m3/hr. The normal discharge pressure

of crude booster pump is 23.87 Kg/cm2g. Normally two crude pumps will be in operation

and one will remain standby.

1.1-1: CRUDE PREHEAT TRAIN-I

Crude preheat trains are provided to accomplish the following.

To heat the crude oil and bring it to the required desalting temperature.

To further heat the crude oil after desalting.

To recover heat from outgoing products and circulating reflux streams by heating the

crude oil, thereby improving fuel economy in operation at unit.

Crude Preheat Train–I is described below:

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There are total 15 nos. of heat exchangers in this section where crude is preheated

to 135-140 ̊C before going to desalter.

Crude, which is at ambient temperature, goes to the heat exchanger where it is

treated against LGO and heated upto 60 ̊C. Crude is further divided into two parallel

passes with the help of a differential temperature controller DTC (3 way C/V).

Both the passes travel through separate heat exchangers, exchange heat with

products and are heated upto 140 ̊C. Crude from the passes combine together and

goes to desalter.

1.1-2: CRUDE DESALTING

Crude oil brings along with it salts, particularly those of sodium, Magnesium etc.,

metals like Arsenic, Vanadium etc., and mud. Although these are present only in small

amounts, their presence can result in serious problems in downstream equipment’s viz.

Heat exchangers, charge heater and Atmospheric column. Hence the need of their removal

is important before processing.

At high temperatures, Magnesium chloride decomposes and forms Hydrochloric acid,

corroding trays in the top section of column and tubes of overhead condensers etc. The

presence of calcium and sodium salts can cause plugging of heat exchanger and heater

tubes, there by rapidly reducing heat transfer co-efficient. The presence of Arsenic acts as

a poison to platinum catalysts if it is used in downstream process units. Presence of these

salts also promotes coke formation in heater tubes which results in increased pressure drop

as well as less heat transfer rates. The excessive coke formation results in escalation of hot

spots on heater tubes which can have serious and disastrous consequences for heater tubes.

At high temperature salts in crude oil show a tendency to deposit along heat exchange

surface of the equipment.

Caustic injection upstream of Desalter in crude is done to neutralize acids present in

crude and convert them into water solvable salts. These salts are then removed by desalter

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water in desalter. Caustic injection downstream Desalter is provided to neutralize any other

acid traces formed at desalter operating conditions.

Brine is associated with crude both as a fine suspension of droplets and more permanent

emulsion. To break this tight emulsion, Demulsifier is added. This ensures better function

of Desalter. Demulsifier is injected into crude upstream of desalter. Provision also Exists

for injection of Demulsifier into the crude line at B/L for better mixing.

In fact, both caustic solution and Demulsifier are added into the crude before the first

exchanger in the preheat train I. Process is described below:

The desalting process consists of three main stages-heating, mixing and separation.

For effective separation of salt and water from crude oil, it is heated upto about

140 ̊C thoroughly mixed with extra water (3-4% on crude flow) by passing through

mixing valve at the inlet of desalter (mixing valve pressure drop is generally kept

at about 1.0 kg/sq.cm).

The extra water is added to collect and dissolve all the water soluble salts in the

crude.

The rate at which water is injected into the crude is dependant primarily upon the

salt and BS&W content of crude being treated.

In some instances, it is not possible to achieve sufficient mixing across the mixing

valve alone; provision is therefore given to inject water ahead of desalter heat

exchangers. This water is preheated to 100 ̊C.

The mixing valve, with isolation and bypass facility, is located at the inlet of the

desalter. By varying pressure drop across the valve the desired mixing can be

achieved. The normal operating pressure is 10.5 to 11.0 kg/sq.cm(g).

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1.1-4: CRUDE PREHEAT TRAIN – II

Crude preheat train–II is desalter outlet to crude charge heater (05-FF-01). Major

equipment at this section are shell and tube type heat exchangers. Crude preheat train – II

can be subdivided to crude preheat train – II (old) and Crude preheat Train – II (New).

Booster pump pumps crude from desalter outlet to one of the heat exchangers where

crude is treated against Kero CR.

At outlet, the crude flow is divided into two parallel passes by DTC. Crude in both

the passes exchanges heat with LGO and RCO respectively. Both the passes

combine in the end where the crude temperature is around 175 ̊C.

The two passes that combine are again divided into two passes, and is treated

against HGO CR. LGO CR and HGO.

Crude after passing through a series of heat exchangers is fed to the flash zone of

pre-fractionator column at a temperature of 225 ̊C.

1.2: FURNACE

Major equipment of this section is atmospheric heater, air pre-heaters, ID fan, FD fans

and Steam air decoking pot.

In the heaters, crude is further heated and partially vapourised by rising temperature

from 275-370 ̊C in case of imported and upto 355 ̊C in case of BH/SG crude.

Here, furnace is a box type, horizontal tubes, balanced draft furnace. Crude feed

flows to the heater in four passes. The four passes join together and combine at the

outlet to go to the distillation column. There are total 20 nos. of dual (oil and gas)

fired burners and one gas burner in the heater.

Fuel oil pressure of 6.0 kg/sq.cm is maintained by the controller. The atomizing

steam pressure to the burners is controlled by differential pressure controller.

Fuel gas is supplied to the heater at about 3.4 kg/sq.cm.

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If fuel gas pressure falls below 1.8 kg/sq.cm low pressure alarm will sound in the

control room and a safety shutdown valve SDV will automatically cut off fuel gas

flow to the heater, thus eliminating the possibility of back fire.

A return is provided on the fuel oil heater. A 1:1 ratio of fuel oil consumption to

return is provided in the design to obtain a good control on firing and prevent

congealing of the internal fuel oil (IFO) system.

The globe valve provided on the IFO return line should be adjusted to give the

desired circulation rate. For recovering heat from fuel gases, boiler feed water is

circulated through BFW coils at convection section.

1.3: MAIN FRACTIONATING COLUMN

The crude after final heating in furnace is fed to the Atmospheric Column for separation

of products by fractionation. Atmospheric column contains 51 valve type trays for side

stream withdrawal. The column has a stripping section at the bottom. It has lower diameters

at top and bottom sections than middle to cater to higher vapor load in middle section.

Local pressure gauges and DCS mounted TI are provided to indicate pressure/temperature

profile inside the column.

