Internship Report

(BYCO Oil and Petroleum Limited, Karachi.)

By

Khaqan Majeed

National University of Sciences and Technology (NUST)

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Certificate

This is to certify that work in this dissertation/report has been carried out by Mr. Khaqan

Majeed and completed under my supervision, ORC-2 BYCO Oil and Petroleum Limited,

Karachi, Pakistan.

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Supervisor: ______________

Engineer. Abdul Qader

Assistant Advisor

Advisory Department ORC-2

BYCO Oil and Petroleum Limited, Karachi.

Remarks:

Acknowledgment

First of all we are bow before ALLAH, The Almighty to thank for his countless blessing and bounties.

Secondly we are highly thankful to Engr. Abdul Qader our internship advisor, who guided us, encouraged us and accepted nothing less than our best efforts.

We are also thankful to our Parents who kept our spirit high and didn’t let us down. Special thanks to our Friends for their continuous support and technical assistance.

At last but never the least we are thankful to all members of operation department at ORC-2 (BYCO) specially Eng. Hisham Hafeez Khan , Eng. Muhammad Noman and Mr. Hafiz Junaid for their precious time and value able advices.

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Abstract

This report consists learning that we got during internship period at ORC-2 BYCO Oil and Petroleum Limited Karachi. Safety is always first priority in any industry. We have discussed safety target of BYCO, main hazard which can occur in refinery area and emergency alarms for different alarming situation.

Second thing, upon which whole refinery is dependent, is utilities. To run plant it requires water and power. Water treatment plant, power house, cooling tower, compressor, boiler and fire line network is discussed in utilities.

Refinery Process is divided in black oil movements, white oil movements and oil movements. Black oil movement is treatment of crude oil. Products of crude distillation unit are further treated to meet end user requirements. White oil movement is treatment of Overhead product Naphtha. Naphtha is treated in hydro treating unit to convert sulfur and nitrogen into hydrogen sulfide and ammonia. Naphtha contains hydrocarbons C1 to C10 which are separated in gas treatment unit where we get LPG, light naphtha and heavy naphtha. Light naphtha is treated in isomerization unit to convert n-paraffin to iso-paraffin. Heavy Naphtha is treated in plat former to crack into lighter hydrocarbons to make gasoline.

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Table of Contents1- Environmental, Health and Safety (EHS)..............................................................................................1

1.1- Targets.........................................................................................................................................1

1.1.1- LTI........................................................................................................................................1

1.2- Safety Signs..................................................................................................................................1

1.2.1- Blue..........................................................................................................................................1

1.2.2- Green.......................................................................................................................................1

1.2.3- Yellow......................................................................................................................................1

1.2.4- Red...........................................................................................................................................1

1.3- Main Hazards...............................................................................................................................1

1.3.1- Fire...........................................................................................................................................1

1.3.2- Chemical..................................................................................................................................1

1.3.3- Confined Area..........................................................................................................................2

1.3.4- Electric.....................................................................................................................................2

1.3.5- Noise Hazard............................................................................................................................2

1.3.6- Radiation..................................................................................................................................2

1.3.7- Thermal....................................................................................................................................2

1.3.8- Physical....................................................................................................................................2

1.4- Emergency Alarms.......................................................................................................................2

2- Utilities............................................................................................................................................3

2.1- Water treatment:........................................................................................................................3

2.1.1- Dissolved Air Flotation (DAF)...............................................................................................3

2.1.2- Multi Media Filter (MMF)....................................................................................................4

2.1.3- Reverse Osmosis (RO)..........................................................................................................5

2.1.4- Electro De-Ionization...........................................................................................................6

2.2- Boilers..........................................................................................................................................8

2.2.1- Flash Vessel...............................................................................................................................8

2.2.2- DEARATOR.................................................................................................................................8

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2.2.3- Boiler.........................................................................................................................................9

2.3- Cooling Tower............................................................................................................................12

3- Black Oil Movements.........................................................................................................................14

3.1- CRUDE OIL DISTILLATION UNIT.......................................................................................................14

3.1.1- Feed.........................................................................................................................................14

3.1.2- De-salter..................................................................................................................................14

3.1.3- Furnace (1F-1)..........................................................................................................................16

3.1.4- Fractionating Column (1C-1)....................................................................................................16

3.1.5- Accumulator............................................................................................................................18

3.1.6- Strippers..................................................................................................................................19

3.1.7- Chemical Dosing......................................................................................................................19

4- White Oil Movements........................................................................................................................20

4.1- Naphtha Hydro treating Unit (Plant-6)...........................................................................................20

4.1.1- Feed Surge Drum (6C-3)..........................................................................................................20

4.1.2- Pumps and Heat Exchangers...................................................................................................20

4.1.3- Furnace (6F-1)..........................................................................................................................20

4.1.4- Reactor (6C-1)..........................................................................................................................21

4.1.5- Reactor Product Separator (6C-2)............................................................................................21

4.1.6- Product Flash Drum (6C-5).......................................................................................................21

4.2- Gas Treatment Plant (Plant-8)........................................................................................................23

4.2.1- DE-ETHANIZER (8C-1)...............................................................................................................23

4.2.2- De-Butanizer (8C-5).................................................................................................................23

4.2.3- De-Isohexanizer (8C-13)..........................................................................................................24

4.3- Isomerization Unit (Plant-16).........................................................................................................26