Description of entire column has been taken up zone wise below:

1.3-1: FLASH ZONE

Heated and partly vaporized crude feed coming from fired heater enters the flash zone

of the column above tray no.6 at 375 C. Hydrocarbon vapors flash in this zone and get

liberated. Non-flashed liquid moves down ward, which is largely bottom product, called

Long Residue. Certain degree of over flashing of crude is desirable for proper stabilization

of LR and fractionation of gas oil components. Over flash is achieved by setting up COT

at slightly higher than actually required. This over flashed material is washed with gas oil

coming down from below of 15th tray. It strips out heavier vapor components coming up

which otherwise would move-up & cause coloration of gas oil stream. Tray 7th to 14th forms

the wash zone section of atmospheric column along with LR. Flow of over flash liquid can

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be increased by both increasing COT and condensing more material on 7th tray gas oil draw

off. However, this will result in less gas oil yield and higher energy consumption without

any advantage. Too large flow of over flash liquid may result in drop in bottom temperature

and lighter bottom product, LR.

1.3-2: OVERHEAD SECTION

The overhead vapors of Atmospheric Column at 1120 C/1150 C passes through the

overhead air condensers (Fin fan cooler) and trim condenser. The condensed Naphtha &

steam are accumulated in crude column overhead reflux drum.

Condensed hydrocarbons are allowed to settle in reflux drum where steam condensate

settles in vessel boot and is pumped to desalter water drum or sour water stripper of SRU

unit under inter phase controller. Sour water flow is measured by FI-1801 & its pH is

indicated by PHI-1601. On actuation of boot level alarm low shall be closed by operation

and the flow has cut off. A part of accumulated hydrocarbons is pumped back to

atmospheric column as top reflux by Column reflux pumps under flow control to control

top temperature. This flow controller can be cascaded with atmospheric column top

temperature controller for precise control of column top temperature.

Ahuralan is dozed at the top of column to arrest corrosion and ammonia solution is

dozed O/H vapor outlet line to maintain sour water PH level @ 6 to 6.5. Excess quantity

of Naphtha in reflux drum is pumped by stabilizer feed pumps to stabilizer as feed.

Reflux drum level controller can be cascaded with discharge of stabilizer feed pump flow

controller.

Minimum flow protection controllers are provided for discharge of reflux pumps &

stabilizer feed pumps respectively. In the event of low flow in reflux or stabilizer feed lines

due to throttling of control valves, minimum continuous flow to each pump, this

arrangement prevents heating of pump due to closed discharge operation & resultant

damage to pump.

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1.3-3: MIDDLE SECTION:

Middle section of the column has circulating refluxes and product withdrawal network.

In order to maximize heat recovery and balance the column loading for maintaining proper

temperature profile across the column, three circulating refluxes (CR) systems are provided

viz. Heavy Naphtha CR, Kero/ATF CR, and Gas Oil CR. These circulating refluxes are

drawn from their respective product draw off trays and are routed to preheat recovery trains

for heat recovery before entering back to the column again.

Duty controllers are provided on CR circuits to control CR flow rates to column. These

duty controllers take corrective action based on actual CR duty & desire CR duty. For a

particular type of crude and crude through put, the CR under reference will have certain

duty. This will be governed by total crude flow and specific heat of CR and is called desired

CR duty. Actual CR duty is also computed by duty controller based on real time

measurement of temperature difference between CR draw off and CR return stream, CR

flow rate and specific heat of CR. Total crude flow, CR temperature difference and CR

flow are measured by various instruments. Specific heat of CR is fixed by operator in

software for computation purpose and no on line measurement for this property is

available. Actual and desired CR duty is calculated in the duty controller as under:

Actual CR duty = (Measured CR flow)X(CR temp. Difference)X(sp. Heat of CR

stream)

Desired CR duty = (Desired CR duty/Desired total crude Flow)X(Actual Crude

flow)

Inputs to be manually configured by operator are specific heat of CR stream and ratio

(Desired CR duty/ desired total crude flow) for each crude. Desired CR duty should be

estimated on pro-data feed rate basis to CDU. This is typical to all such duty controllers on

circulating reflux lines. Desired CR duty is compared with actual CR & the flow of CR is

varied to achieve desired CR duty.

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1.3-4: BOTTOM SECTION (RCO CIRCUIT)

Long Residue product is collected at bottom of the column. Column bottom level is

indicated and controlled by level controller. Column bottom level control can be done

either by manipulating LR flow to FPU/Storage during normal operation or by

manipulating LR flow. LR at a temperature of 365 C is pumped out from the bottom of the

column by LR pumps to LR Storage (or) FPU Independent level control with high & low

level software alarm is provided to have redundancy of indication. Selector switch is also

provided for cutting the LR flow to LR Storage/FPU when the atmospheric column level

is low. A low level switch along with alarm is also given. Bottom temperature and LR

pump suction temperature are indicated by temperature indicator.

1.3-5: CIRCULATING REFLUXES/PUMP AROUND CIRCUITS

Three circulating refluxes are described below.

(1) Top CR (2) Kero CR (3) G.O. CR.

(1) Top CR – Drawn from tray – 43 to pumps @ temp ~ 150° C discharge to exchangers

tube side tube outlet stream returns back to column.

(2) Kero C.R. - Drawn from tray 25 to pumps @ temp 200° C to 220° C.

(3) G.O. CR - Drawn from tray-16 to pump at temperature ~ 300° C to 315° C.

1.4: PRODUCT STRIPPERS

There are three side strippers for stripping out side draw off products from atmosphere

column, viz. Heavy Naphtha, Kero /ATF and GO.

They are described as under:

1.5: HEAVY NAPHTHA STRIPPER

Ten valve type trays are provided in HN stripper. Local PG and LP steam connections

are also provided on this stripper. LP steam is used to purge the column. HN to be stripped

is admitted on 10th tray under its level control. Minimum 1500 mm elevation difference is

provided between stripper entry nozzle and piping to provide back pressure and prevent

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flashing in piping. HN in bottom is re-boiled in re-boiler by HGO C/R. HN is stripped off

by its hot vapors generated in re-boiler. Mass transfer between down coming HN liquid

from tray 10 to bottom and uprising HN vapors takes place on each tray. Finally stripped

HN is drawn by pumps and sent to product cooling section. Outgoing HN temp. Is indicated

by. Stripped light vapor goes back to 36th tray of atmospheric column.

Gas oil CR supplies heat to Heavy Naphtha Stripper Re-boiler. Pumps get suction from

bottom of column.

1.6: KERO/ATF STRIPPER

Six valve type trays are provided in Kero/ATF stripper. Local PG and LP steam out

connections are also provided on this stripper. Kero/ATF to be stripped is admitted on 6th

tray of KERO/ATF stripper under its level control. Minimum 1500 mm elevation

difference is provided between stripper entry nozzle and piping to provide back pressure

and prevent flashing in piping. MP steam is used as stripping medium in this stripper.

Steam flow is regulated by FIC-1508 on steam line. It regulates MP steam flow to stripper

based on per unit mass of Kero/ATF product outflow.. Steam to product ratio is decided

by operator and configured in software for routine control. MP steam reduces partial

pressure of hydrocarbon components inside stripper and helps them vaporize at relatively

low temp. Mass transfer between down coming Kero/ATF liquid from tray 6 to bottom and

uprising vapors takes place on each tray. Finally lighter end stripped Kero/ATF is drawn

by pumps and sent to preheat train I for exchanging its heat to crude. It is further cooled in

cooler before routing to caustic wash system. Provision is made for Pump getting suction

from same suction header of pump, which discharges to cooler Outlet of both the circuits’

joins together & flows to caustic wash system. Stripped light vapors goes to 28th tray of

atmospheric column.

Design data: salt to load: 61 Mt.

Inlet moisture: 1300-1500 ppm.

Outlet moisture: <200 ppm

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1.7: NAPHTHA STABILISER

Naphtha obtained in atmospheric column overhead Naphtha reflux drum contains some

light ends like C3 and C4, which vaporize at normal atmospheric conditions. This naphtha

if stored as such in storage tanks will release lot of hydrocarbon vapors and can create

unsafe conditions and pressurization of the storage. To avoid these problems, the lighter

components from naphtha are removed. This process is called Naphtha stabilization.

Naphtha stabilization is carried out in naphtha stabilizer where C1/C2/C3 and C4

hydrocarbons are removed from naphtha. Stabilizer column has 43 nos. of valve type trays.

The column is provided with a set of safety valves set at 15-kg/cm2 g. Their discharge is

routed to flare header. MP steam connection is provided for steam purging of the column

during shut down. DCS mounted temperature indication of top outlet; tray 38, tray 5 and

bottom outlet are provided. Local PG at tray 43, and below tray I is also provided to monitor

pressure profile in the column.

Un-stabilized naphtha feed to the stabilizer is first heated up to 119 0 C in feed/

Stabilizer Bottom Exchanger parallel by exchanging heat with outgoing stabilized naphtha

product stream from stabilizer bottom. Feed from drum enters the column on the 20th tray

under flow control that is normally cascaded with level controllers. Local PG, TG and TI-

are also provided on feed line to monitor feed temperature pickup.

1.8: LPG-AMINE ABSORPTION SECTION

LPG mixture from Naphtha Stabilizer reflux drum is sent to LPG surge drum. Sour LPG

from outside battery limit (from AU4 (or) AU-3) also joins at downstream. The surge drum

pressure is maintained at 10.0 Kg/cm2, releasing to fuel gas system i.e. upstream of FG

K.O. Drum. The level of the surge drum should always be maintained at 50%.

The LPG from the surge drum is pumped by the LPG booster pumps to the bottom of

LPG Amine absorber column under flow control.

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1.9: CHEMICAL INJECTION FACILITIES

Hydrochloric acid from the salt in the crude and hydrogen sulphide dissolved in the

crude (or formed from the dissociation of heavy Sulphur compounds present in crude)

concentrates in the overhead system. Both form of acid solutions, which are corrosive.

Measures must be taken to overcome their effects. The overhead system including

condensers and reflux drum is made of carbon steel. In order to protect this section, caustic

solution, ammonia solution and corrosion inhibitors are added at various points. The

purpose of injection caustic at the outlet of desalter is to achieve better mixing of these

chemicals with crude and neutralize the acids and salts, mainly HCL and H2S as soon as

they are formed (at a temp. Of 120 C and above) the reaction products i.e. sodium and

ammonia salts go along with reduced crude. The balance acids and acid gases if any will

go up to the overhead system where ammonia is injected in the overhead vapor line to

neutralize. Amount of ammonia should be controlled in such a way that pH of reflux drum

water remains at 6.5±0.2.

Injection of caustic at the outlet of desalter should be maintained in such a way that the

salt formation should be low in the overhead circuit, which might scale up the overhead

condenser tubes.

A slightly acidic condition of the overhead system is desirable to keep ammonium salts

in solution, which if precipitates would foul and plug the condensers. Corrosion against

slightly acidic conditions is minimized by adding corrosion inhibitors in the overhead

vapor line. The inhibitor is also added in reflux line. Top section of the column is also

benefited from the injection of corrosion inhibitors mainly in the reflux line. These

inhibitors are high boiling compounds and can perform satisfactorily at higher column top

temperature also.

The amount of inhibitor injected depends upon the type of inhibitor used and generally

specified by the vendor. However slight adjustment is made by operating personal

depending upon iron content in the reflux drum water. These inhibitors are filming organic

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compounds, which cover entire metal surface of the system with a thin film. This prevents

contact of corrosive water with metal surface.

Various points of chemical injections are listed below:

De-emulsifier De-emulsifier is injected in the crude pump suction to break oil and water emulsion

in desalter. Normal injection rate is 4 to 5 ppm. However, if oil is observed in

desalter drain water, de-emulsifier injection rate has to be increased.

De-emulsifier chemical is brought in drums and offloaded into the vessel. The de-

emulsifier injection pumps are dosing pumps provided with a safety valve. The rate

of injection can be varied by adjusting the knob on the pump.

Caustic Solution

Caustic is injected in the crude pump suction, as water separation from oil in

desalter becomes better in alkaline medium. For this, brine water pH is maintained

at about 8.0 to 9.2. 3% wt caustic solution is prepared in the tank and injected by

pump.

At the desalter also, the same caustic is injected to neutralize the chloride salt. The

chloride salt in the crude produces HCl (Hydrochloric Acid) at higher temperature.

This HCl is highly corrosive to column overhead, vapour line and the reflux drum.

Hence, caustic is injected to neutralize HCl to NaCl (sodium chloride).

Finally NaCl goes out from bottom of the main fractionator along with RCO. Any

left over HCl vapour goes to the top and finally comes along with sour water.

Hence, if sour water chloride contents are reported more than 6 ppm, caustic

injection post desalter has to be increased. Also sour water pH is to be maintained

at 6.5 to 7.0 with the help of ammonia injection.

Ammonia Injection

Ammonia solution is injected in the crude fractionating column overhead and in

pre-fractionator column to neutralize highly corrosive acid HCl.

22 Page

Ammonia converts HCl to ammonium chloride (NH4Cl). About 1% strength

ammonia solution is injected in the top vapour line and in the top reflux line.