4.3.1- Liquid Preparation...................................................................................................................26

4.3.2- Panex Unit...............................................................................................................................27

4.3.3- Molex Unit.........................................................................................................................28

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List of TablesTable 1 Boiling ranges of crude oil fraction..............................................................................................14Table 2 Trays Distribution in Fractionator................................................................................................18Table 3 Contaminats value in Panex Feed.................................................................................................27

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List of FiguresFigure 1 DAF System....................................................................................................................................4Figure 2 Process Flow Diagram ofMMF.......................................................................................................5Figure 3 Process Flow Diagram of Sea water RO.........................................................................................6Figure 4 Process Flow Diagram of Brackish Water RO and CEDI..................................................................7Figure 5 Diagram of DE aerator...................................................................................................................9Figure 6 Process flow diagram of Boiler....................................................................................................11Figure 7 Diagram of DEsalter.....................................................................................................................15Figure 8 Process flow diagram of DE salter................................................................................................16Figure 9 Process Flow Diagram of CDU......................................................................................................19Figure 10 Process Flow Diagram of Plant-6...............................................................................................22Figure 11 Process flow diagram of M.E.A..................................................................................................24Figure 12 Process flow diagram of Gas treatment Plant............................................................................25

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1- Environmental, Health and Safety (EHS)

Safety always has been first priority in industry to make life and environment safe. For BOPL safety now means tomorrow is safe. For everyone who work there safety training and obey the safety rules are compulsory.

1.1- TargetsBOPL has safety targets to make environment safe.

LTI

1.1.1- LTIBOPL keep zero last time injury. Every time when accident occurs, injury rate should be

zero.

1.2- Safety SignsThere are many sign to guide the labor. They have different color which their strength.

1.2.1- BlueBlue color is compulsory which should be obeyed whatever the circumstances are.

1.2.2- GreenThis color guides about safety. Green tell what should do according to equipment or

place.

1.2.3- YellowYellow color is warning color.

1.2.4- RedRed color is about fire. Equipment with red color is about fire.

1.3- Main HazardsBOPL has listed main hazard which may occur in refinery. According to them safety

measurement are done. Main hazards are:

1.3.1- FireFire may occur in refinery site due to hydrocarbon leakage. So safety measurement is

done to control fire if it occurs.

1.3.2- ChemicalAs BOPL is dealing with crude oil to make pure products from it. During the production

there may be leakage of hydrocarbons. To control chemical leakage different safety measurement are done.

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1.3.3- Confined AreaThere are site that may be have a way to get in for different purposes but it may harmful

for irrelevant people so they are cleared confined areas. To go in confined area, relevant person should obtain permit.

1.3.4- ElectricElectric shock may occur as there are different wires.

1.3.5- Noise HazardEquipment installed in refinery creates noise which is also hazard. To avoid results of

noise hazard, ear plug is used.

1.3.6- RadiationRadiation equipment are installed for different purposes. When they are switched on,

common labor is kept away from site. Only men in appropriate radiation dress are allowed to enter radiation zone.

1.3.7- ThermalDifferent equipment like furnace, stack, heat exchanger, boiler, steam lines have thermal

effect. So always keep a distance to avoid thermal affects.

1.3.8- PhysicalMoving machinery like cranes, are working on site. Irrelevant person should remain away

from site because they can make physical damage.

1.4- Emergency AlarmsEmergency is held if any following case occurs.

Fire Chemical Leakage Radiation Exposure Equipment Damage

During emergency, everyone should be gathered at assembly point.

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2- Utilities

Utilities are section of industry that provides power, water and other things to run the production unit. Commonly they include:

Water Treatment Boiler Compressor Cooling Tower Power House Fire Water Network

2.1- Water treatment:In BOPL water is obtained from two sources:

Sea Water Boring Wells

Sea water is pumped from sea to open channel. Two submersible pumps are used to extract water from sea.

In boring well, water from 1oom depth is extracted. Currently 20 pumps are working. Water from sea and boring wells is transported through open channel whose length is 1.5 km.

Water treated for use in boiler to form steam, for making steam water should be distilled. To make distilled water different process are being used.

Dissolved Air Flotation (DAF) Multi-media Filter (MMF) Reverse Osmosis (RO) Electro De-Ionization

2.1.1- Dissolved Air Flotation (DAF)Air is introduced to water stream that adheres or traps solid particles. This increases

buoyancy of particles and they came out at surface. DAF is first in water treatment. In this stage water before treatment has 40,000 TDS.

Before DAF, chemical pretreatment is done. Chemical treatment is done to control pH, to make flocks and corrosion. We are using following chemical in water treatment:

Caustic Soda to maintain Sodium hypochlorite

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Fe2Cl3

Poly electrolyte

DAF is simply open water tank which contain scrapper. Water from chemical pretreatment is injected into water tank. A water recycle is made in DAF, in which air is inserted. This air traps or adhere solid particles with it and due to buoyancy, they are deposited on water surface. Poly electrolyte helps to make flocks. These suspended particles are removed from surface by scrapper. After DAF treatment water turbidity is equal 5 NTU. In DAF system 5 pumps are being used, 3 for feed and 2 for back wash.