It is very important to know that the use of excessive ammonia will cause leak in

the overhead condenser tubes. This is because ammonia reacts very fast with the

brass metal and eats away the metal.

Hence, sour water pH to be maintained strictly not more than 6.5. Ammonia is

brought in the unit in cylinders. Water is received in the two solution vessels.

Ammonia solution is prepared by injection of ammonia from ammonia cylinder

into the solution vessel. A pressure gauge and safety valve are provided on the

ammonia connection manifold.

To prevent cooling and icing of the cylinders when preparing ammonia solution, a

connection to spray water is provided. The solution vessels are provided with seal

to minimize the loss of ammonia.

Corrosion Inhibitor Injection

Corrosion inhibitor is an organic chemical. It acts as corrosion inhibitor by forming

continuously a monomolecular layer on the metal surfaces, by direct contact

between metal and the corrosive elements present in the system.

This is injected at the top f the vapour line of the crude fractionating column overhead and in the stabilizer column to protect vapour line and condenser.

Normal injection rate of 4 to 6 ppm is maintained by the pump.

23 Page

CHAPTER 2: DEMAND AND SUPPLY DATA

2.1: FEED: CRUDE

a) 100% Arab mix Crude consisting of Light and Heavy Arab Crude in 50:50

proportion by weight.

b) Main Column along with overhead condensers and furnace have flexibility to

process 3.0 MMTPA Arab mix crude in 50:50 weight proportion with respect

to flow and hydraulics alone.

The properties of Arab Crude mix are as follows:

Sr.

No.

Specification Unit Value

1. Specific gravity @15 oC 0.8728

2. TBP Distillation (%

volume)

oC

3 IBP oC 27.3

4 5 oC 52.9

5 10 oC 97.2

6 30 oC 223.0

7 50 oC 344.4

8 70 oC 476.8

24 Page

9 90 oC 658.3

10 95 oC 709.3

11 EP oC 732.2

12 API Gravity oC 30.6

13 Viscosity @37.8 oC Cst 10.5

14 Pour Point oC -124

15 RVP@38 oC Kg/cm2 0.6

16 Salt content(max) Ppm 165

17 BS&W %Vol 2.0

2.2: PRODUCTS

Sr.No. Product Specification Value

1. O/H Naphtha TBP cut oC IBP-170 oC

2. Heavy

Naphtha

TBP cut oC 120-170 oC

3. ATF

TBP cut oC

Flash Point oC

Freezing point oC

ASTM D-86 EP

140-240

38 (min)

-50 (max)

288 oC

25 Page

4. SKO TBP cut oC

Flash Point oC

ASTM D-86 EP

140-270

36 (min)

300 (max)

5. Gas Oil TBP cut oC

Flash Point oC

ASTM D-86 95%

240/270-370

34 (min)

Not to exceed 365oC

6. Long residue TBP cut oC Shall not contain

more than 8% vol

(max) of material

boiling below 370 oC

7. LPG Vapor pressure 6.5

Kg/cm2

Weathering oC

Not more than 16.87

Kg/cm2

95% vol to contain no

more than 2% of C5+

component.

26 Page

2.3: PRODUCT AND THEIR END USES

PRODUCT END USES

LPG Cooking Gas (marketed as ‗INDANE‘)

Benzene Raw material for petrochemicals

Toluene Raw material for petrochemicals

Naphtha Raw material for petrochemicals

Motor Spirit (90 Octane) ‗Petrol‘ for vehicles

Aviation Turbine Fuel (ATF) Fuel for jet aircraft

Superior Kerosene (SK) Illuminant, domestic purpose

High Speed Diesel (HSD) Diesel locos, trucks, buses, ships

Light Diesel Oil (LDO) Small engines attached to irrigation pumps

Low Sulphur Heavy Stoke (LSHS) Fuel in thermal power stations

Fuel Oil (FO) Industrial Furnaces/Boilers

Bitumen Road surfacing

n-Heptane As solvent

ARO Used in aluminium rolling industries

Linear Alkyl Benzene (LAB) Detergent Manufacture

Butene Co-polymer 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 foot wear

Polymerization reactions in industries like

27 Page

Pharmaceuticals & printing ink.

Retreading of car tyres

Sulphur Sulphuric acid and tyre manufacture

MARKETING – REACH IN EVERY PART OF INDIA

Over 41,600 touch points (51.5% of industry)

Cross country retail network comprising of 23,993 (45.9%) outlets

Continued Rural thrust: 6,002 Kisan Seva Kendras

LPG supply to over 81 million households with over 7,000 (50.6%) LPG distributorship

Reaching the doors of bulk customers: Bulk Customer Pumps 6,359(86.0%)

Growing oil Demand

28 Page

CHAPTER 3: Pumps and Valves

3.1: PUMPS

Pump

No

PA

Service KW Rated

Amps

Capacity

M3/hr.

max

DP

Kg/cm2

1A to E Crude Feed 240 25 287 16

2A to E Desalted Crude 300 31 310 22

5A/B/C Top Reflux 45 75 146 11

6A/B/C CC-05 Feed 75 126 79 20

29 Page

7A/B Top CR 37 62 242 9

8A/B HN r/d 30 52 18 15

9A/B Kero r/d 75 126 124 17

10A/B/C Kero CR 75 126 358 10

11A/B GO r/d 75 126 125 14

12A/B/C GO CR 160 260 361 15

14A/B LPG Reflux 22 37 78 14

15A/B Desalter Water Stage-I 15 26 38 17.5

16A/B Desalter Water Stage-II 55 93 38 19

17A/B LPG NaOH Circulation 75 14 36 11

18A/B LPG water wash 75 14 36 12

19A/B LN caustic wash 5.5 10 25 9

20A/B LN water wash 5.5 10 25 13

23A/B Kero caustic wash 7.5 14 34 18

24A/B Kero Water wash 7.5 14 34 17

25A/B LPG Caustic / Water

makeup

18.5 32 5 20

26A/B NH3 Injection 0.37 1.1 7 Lit/hr 8.5

Pump

No

Service KW Rated

Amps

Capacity DP

Kg/cm2

30 Page

PA M3/hr.

max

27A/B Demulsifier Injection 0.37 1.1 11 Lit/hr 11

29A/B Ahuralan Injection 0.37 1.1 24 Lit/hr 10

31A/B Caustic injection 0.75 2.7 410 Lit/hr 15.8

32A/B Caustic Circulation / m- up 11 20 5 11.5

33 47% caustic transfer 3.7 5 3.1

40A/B Wash water make up 11 20 5 10.5

41A/B LN rundown 15 26 58 8

42A/B VV-2 sour water 3.7 7.3 9 6

43A/B Spent caustic 5.5 10.2 10 6.5

44A/B Kero / ATF caustic M/up 15 28 5 19.3

45A/B IFO 45 75 30 15.5

46 CBD 18.5 37 20 6.8

48 ABD 7.5 9.6 6 5

50A/B LPG booster 45 75 37 22

51A/B/C LR 180 19 275 16.8

52A/B Coolant Water 30 50 98 5.5

102A/B Kero-I CR 90 150 371 11

103A/B LGO product 90 150 132 15.1

31 Page

104A/B HGO CR 90 150 470 9

101A/B Kero-I 110 183 106 21.6

Brief description of pressure and temp. Safety valves: -

3.2: VALVES

3.2-1: LIST OF PSV’s

TAG NO. Service LOCATION Set

pressure

Kg/cm2 g

Relieving

Temp ° C

Selection

Basis

PSV1201A/B H/C Desalter-I

stage

16.00 Hold Hold

PSV1202A/B H/C Desalter-II sta 16.00 Hold Hold

PSV-1501 H/C 05-CC-001 4.5 130 Block

discharge

PSV-1502 H/C 05-CC-001 4.5 130 Block

discharge

PSV-1503 H/C 05-CC-001 4.5 130 Block

discharge

PSV-1601 H/C 05-VV-002 4.5 128 Fire

PSV-1602 H/C 05-VV-002 4.5 128 Fire

PSV-1701 H/C 05-CC-005 15 87 Block

discharge

32 Page

PSV-1702 H/C 05-CC-005 15 87 Block

discharge

PSV-1703 H/C 05-CC-003 15 97 Fire

PSV-1704 H/C 05-CC-003 15 97 Fire

PSV-1901 H/C 05-VV-006 29.5 132 Fire

PSV-1902 H/C 05-VV-006 29.5 243 Fire

PSV-1903 H/C 05-VV-007 29.5 132 Fire

PSV-1904 H/C 05-VV-007 29.5 243 Fire

PSV-2001 H/C 05-VV-009 16 205 Fire

PSV-2002 H/C 05-VV-009 16 212 Fire

PSV-2003 H/C 05-VV-0010 16 205 Fire

PSV-2004 H/C 05-VV-0010 16 212 Fire

PSV-2201 H/C 05-VV-013 23 316 Fire

PSV-2202 H/C 05-VV-013 23 230 Fire

PSV-2203 H/C 05-VV-014 23 316 Fire

PSV-2204 H/C 05-VV-014 23 230 Fire

PSV-2501A LPG 05-VV-020 14.5 85 Fire

TAG NO. Service LOCATION Set

pressure

Kg/cm2 g

Relieving

Temp ° C

Selection

Basis

33 Page

PSV-2501B LPG 05-VV-020 14.5 85 Fire

PSV-2601A LPG 05-CC-006 29.5 110 External fire

PSV-2601B LPG 05-CC-006 29.5 110 External fire

PSV-3101 Fuel oil 05-VV-026 3.5 526 External fire

PSV-3102 Fuel oil 05-VV-026 3.5 526 External fire

PSV-3105 HP

steam

05-VV-027 43 266 Fire

PSV-3108 LP

steam

05-VV-035 6.5 173.5 Fire

PSV-3109 LP

steam

05-VV-035 6.5 173.5 Fire

PSV-3201 LPG 05-VV-029 14.5 96 Fire

PSV-3202 LPG 05-VV-029 14.5 96 Fire

PSV-3203 FG 05-VV-020 14.5 60 Fire

PSV-3204 FG 05-VV-020 14.5 60 Fire

PSV-

43002A/B

Inst Air 05-

VV0037A/B

9.0 186.6 Fire

PSV-4401 MP

Steam

05-MD-001 15 285 C/V failure

PSV-4402 MP

Steam

05-MD-001 15 285 C/V failure

PSV-0000 HC Salt dryer 16 Ambient

34 Page

PSV-0000 HC Salt dryer 16 Ambient

3.2-2: LIST OF TSV’s

TAG.NO SERVICE LOCATION SP kg/cm2 Relieving

Temp.

Selection Basis

TSV-1101 Crude 35.5 150 Thermal Expansion

TSV-1102 Crude 35.5 150 “

TSV-1103 Crude 35.5 150 “

TSV-1104 Crude 35.5 150 “

TSV-1105 Crude 35.5 150 “

TSV-1201 CW 6 65 “

TSV-1202 CW 22 65 “

TSV 1301 Crude 43 215 “


Temp.

Selection Basis

TSV 1302 Crude 43 175 “

TSV 1303 Crude 43 215 “

TSV 1304 Crude 43 225 “

TSV 1305 Crude 43 255 “

TSV 1307 Crude 43 305 “

35 Page

TSV 1308 Crude 43 65 “

TSV 1604 CW 6.0 65 “

TSV 1605 CW 6.0 65 “

TSV 1606 CW 6.0 65 “

TSV 1703 CW 6.0 65 “

TSV 1704 CW 6.0 65 “

TSV 1705 CW 6.0 65 “

TSV 1801 CW 6.0 65 “

TSV 1802 CW 6.0 65 “

TSV 1803 CW 6.0 65 “

TSV 1805 CW 6.0 65 “

TSV 1806 CW 6.0 65 “

TSV 1807 CW 6.0 65 “

TSV 1808 CW 6.0 65 “

TSV 1809 CW 6.0 65 “

TSV 1810 CW 6.0 65 “

TSV 1811 CW 6.0 65 “

TSV 1812 CW 6.0 65 “

TSV 3101 FO 16.5 245 “

36 Page

TSV 3102 FO 16.5 245 “

TSV 3103 FO 3.5 245 “

TSV 3104 FO 3.5 245 “

TSV 3105 FO 16.5 245 “

TSV 3106 FO 16.5 245 “

TSV 5002 H/C EE-102A/B 35.5 150 THER.EXPANSION

TSV 5003 H/C EE-103A/B 35.5 150 “

TSV 5004 H/C EE-104A/B 35.5 150 “

TSV 5005 WATER EE-13B 6.9 65 “

TSV 5006 WATER EE-12 A/B/C 2.2 130 “

TSV 5007 WATER EE-16D 6.9 65 “

TSV 5008 WATER EE-16E 6.9 65 “

TSV 5009 WATER EE-16F 6.9 65 “

TSV 5010 H/C EE-106A/B 43 210 “

TSV 5011 H/C EE-105A/B 43 250 “

TSV 5012 H/C EE-107A/B 43 310 “

TSV 5013 H/C EE-108A/B 43 310 “

TSV 5014 H/C EE-18 C/D 2.5 150 “

TSV 5015 WATER EE-17D 6.9 65 “

37 Page


Temp.