Figure 1 DAF System

2.1.2- Multi Media Filter (MMF)Multimedia filter consist bed filter bed. Filter bed consists of three different material type

layers. Above of all is anthracite, intermediate layer is sand and third layer is gravel. Anthracite has small particle size, sand has intermediate and gravel has large particle size. Large suspended particles are trapped in anthracite layer while in sand layer intermediate sized particles are trapped. Small size particles are trapped in bottom layer. This arrangement is made so that all particles should not deposit on first layer to back wash repetition.

Water from DAF, is send to MMF to remove further suspended particles. At inlet turbidity of water is 5 NTU while after treatment it is less than 1 NTU.

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Figure 2 Process Flow Diagram of MMF

2.1.3- Reverse Osmosis (RO)Reverse osmosis relies on differences between the physical and chemical properties of

the solutes and water to achieve separation. A high pressure feed stream is directed across the surface of a semipermeable material, and due to a pressure differential between the feed and permeate sides of the membrane, a portion of the feed stream passes through the membrane. As water passes through the membrane, solutes are rejected and the feed stream becomes more concentrated. The permeate stream exits at nearly atmospheric pressure, while the concentrate remains at nearly the feed pressure.

The smallest unit of production capacity in a membrane plant is called a membrane element. The membrane elements are enclosed in pressure vessels mounted on skids, which have piping connections for feed, permeate, and concentrate streams. A group of pressure vessels operated in parallel is called a stage. The concentrate from one stage can be fed to a subsequent stage to increase water recovery (a multistage system, sometimes called a brine-staged system) or permeate from one stage can be fed to a second stage to increase solute removal (a two-pass system, also sometimes called a permeate-staged system).

Here at ORC-2, RO is further divided in two categories i.e. Seawater RO and Brackish water.

a- Seawater ROWater after treatment in DAF and MMF, contains 40000 TDS. Before entering pressure

vessel, water flow through 5um cartridge filter as a minimum pre-filtration step for protection of the membrane elements. To remove dissolved particles, high pressurized water at 903psig is passed from 15 pressure vessels in parallel arrangement. Each pressure vessel contains 7 membrane elements. Water is kept chlorine free as it will degrade the membrane element. At outlet TDS are 400mg/l. Here recovery of solutes is about 40%. This water can be used as fire

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water, CW makeup water, process water, potable water and utility water but cannot be used for boiler. For use in boiler further treatment is done.

Figure 3 Process Flow Diagram of Sea water RO

b- Brackish Water ROAfter treating water in seawater RO, TDS come to 400mg/l which categories it in

brackish water. Permeate from seawater RO is treated in brackish water RO system. This system contains 7 pressurized vessels. Water at 144 psig is injected at outside of membrane element. Here after treatment TDS is 20mg/l while recovery is about 90%.

2.1.4- Electro De-IonizationTo obtain TDS less than 0.1mg/l, permeate from 2nd pass RO is further treated in electro

de-ionization. It will make useable water for boiler. Total number of CEDI is 24. In EDI the dissolved salts are ionized by the application of voltage. Positive ions move towards cathode and negative ions moves towards anode. It is a three layer compartment where salt is used as electrolyte and its level is maintained at 0.5-2inches. In middle there is a layer of resin, then 2 electrodes and then a membrane layer. Here recovery is 95%.

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Figure 4 Process Flow Diagram of Brackish Water RO and CEDI

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2.2- BoilersBoilers are pressure vessels designed to heat water or produce steam, which can then be

used to provide space heating and/or service liquid heating. Boiler is categories in two types i.e. water tube boiler and fire tube boiler. In ORC-2, water tube boiler is used to make high pressure steam. Three boilers are installed with common DE aerator but separate economizer and stack assembly. Here we are using it to make steam. Three type steams are used.

HP MP LP

HP is high pressure steam at 43.7barg and 380oC. MP is medium pressure steam at 18barg and temperature is 208oC while LP is low pressure steam at 4.3barg and 157oC. LP is condensate of HP. HP is used to run turbines. MP and LP are used process steam. To make steam from distilled water, complete assembly of equipment is used.

Distilled water and condensate are generally used to make steam. Distilled/Demin water is used only for first time run of boiler. In continuous process demin water will be used as makeup water. Condensate water is used as main process stream.

2.2.1- Flash VesselCondensate from BOPL is flashed in flash vessel. Vapors will rise above and again added

to LP steam. Liquid phase at bottom will be deposited. Liquid phase contains heat which will be recovered by heating DEMIN water in plate type heat exchanger. After flash tank, water is treated in DE aerator.

2.2.2- DEARATORA DE aerator is a device that is widely used for the removal of oxygen and other

dissolved gases from the feed water to steam-generating boilers. In particular, dissolved oxygen in boiler feed water will cause serious corrosion damage in steam systems by attaching to the walls of metal piping and other metallic equipment and forming oxides (rust). Dissolved carbon dioxide combines with water to form carbonic acid that causes further corrosion.

At ORC-2, two DE aerators are used. LP DE aerator HP DE Aerator

DE aeration is done by two methods i.e. mechanical DE aeration and chemical DE aeration. Mechanical DE aeration is done by help of steam. Steam is injecting at the bottom of DE aerator and it cause to remove dissolved gases. While in chemical DE aeration O2 scavenger is added to water stream. Here at ORC-2 we are adding sodium sulphate as O2 scavenger. Most DE aerators are designed to remove oxygen. It reacts with dissolved O2 and separate it water stream. Sodium sulphite is non-scaling agent. Here both mechanisms are used for DE aeration. Mechanical DE aeration occurs first than chemical DE aeration.

a- LP DE aeratorFeed water is sprayed by means of nozzle from top. LP steam is injected at bottom

through steam Spurger. Dissolved gases will be vaporized and will vent from top. DE aerator is

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kept at height to create pressure head. In LP DE aerator water is discharged at low pressure 19barg. Water from LP DE aerator is used at BOPL plant area as process water in re-boiler etc.

b- HP DE aeratorHP DE aerator works same like LP DE aerator. Water discharge is at 50.3barg. Discharge

of HP DE aerator is used as feed water of boiler.

2.2.3- BoilerWater from HP DE aerator is used as feed water in boiler. At ORC-2, all three boilers are

water tube boiler. A water tube boiler is a type of boiler in which water circulates in tubes heated externally by the fire. The circulated water is heated by the hot gases and converted into steam at the vapor space in the drum. These hot gases are produced by burning fuel inside the furnace. The whole assembly of boiler and process is discussed below.

a- EconomizerEconomizer is installed to recover heat from flue gases of boiler by heating feed water.

Flue gases from boiler have large amount of heat while feed water is at ambient temperature. If feed water is injected at ambient temperature in boiler it will increase fuel consumption to gain heat. So before injecting feed water in boiler, it is indirectly contacted with flue gases. Water will gain heat from flue gases. Flue gases go from 292 oC to 186 oC temperature. Now it can be vented in atmosphere. In ORC-2, three boilers are installed. Each boiler is connected to separate economizer and stack column.

b- Steam DrumA steam drum is a standard feature of a water-tube boiler. It is a reservoir of water/steam at

the top end of the water tubes. The drum stores the steam generated in the water tubes and acts as a phase-separator for the steam/water mixture. The difference in densities between hot and cold water helps in the accumulation of the "hotter"-water/and saturated-steam into the steam-drum. Different type chemical dosing is also done for different purposes.

Hydrazine for O2 Exvanger Amine to keep pH < 7 Phosphate as anti-scalant

c- BurnerTwo burners are installed in boiler each with dual fuel system. In dual fuel facility, they

can be run either at furnace oil or fuel gas. Control ratio of air to fuel is injected for complete combustion. Furnace oil is atomized with help of steam. Steam makes furnace oil mist. This mist formation completely burns otherwise showering of furnace oil by nozzles will not help it to burn. As boilers are forced draught boilers air is forced to combustion chamber by blower to maintain a positive pressure.

d- Down Comers and Riser TubesWater form steam drum comes by gravity via tubes called down comers. Down comers

passes through combustion chamber as it gain heat, its vapors rise through tubes called riser. In down comers water from steam drum goes down to mud drum. During pass of down comer from

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combustion zone it get heat. Riser tubes connects mud drum to steam drum. Hot water from mud drum goes through riser tubes to steam passing through combustion chamber.  The steam and water mixture enters the steam drum through riser tubes; drum internals consisting of demister separate the water droplets from the steam producing dry steam. Saturate water at bottom of steam drum is again flows through down comers. By this cycle saturated steam is generated in steam drum. Saturated steam discharges from top of steam drum to make super heat steam.

e- Super HeaterSaturated steam from steam drum is further heated to convert rest vapors to steam. It will

create dry steam. This zone consist thin tubes of steam and flue gases from combustion chamber. This zone is named convection zone as heat is transferred from flue gases to steam tubes. Here we get super heat steam which is ready for use in plant.

f- Water Drum/Mud DrumThe Mud drum is a unit which is located beneath the steam drum to collect the solid

materials which precipitate out of the boiler feed water due to the high pressure and temperature conditions of the boiler. The process by which suspended solids are collected in the boiler is referred to as cycling. Cycling occurs because the boiler feed water is sent through the boiler drum a number of times. This is done to produce the maximum amount of steam per unit volume of feed water. On each run through the boiler drum, a portion of the boiler feed water is vaporized. This results in an increase in the solids concentration in the boiler drum. Eventually, the solids concentration hinders the ability to maintain steam generation efficiency. At this time, a stream of compressed air is used to blow the solids into the mud drum beneath the boiler. The mud drum then stores these materials for later disposal. This process of using compressed air to remove the collected suspended solids is referred to as blow down.

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Figure 6 Process flow diagram of Boiler

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2.3- Cooling TowerCooling tower is a device which removes heat from a medium and rejects this heat to the

atmosphere. The basic principle of cooling tower is that of evaporation and condensation. Sensible heat is exchanged. Cooling towers are classified in two categories.

Natural draft cooling tower Mechanical draft cooling tower

In natural draft cooling tower air flow is due to largely difference in density between the warm air in the tower and the external ambient air. They are most economical. Mechanical draft cooling tower has large fan is used to draw air through circulated water. It has further two types:

Forced draft cooling tower Induced draft cooling tower

Here at ORC-2 we are using induced draft cooling tower. In induced draft cooling tower water and air flow is counter flow. Four cooling towers are installed. Each is further divided in two sections with common fan. At top fan is installed. Below the fans, fins are made to control drift losses. As air speed is high, large amount of water will be vaporized. To condense water fins are installed. They will recover maximum vapor from air. Below fins plate, feed water is sprayed. Fin frame are installed in cooling tower body to increase contact time and area of water and air. Chemical treatment is done in feed water. Following chemicals are injected;

Active Bromine NaOCl Corrosion and Scale inhibitor

Some important terms used in cooling tower are;

a- ApproachThe approach is the difference in temperature between the entering water temperature and

the entering air wet bulb temperature. It tells the maximum level to which water can be cooled.

b- RangeThe range is the temperature difference between the water inlet and exit states. It tells to

what extent water has been cooled.

c- Wet Bulb TemperatureThe temperature measured by moistened thermometer of saturated air when evaporation

and condensation rate is in equilibrium.

d- Dry Bulb TemperatureDry bulb temperature is temperature of ambient air.