Selection Basis

TSV 5016 WATER EE-19B 6.9 65 “

TSV 5017 WATER EE-109 6.9 65 “

TSV 5018 WATER EE-110A/B 6.9 65 “

TSV 5019 WATER 6.9 65 “

TSV 5020 WATER EE-111A 6.9 65 “

TSV 5021 WATER EE-111B 6.9 65 “

TSV 5022 H/C EE-103C 35.5 150 “

TSV 5023 H/C 43 210 “

TSV 5024 H/C EE105C/D 43 250 “

TSV 5025 H/C EE-105 A/B 43 250 “

TSV 5026 H/C EE-107 C/D 43 310 “

3.2-3: LIST OF CONTROL VALVES

S.No. TAG NO. SERVICE SIZE(in.) Action

1 BOILER FEED WTR 1

2 5LV2602 RICH AMINE TO ARU 1 A/O

3 5LV3104 STM CONDEN. TO FLASH DRM 1 A/O

4 5LV3106 LP STM COND. FRM VV-035 1 A/O

5 5FV1807 HY. NAPHTHA FOR GAS OIL 1.5 A/O

38 Page

6 5FV2502 LPG BOOSTER PMP FLW 1.5 A/O

7 5LV3202 LPG TO LPG DRM VV-029 1.5 A/O

8 5PV1701 VENT FRM VV-003 1.5 A/O

9 5FV2501 LPG SURGE DRM 2 A/C

10 5PV3111 FO TO VV-026(BPC) 2 A/C

11 5FV1508 STRIPPING STM TO CC-001 BTM. 2 A/C

12 5FV2011 HY. NAPHTHA TO KERO R/D 2 A/O

13 5FV2503 LPG FRM PA-014A/B 2 A/O

14 5PV1415 FO TO HTR 2 A/O

15 5PV1504A FG TO FLARE FRM CC-001 2 A/O

16 5PV1504B FG TO VV-002 2 A/O

17 5PV1912 LPG PRODUCT R/D 2 A/O

18 5PV2011 HY. NAPHTHA TO STORAGE 2 A/O

19 5PV3203 LPG TO FG KOD VV-028 2 A/O

20 5PV4406 HP STM TO DESUPER HTR 2 A/O

21 5SDV1406 FG SUPPLY(PILOT) 2 A/O

22 5SDV1701 DRAIN FRM VV-003 2 A/O

23 5SDV1901 CAUSTIC SOL. EX VV-006 2 A/O

24 5SDV1902 WASH WTR EX VV-007 2 A/O

39 Page

25 5SDV1903 WTR EX VV-008 2 A/O

26 5SDV1904 CAUST. WASH WTR EX VV-016 2 A/O

27 5SDV2001 CASTIC EX VV-009 2 A/O

S.No. TAG NO. SERVICE SIZE(in.) A/O


29 5SDV2003 WTR FRM VV-025 2 A/O

30 5SDV2201 CAUSTIC EX VV-013 2 A/O

31 5SDV2202 WASH WTR EX-VV-014 2 A/O


33 5SDV2601 AMINE SETTLER BTM 2 A/O

34 5SDV2602 LPG AMINE ABSORBER BTM 2 A/O

35 5LV1201 BR IN FRM DSTLR TO DGASR 2 A/O

36 5LV3103 FO TO VV-026 3 A/O

37 5FV1201 2nd STAGE DESAL. WTR I/L 3 A/O

38 5FV1409 PLANT AIR FOR DECOCKING 3 A/O

39 5FV2501 LPG TO AMINE ABSORBER 3 A/O

40 5LV1602 SOUR WTR TO VV-005 3 A/O

41 5PV3202 LP STM TO LPG VAPORISER 3 A/O

42 5SDV1401 FO RETURN 3 A/O

40 Page

43 5LV1202 1st STAGE DIST. WTR I/L 3 A/O

44 5TV1702 NAPH. STAB. BTM. SAT. EE-018A/B 4 LOCK

45 5FV1401 CRUDE TO HTR PASS-1 4 A/C

46 5FV1402 CRUDE I/L PASS-2 4 A/C



49 5FV1804 HSD R/D 4 A/O

50 5FV2206 KERO/ATF COALASCER O/L 4 A/O

51 5FV3102 HP STM TO EE-028A/B/C/D 4 A/O

52 5HV1701 STABISER O/H VAPOUR 4 A/O

53 5PDV1420 ATM STM TO HTR 4 A/O

54 5SDV1402 FO SUPPLY 4 A/O

55 5SDV1601 SOUR WTR TO SRU 4 A/O

56 5SDV2501 LPG TO LPG SURGE DRM 4 A/O

57 5PV1423 FG TO HTR 6 A/O

58 5FV1410 DECOCKING STM TO HTR PASS-1 6 A/C




41 Page

62 5FV1505 TOP RFLX TO CC-001 6 A/C

63 5FV1805 LR TO BL(FPU) 6 A/O

64 5FV1806 LR TO BL STORAGE 6 A/O

65 5HV2001 LN+CAUSTIC TO VV-009 6 A/C

66 5HV2002 LN WTR TO VV-010 6 A/C

67 5HV2201 KERO+ATF+CAUST. TO VV-013 6 A/C

68 5HV2202 KERO+ATF+WASH WTR TO VV-014 6 A/C

69 5SDV1801 LN TO CAUSTIC WASH 6 A/O

70 5FV1501 TOP CIR. RETURN TO CC-001 8 A/C

71 5LV1508 KERO STRIPPER FEED 8 A/O

72 5LV1510 GAS OIL STRIPPER FEED 8

A/O

S.No. TAG NO. SERVICE SIZE(in.)

73 5SDV1403 FG SUPPLY 8 A/O

74 5LV1206 CRUDE BOOSTER PMP D/S 8 A/C

75 5FV1502 ATF/KERO CR RETURNED TO CC-001 10 A/C

76 5TV1116 EXCH-05-EE-006 A/B BYPASS 12 A/C

77 5FV6201 SKO TO DHDT 8 A/O

42 Page

CHAPTER 4: LINE SIZING

This specification provides guidelines for designing and installing the gaseous low-

pressure (<275 psig) and high-pressure (276 to 7,000 psig) high-purity product process

piping. For both low- and high-pressure, stainless steel (303, 304, and 316) tubing, piping,

fittings, and components are preferred. Maximum hardness is 80Rb.