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e- Absolute HumidityAbsolute humidity is a measure of the actual amount of water vapor (moisture) in the air,

regardless of the air's temperature. The higher the amount of water vapor, the higher the absolute humidity.

f- Relative HumidityRelative humidity can be expressed as the ratio of the partial pressure of the water vapor

in mixture to the saturated vapor pressure of the water at given temperature.

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3- Black Oil Movements

Black oil movements involve treatment of crude oil. It covers crude oil distillation, vacuum distillation and heavy gas oil treatment. Currently only crude oil distillation unit (plant-1) is in working condition. Heavy gas oil treatment (plant-4) and vacuum distillation unit (plant-2) are under commissioning. So here we will cover only crude distillation unit (plant-1).

3.1- CRUDE OIL DISTILLATION UNITIn any refinery crude distillation unit is first processing unit. Crude oil is separated on

basis of boiling point at atmospheric pressure to achieve different products. Here at ORC-2, the crude is separated into five basic streams which are then further processed to get end user required product. Separation of the crude is accomplished by vaporizing and condensing the crude under controlled conditions so that fractions boiling ranges can be achieved. Below table shows crude oil fraction’s boiling ranges.

Table 1 Boiling ranges of crude oil fraction

Stream Boiling Range oF

Naphtha <320

Kerosene 320-510

Light gas oil 510-680

Heavy Gas oil 680-750

Furnace oil/ Residue >660

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3.1.1- Feed The feed to the unit normally imported mostly from Qatar Marine crude. Oil is shipped

from oil ship to directly unit by single point mooring buoy facility. BYCO is first company of Pakistan having single mooring point (SPM) buoy facility. The unit is designed to handle 115 MBPD. The feed is pumped to the unit from crude storage by pumps located near the crude tanks.

3.1.2- De-salterAfter preheating crude oil in heat exchanger, it is pumped to de-salter unit. The crude oil

contains salt of calcium and magnesium in the form of dissolved salt in the tiny droplet of water which forms a water-in oil emulsion. This water cannot be separated by gravity or through mechanical means. It is separated through electrostatic water separation. This process is called desalting. In the electrostatic de-salter, the salty water droplets are caused to coalesce and

migrate to the aqueous phase by gravity.

The De-salter is installed before the Pre-heat section of Crude Distillation Unit to operate at temperatures between 120-150oC. Desalter is a horizontal unit electrodes and mesh to maintain water layer below oil. The desalting operation is carried out by flushing the crude from bottom of de-salter to fresh water of low salt content. De-salter contains 5 beds, first two water bed, intermediate emulsion bed and top two beds are crude oil bed. As crude is passed through water beds, it is washed. After water beds electrostatic filed is established with help of electrodes. Caustic soda injection is done as an electrolyte. This electrostatic field will emulsify salts with water droplets in crude oil. These will settled down with gravity. The De-salter carries out

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dehydration of the crude to bring down the water content to below 0.1%. For high efficiency, high temperature and pressure is maintained.

Figure 8 Process flow diagram of DE salter

3.1.3- Furnace (1F-1)The desalted crude is passed through a series of heat exchangers (shell and tube).

Temperature then rises from 150oF to 350oF. But temperature of feed in distillation requires 666oF. After pre-heating by heat exchangers, it is then passed through a furnace. Its temperature is then raised to 710oF, in the furnace 1F-1. 1F-1 is brickery type furnace with forced draft fan while partially induced fan at outlet. Furnace is facilitated with dual burning system. Crude oil is heated in two sections. Fist it is heated in combustion zone which is called radiation zone then is heated in convection zone. From here it flashes into the crude column 1C-1 at a temperature of 710oF and a pressure of 30psig. Under these conditions, some of the crude is vaporized and the vapor passes up the column whilst the remainder, as liquid, flows down the column.

3.1.4- Fractionating Column (1C-1)At about 666 oF, and about 30psig crude is fed just above 4th tray of column as at this

point feed will in equilibrium with column stream. Most of the fractions in the crude oil vaporize and rise up the column through trays. The different fractions are gradually separated from each other on the trays of the fractionation column. The heaviest fractions condense on the lower trays and the lighter fractions condense on the trays higher up in the column. At different elevations in

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the column, with special trays called draw-off trays, fractions can be drawn out on gravity through pipes, for further processing in the refinery.

The main column is typically 50 m (164 ft) high and is equipped with about 37 valve trays. The vapor goes up in tremendous amounts and at a high flow rate, necessitating a large diameter column above the flash zone. At the bottom of the stripping section, steam is injected into the column to strip the atmospheric residue of any light hydrocarbon and to lower the partial pressure of the hydrocarbon vapors in the flash zone. This has the effect of lowering the boiling point of the hydrocarbons and causing more hydrocarbons to boil and go up the column to be eventually condensed and withdrawn as side streams. In the overhead condenser, the vapors are condensed and part of the light naphtha is returned to the column as reflux. Further reflux is provided by several pump around streams along the column. In the distillation tower, heat required for separation is provided by the enthalpy of the feed. For effective separation heat has to be removed from the tower, in this case, by the overhead condenser and several pump around streams along the tower length.

The side draw products (Kerosene, LGO and HGO) are stripped to control their initial boiling point. The strippers contain several trays and the stripping is done using steam at the bottom of the stripper or re-boiler type side stream strippers. The end boiling point of the side stream is controlled by the flow rate of the side stream product.

The overhead vapor is condensed at the top of the tower by heat exchange with the cool crude coming into the unit and by air and cooling water. The liquid product is called light straight run naphtha. Part of this product is returned to the column as an external reflux. Down the column, other products are withdrawn, such as heavy straight run naphtha, kerosene or jet fuel, LGO and HGO. All of these products are withdrawn above the feed tray. The atmospheric residue is withdrawn from the bottom of the column. It is used as furnace oil currently. After installation of VDU, residue of CDU will be treated to get asphalt and other products.

The main column is equipped with 37 valve trays. The trays distribution between products as shown in

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Table 2 Trays Distribution in Fractionator

Zone Number of Trays

Overhead product Naphtha to kerosene 13

Kerosene to light gas oil 10

Light gas oil to heavy gas oil 7

Heavy gas oil to flash zone 3

Flash zone to atmospheric residue 4

a- Re-boilerRe-boiler is heat exchanger used to provide heat to the bottom of distillation columns. It

boils the partial bottom product of the distillation column to generate vapors which are returned to the column to drive the distillation separation. This stream is called bottom reflux.

b- Pump AroundA pump around circuit consist of withdrawing hot liquid from the column, cooling it, and

returning the cold liquid to the column. To achieve this progressive cooling, pump around are used, one at the top of the column (total pump around) and one at approximately middle of the column (intermediate pump around). This pump around cooling accomplishes a number of tasks. First, the cold liquid condenses more of the rising vapors thus providing more reflux to compensate for the withdrawal of products from the column.

Second, heat is removed from the column at higher temperatures. This is in addition to the heat removal from the condenser which takes place at relatively lower temperatures, thus the thermal efficiency of the column is improved and the required furnace duty is reduced. Third, pump around streams reduce the vapor flow rate throughout the column. Therefore, the required column is smaller than what would otherwise be required if pump around streams where not there. The drawback to using more pump around streams is that they tend to reduce the fractionation because a more fractionated liquid is mixed after cooling with a less fractionated liquid a few trays above.

c- RefluxIn the overhead condenser, the vapors are condensed and part of the light naphtha is returned

to the column as reflux. Purpose of reflux is to increase purity and to maintain temperature gradient by decreasing temperature in upper section.

3.1.5- AccumulatorAt top of the column, vapors are routed to an overhead condenser, typically cooled by

water or air coolers. At the outlet of overhead condenser, liquid (naphtha) and gases are separated in an accumulator at 40oC. Gases are routed to a compressor for further recovery of LPG (C3/C4), while the liquids (Naphtha) are pumped to a stabilizer column.

3.1.6- StrippersThe products are also drawn from different trays of the column. These are called side

draw-offs. The purpose of the side stripper is to remove some light hydrocarbons by using steam

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injection. The lightest side draw-off from the fractionating column is a fraction called kerosene, boiling in the range 150-280oC, which flows into a smaller column called side-stripper. Side stripper contains three separate sections. They are kerosene, LGO and HGO stripping section respectively. Stripper contains total 28 trays. Kerosene is achieved at 354oF from first stripping section. It is run down. To make jet fuel from kerosene then kerosene is further treated.

LGO at 510oF is stripped from second stripping section. This is used as diesel oil. While from third stripping section, HGO at 663oF which is currently mixed with furnace oil as plant-4 is under construction.

3.1.7- Chemical DosingIn overhead product, total pump around and intermediate pump around we are

adding neutralizing amine and filming amine. Neutralizing amine controls pH to avoid corrosion while filming amine protects from fouling.

Figure 9 Process Flow Diagram of CDU

4- White Oil Movements

White oil movements cover the treatment of over product (Naphtha) from fractionator. Naphtha is treated in hydro treating unit then in gas treatment plant. From gas treatment plant light naphtha is treated in isomerization unit while heavy naphtha is treated in catalytic cracking unit which is under construction.

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4.1- Naphtha Hydro treating Unit (Plant-6)The purpose of hydro treating plant is to remove sulfur and nitrogen from naphtha

(overhead product of fractionator). Hydrogen is added which convert sulfur into hydrogen sulfide and nitrogen to ammonia.

The feed to this plant is the top product from the crude distillation column and consists of all material boiling below 320oF and a stream of hydrogen rich gas. The gas is the off gas from plat former, where hydrogen is produced as a byproduct. The gas is compressed by a compressor after passing through knock out drum, which removes liquids. Naphtha feed line from plant-1 is divided in two lines 1P-53 and 1P-234. 1P-234 line is treated in absorption column with hydrogen. Both lines are mixed before vessel 6C-3.