MAXIMUM ALLOWABLE WORKING PRESSURE

Maximum allowable working pressures (MAWP) for commercially available tubing

and piping are given below. Piping systems must be designed so that the process pressure

of the gas will not exceed the MAWP of the pipe, tubing, or components.

Low-pressure (<275 psig)

For all sizes from 0.25- to 1-in OD stainless steel tubing, 0.035-in. wall thickness is

acceptable. Schedule 10S to Schedule 80S stainless steel pipe is also acceptable for both

plain end and threaded end styles. Threaded ends should be 80S.

High-pressure (275 to 7000 psig)

See the Tables below. The product system downstream of the compressor will operate

at 6,000 psig. The high-pressure storage tubes are designed to a maximum allowable

working pressure of 6,667 psig. The tubing or piping for these high-pressure circuits should

be selected to meet or exceed this pressure. To this end, the high-pressure piping/tubing

will be designed for 7,000 psig. Acceptable sizes and wall thicknesses are:

1/4-in. OD tubing: 0.049 and 0.065-in. wall thickness; 0.065-in.


78 5FV6202 SKO TO ATF MEROX 8 A/O

79 5FV6203 HOT RCO TO DCU 8 A/O

80 5FC6204 HN TO DHDT 2 A/O

81 5FV6205 GO TO DHDT 6 A/O

82 5FV7218 LN TO ISOM 4 A/O

43 Page


3/4-in. OD tubing: Not Allowed

1-in. OD tubing: Not Allowed

3/4-in. Schedule 80 piping: Limited to 6,550 psig with plain ends

The components specified in the Instrument Summary are primarily 1/2-in. and are

configured with either 1/2-in. female pipe ports or compression style tube fittings,

depending on availability. The piping designer/contractor may choose to modify the

specified end connection when ordering the components to facilitate installation. If the end

connections are modified, then confirm with the supplier that the pressure rating for the

component with the new end connection still meets the required MAWP for the system

(7,000 psig).

44 Page

CHAPTER 5: INSTRUMENTATION POWER SYSTEM

Main features of electrical instrumentation power system are described below:

Through a battery bank in main unit sub-station, 110 V DC supply is available to

all solenoid valve infield and auxiliary consoles in Control Room. On auxiliary

consoles are mounted Push Buttons, Running Status, Lamps & Selector Switches

to PLC interlocks etc. few spare outlets of 110 V DC supply are also provided in

control room to carry out miscellaneous testing jobs etc. battery backup will remain

available for a period of 1 hour for UPS & other Instrument requirements.

110 V AC power supply (uninterrupted) is available to all Hard Wire Alarms,

Hooters, and Multipoint. Digital Temp. indicators (TJI), Density Analyzers,

Supervisory Computers, Printer, Video Hot copier, DCS monitor (CRT) & hand

indicator controllers.

In the event of power failure, 110 V AC supply will remain available for a

maximum period of 60 min to above instrument to facilitate safe shut down of

process units. If power from main feeder is still not resumed plant instrument will

assume safe shut down position according to logic built in PLC. After power is

resumed DCS system and supervisory computer should be booted before reverting

back to normal operations.

.

45 Page

CHAPTER 6: SAFETY MEASURES ADOPTED

6.1: FIRE PREVENTION ACTIVITIES:

Regulation for the prevention of fire:

1) Ban on carrying of a potential source of ignition, ban on lighting fires in battery area.

Ban on smoking, Ban on carrying lamps, use of spark arrestors.

2) General precautions: Maintain good housekeeping. Follow the laid down procedure

strictly. Sampling and draining of hydrocarbon should be done under strict supervision. Do

not operate equipment unauthorized. Use only approved type of tools, anticipate the

hazards during vessel cleaning and take preventive step in advance.

6.2: SOUND ENGINEERING:

Design of the plant materials used for construction means of escape etc.

6.3: GOOD HOUSE KEEPING:

Cleanliness of the plant, methods of storage.

Good habits: observation of fire prevention rules etc.

Common sense: No smoking near inflammable material etc.

6.4: INSTRUCTION TO PERSONNEL

Knowledge of job.

Safe practices.

Action in case of fire.

Knowledge of fire extinguishers etc.

6.5: REGULAR TRAINING OF EMPLOYEES

Induction training program.

Refresh course.

Special listed training programmes.

46 Page

6.6: FIRE PROTECTION SYSTEM IN THE UNIT

A. Fire extinguisher 200 NOS.(10 kg DCP)

B. Fire glass: 20 NOS.(25 kg DCP)

C. Fire water monitors: from all four sides.

D. Tower platform monitors: 3 NOS.

E. Water sprinkler system: in pump house and at

Caustic/water vessels and on

fin coolers

F. Hydrocarbons gas detector: near P-5A/B,P-6A/B,

P-14A/B,

P-50A/B,

PA- 07A/B

G. Safety shower and eye washer: 2 No. (Near caustic tank, near

furnace)

H. Riser hydrant: A) At vessel platform

B) all columns.

6.7: WORK PERMIT SYSTEM

Work permit is a written document that categorically spells out

The task.

Equipment involved & its condition.

Its location.

Personnel involved.

47 Page

Time limitation

Precautionary measure to be taken together with likely hazard to be encountered, if

any.

Act as a predetermined checklist for various safety precautions.

Serves as a media of information.

Instills a sense of security from accident.

Work permit system is required in the refinery as per, Sec.7 (2a) SSW

OISD-105

Rule 172 of petroleum rules, 1976

OBJECTIVE:

To make the procedure of the work foolproof.

To guarantee against accidental starting of machinery or entry of

any hazardous liquid or gas into a vessel whose jobs are proposed.

6.7-1: TYPES OF WORK PERMITS:

Hot work permit

Cold work permit

Excavation permit

Work at height permit

Work at depths

Electrical work permit

Vessel entry permit

48 Page

6.7-2: POINTS TO BE ENSURED WHILE GIVING CLEARANCE:

1) Equipment / Area inspected.

2) Surrounding area checked / cleaned.

3) Sewers, Manholes, CBD etc and hot surfaces covered.

4) Consider & ensure no hazard from other routine / non-routine operation and alters

surrounding / concerned persons.

5) Equipment electrically isolated and tagged.

6) Running water hose/ portable extinguisher provided.

7) Equipment blinded / disconnected / closed / isolated wedged open.

8) Equipment properly drained / depressurized, steamed / purged.

9) Firewater system checked for readiness.

10) Equipment water flushed.

11) Gas / oxygen deficiency test done and found OK.