4.1.1- Feed Surge Drum (6C-3)Naphtha feed line goes to vessel 6C-3 where naphtha is flashed. Vapor goes to gas header

line while water in naphtha is accumulated at bottom due density difference. Boot is attached with vessel to collect water and drain it.

4.1.2- Pumps and Heat ExchangersTo circulate naphtha through heat exchanger, furnace and reactor, pump assembly is

used. Three pumps are installed. Boost pump is installed in series before 6G-1. Both pumps are motor driven pumps. Boost pump is for boosting pressure of naphtha. Discharge of boost pump is suction of 6G-1. This pump creates required pressure of naphtha stream. Third pump (turbine driven) is standby pump. Naphtha is pre-heated in seven shell and tube heat exchangers assembled in series. Cold naphtha flows through shell. Before pre-heating hydrogen line is added to naphtha stream. The mixture of naphtha and hydrogen is then heated up to a reaction temperature in exchangers and then passes it into a furnace to raise the temp up to 480oF.

4.1.3- Furnace (6F-1)In reactor high temperature is required. Temperature gained by pre-heating is 480oF that

is low. To boost temperature furnace is installed. Here temperature will be at 580oF.

4.1.4- Reactor (6C-1)Reactor conditions for naphtha hydro treating unit are around 580˚F and pressure of

640psig. The naphtha hydro-treating unit uses a Nickel, cobalt and molybdenum combination catalyst to remove sulfur and nitrogen by converting it to hydrogen sulfide and ammonia respectively that is removed along with unreacted hydrogen. Catalyst poisoned with time due that temperature requirement also increases. When required temperature reaches 750oF catalyst is changed. Some of the hydrogen sulfide-hydrogen mixture is recycled back to the reactor to utilize the unreacted hydrogen, using a compressor. Here the organic sulfur is converted into inorganic sulfur. Hydrotreating reactions are classified as

a- Desulfurization

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b- Denitgenation

4.1.5- Reactor Product Separator (6C-2)Product of reactor contains naphtha with dissolved H2S and unreacted hydrogen. They

are cooled in heat exchanger by losing heat to reactor feed naphtha. Before product separator, reactor product is washed by water as formation of amine chloride occurs due to addition of filming amine. Water absorbs amine chloride. In separator, product is flashed, vapors-gas vent from top while water is accumulated in boot. Vent is sent to gas header. Water from boot is regularly drained.

4.1.6- Product Flash Drum (6C-5)Product from vessel 6C-2 contains unreacted hydrogen. To recover hydrogen, product is

further flashed in 6C-5 vessel. Unreacted hydrogen recovered from top and recycled to reactor. Naphtha is sent to plant-8 for gas treatment. Currently naphtha contains hydrogen sulfide.

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Figure 10 Process Flow Diagram of Plant-6

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4.2- Gas Treatment Plant (Plant-8)The purpose of gas recovery plant is to separate the light ends from various other refining

units. The other function is to remove the light ends from the naphtha fraction of crude to produce the most useful feedstock for the plat-former. Naphtha from HTU is dived in two lines DE ethanizer and DE botanizer. Depending on composition of naphtha, it is sent in DE ethanizer or DE botanizer.

4.2.1- DE-ETHANIZER (8C-1)The purpose of this unit is to separate the ethane and lighter products from the heavy

naphtha. the naphtha from the hydro-treating unit is then fed into the de-ethanizer column. In this unit ethane and lighter products are separated from heavy naphtha along with some hydrogen sulfide. The top product ethane and methane are used as fuel gas in furnaces and boilers. The de-ethanizer column operates at an overhead accumulator of below 450psia at 125oF. The bottom product is C3 and above naphtha which leaves at 265oF. Top and bottom reflux are kept to maintain temperature. Intermediate reflux is also installed to separate water.

Column contains 29 plates. Bubble cap trays are used as vapor load is low. In top product stream from heavy naphtha bottom product of de isohexanizer is mixed. This stream is mixed to absorb higher carbon hydrocarbon from vapors. Overhead accumulator separate ethane and lower hydrocarbon from top product and send it to fuel gas.

Bottom product contains carbons C3- C10. It is feed for DE botanizer.

4.2.2- De-Butanizer (8C-5)The bottom product from the De-ethanizer column is then fed into the De-butanizer

column for further separation of lighter products. In De-butanizer the Butane and lighter products are withdrawn as the top product along with hydrogen sulfide (H2S) at 136oF and 110psig. Some of this condensate from overhead accumulator is returned as reflux. LPG’s and H2S are sent to the amine treatment plant. The botanizer has a re-boiler, which uses 200 psig streams as the heating medium. The bottom product from de-butanizer at 334oF passes into de-isohexanizer. DE-butanizer contains 24 trays.

Amine TreatmentThe de-butanizer overhead product is washed with a solution containing lean mono-

ethanol amine (MEA) to remove hydrogen sulfide and other sulfur compounds MEA absorber. The propane/butane mixture is preheated in exchanger 8E-6 and is then separated in the propane/butane splitter 8C-11. The propane vapor condenses overhead, is condensed in air cooled condenser 8E-7 and collects in accumulator 8C-12. Some of the product is returned as reflux whilst the remainder is sent to LPG storage. Rich M.E.A is sent plant-9 to remove H2S from it and make lean M.E.A. Hence plant-9 is under construction.