12) Shield against sparks provided.

13) Proper ventilation and lighting provided.

14) Proper means of exit provided.

15) Precautionary tags / boards provided.

16) Portable equipment / Hose nozzles properly grounded.

17) Standby personnel provided for fire watch from process / maintenance / contractor

/ fire and safety department.

18) Iron sulfide removal / kept wet.

19) Area cordoned off.

20) Precautions against public traffic taken.

21) Clearance obtained for excavation / road cutting from technical / fire / concerned

departments.

22) Clearance obtained for dyke cutting.

23) Checked spark arrestors on mobile equipment.

24) Checked for oil / gas trapped behind lining in equipment.

25) Check for hot tapping.

49 Page

6.8: CORRECTIVE ACTION TO BE TAKEN TO PREVENT HAZADOUS

SITUATION FROM ESCALATING

HAZARDOUS SITUATION ACTION

Severe hydrocarbon leakage Cut off all furnace

Take unit on circulation. If required

shutdown totally.

Block adjacent roads

Inform F&S

Isolate leaky section using PPEs &

depressurize to flare.

Inform RSM/CPNM

Furnace Coil Rupture Open STD

Cut off fuel to furnace

Cut off feed

Put coil purging steam.

Take emergency S/D of entire

plant

Inform RSM / CPNM

Severe Exchanger Leakage Bypass exchanger-using PPE & isolate it.

Depressurize

Keep steam Lancer

Inform RSM / CPNM

Cut off furnace if H/C vapor travels

towards furnace

Pump Seal Leakage Start stand by pump

Isolate the leaky pump

Depressurize

Keep fire Engine standby.

Inform RSM / CPNM

50 Page

6.9: SAFETY SYSTEM AND THEIR FUNCTIONS

Following safety systems are available in the unit

1. PSVs

2. Interlocks

3. Hydro-carbon leak detectors

4. Fire water sprinkler system

5. PPEs

6.9-1: PSVs

Purpose: PSVs are provided to protect the equipment like columns, vessels, pipe line etc

by relieving excess pressure to flare / atmosphere when there is abnormal pressurization

due to CW failure or fire etc.

Where Situated: Normally it is situated at column top vessel top, compressor discharge and

positive displacement pump discharge.

Relieve Where: Normally to flare system.

Flare Knock Out Drum: All PSV discharge is routed to flare connected to a header which

is routed to flare KOD located at AU5 battery limit. Liquid which is carried along with gas

is settled in this vessel are drained out to CBD. Only gas from its top is send to flare. It is

provided with a level indication (with alarm). Level indication is transmitted to DCS CR.

In normal condition once in a shift draining is done.

6.9-2: Interlocks

Purpose: Meant for protecting of equipment in case of extreme deviation in parameter

from operating limit, before it reaches the equipment design limit.

Location: Furnaces

What all interlocks: (Furnace fuel will cut off if there is)

Low Combined pass flow

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Low FG pressure

Low Fuel Oil pressure.

FD fan failure

ID fan failure (STD does not open within 30 sec)

6.9-3: Hydrocarbon Leak detectors:

Facility: The unit is provided with 05 numbers of hydrocarbon detectors located at

vulnerable points where chances for leak is more. It senses the leak & if concentration is

more than the specified limit, will give signal to DCS control room through alarm. After

getting the alarm, Panel operator instructs the field operator to check physically the area,

for any leakage.

6.9-4: Fire water Sprinkler:

Firewater Sprinkler is provided on all black hot hydrocarbon pump for cooling purpose.

During pump seal leak & subsequent fire, sprinkler system is activated to cool the pump to

avoid damage to piping & structure. This system will be provided to all hot pump in near

future.

6.9-5: PPEs:

Safety helmet, safety shoe, rubber / canvas hand gloves, apron, Breathing apparatus, gas

mask/ canister for use in different gas atmosphere etc. are provided for safe operation and

emergency handling in case of abnormal condition. BA set is kept in DCS control room.

Safety helmet & safety shoes have been provided to all operating personnel. Other PPEs

are available in Check & Change room of operators.

6.9-6: HVLR.

High Velocity Long Range monitor has been provided for spraying water jet at top of high

column during fire fighting

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CHAPTER 7: ENVIRONMENTAL ISSUES

Indian Oil Corporation is committed to conduct business with strong environment

conscience ensuring sustainable development, safe workplaces and enrichment of quality

of life of Employees, Customers and the Community. We, at IndianOil, believe that good

S, H & E performance is an integral part of efficient and profitable business management.

We shall: Accordingly, the Corporation's endeavour is to: Establish and maintain good

standards for safety of the people, the processes and the assets. Comply with all Rules and

Regulations on Safety, Occupational Health and Environmental Protection. Plan, design,

operate and maintain all facilities, processes and procedures to secure sustained Safety,

Health and Environmental Protection. Remain trained, equipped and ready for effective

and prompt response to accidents and emergencies. Welcome audit of our S, H & E conduct

by external body, so that stakeholder confidence is safeguarded. Adopt and promote

industry best practices to avert accidents and improve our S, H & E performance. Remain

committed to be a leader in Safety, Occupational Health and Environmental Protection

through continuing improvement. Make efforts to preserve ecological balance and heritage.

Green Belts as Pollution Sinks Scientifically designed green belts have been developed at

IndianOil's Gujarat and Panipat refineries to serve as pollution sinks and to enhance the

aesthetic look of the refinery area.

Extensive tree plantation has been undertaken by Guwahati, Digboi, Mathura, Haldia

and Barauni refineries and townships to develop green cover. Mathura Refinery has planted

about 115,000 trees in the Taj Reserve Forest near Taj Mahal under the 10-Point Initiative

of the Ministry of Petroleum & Natural Gas for improvement of environment in the Taj

Trapezium. Mathura Refinery has developed a sprawling area of 18,000 sq. m. around its

polishing ponds into an ecological park. A large number of migratory birds have made the

ecological park as their habitat. Experts from the Bombay Natural History Society (BNHS)

have identified about 96 varieties of birds in the park.

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Similar parks have also been developed at Barauni and Gujarat refineries. The existence

of rich flora and fauna in these parks is a clear testimony of the clean and eco-friendly

environment in and around the refineries. The other refineries are in the process of

developing such ecological parks. SMOKELESS FLARING As a minimum, start-up and

normal off-spec flaring is to be considered for smokeless flaring. The flare design must

allow for smokeless flaring through this capacity range. In addition, the flare may need to

be designed for smokeless burning for other capacities as might be mandated by local

environmental or regulatory requirements.

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