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Figure 11 Process flow diagram of M.E.A

4.2.3- De-Isohexanizer (8C-13)The bottom product containing C5 and higher hydrocarbons from the de-butanizer

column is then fed into the de-isohexanizer column. In this column iso-hexanes and pentanes are separated as the top product along with iso-butane called light naphtha. Light naphtha is used as the feed for isomerization unit. Bottom product contains C7 and higher hydrocarbons called heavy naphtha used as a feed for plat-forming unit.

DE iso-hexaniser is the tallest tower in BPPL and contains most fractionating trays 70. This is because it is designed to separate two materials, iso-and normal hexane, whose boiling points are very close :( 140oF and 156oF). Other purpose to maximum trays is to keep minimum amount of benzene in light naphtha. Benzene in light naphtha is not desired because it forms coke in isomerizer unit and damage catalyst.

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Figure 12 Process flow diagram of Gas treatment Plant

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4.3- Isomerization Unit (Plant-16)Isomerization unit is for conversion of n-paraffin to iso-paraffin. Iso-paraffin is branch

chain compound which has high octane number. Our basic purpose is to increase octane number of light naphtha from 65 to 95. There are two reasons for using isomerization process for light naphtha. The first is that light hydrocarbons tend to hydrocrack in reformer. Second is that C6 hydrocarbons tend to form benzene in reformer. Gasoline specification requires very low value of benzene due its carcinogenic effect.

In isomerization three units are installed. First is liquid preparation, second is panex and third is molex.

4.3.1- Liquid PreparationThe isomerization unit is specifically designed to for the continuous catalytic

isomerization of paraffin. Light naphtha from the de-isohexanizer unit is used as a feed for the isomerization unit. Feed contains contaminants like moisture and sulfide which damage expensive platinum catalyst. Water must be removed from feed as water is poison to catalyst. It is first passed through a filter unit. Two filters are installed before sulfur guard bed. Both are cartridge filter. They remove contaminants and free water.

a- Sulfur Guard BedThe feedstock is heated to a required temperature for sulfur removal, usually 250oF and

passed down flow over the adsorbent. Sulfur guard bed contains a nickel based sodium zeolite catalyst. Chemi-adsorption occur in sulfur guard bed. The purpose of sulfur guard bed is to protect the panex catalyst from sulfur in liquid feed. Sulfur is removed here.

b- DryersAfter removing of sulfur particles isomerization feed is then passed through heat

exchanger tube side and air coolers. Feed is pumped to dryers at 100oF (38oC). Low temperature must be maintained for proper drying. There are two dryers in the isomerization unit along with six control valves. The liquid feed dryers are used to dry the panex liquid feed to less than 0.1ppm. 1lb water can damage 100lb catalyst so water is kept below 0.1 ppm. Molecular sieves are used in dryer to adsorb water. The piping is designed so that either dryer can be in the lead or the lag position in series flow operation. Either dryer can be operated individually while the other is being regenerated. Makeup hydrogen to the dryers comes from the plat-forming unit at 100oF.

Allowable values of contaminants in feed are shown in table. Before sending feed in reactor, contaminants values should be below values shown in table otherwise they would activate catalyst.

Table 3 Contaminats value in Panex Feed

Contaminants Value

Sulfur <0.5ppm

Nitrogen <0.5ppm

Water <0.1ppm

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4.3.2- Panex UnitPanex is reaction unit which convert n-paraffin to iso-paraffin. Feed from dryes is sent to

surge drum by pumping.

a- Feed Surge DrumThe purpose of this drum is to provide liquid feed surge capacity for the panex unit. It

provides suction head to pump to keep high flow rate. The dried liquid feed from the feed surge drum is pumped by reactor charge pump. At discharge of pump valve is installed which is called yarway valve. This is opened when minimum flow of feed is achieved. Feed flows through the reactor exchanger. Here hydrogen combines with the hydrocarbons. After this a small quantity of Perchloro ethylene is also purged in feed as catalyst promoter. Catalyst has metal and acidic promoter sides. Transition metal traps atomic hydrogen. While acidic side of catalyst lose electron. Perchloro ethylene loses its electron to keep catalyst stable.

b- ReactorsAfter exiting the reactor charge heater, the combined stream then flows to the reactor

series. Two reactors are installed in series. In first reactor benzene is saturated by reacting benzene with hydrogen. Saturation of benzene is exothermic reaction which increases temperature of reactor while high temperature is not desired for isomerization. . After exiting the first reactor the stream then passes to the hot combined feed exchanger, where the first reactor heat of reaction is partially removed. It is then passed through the second reactor where isomerization is completed. In second reactor isomerization of hexane occurs at small temperature. Small amount of heptane present in feed is cracked into propane and butane.

c- StabilizerAfter the second reactor the stream is then routed to the cold combined heat exchanger, it

is then routed to the stabilizer. The purpose of stabilizer is to remove dissolved gases from isomerate. Steam from bottom of stabilizer is injected which removes C3, C4 and HCl (Formed from perchloro ethylene). Bottom product contains iso-paraffin and unconverted n-paraffins. Stabilizers basic purpose is to reduce Reid vapor pressure by removing gases.

d- Scrubber The gases are then passed through gas scrubber to remove hydrogen chloride. Gases are

injected from bottom while caustic soda is showered from top column. Caustic soda absorbs HCl and leaves from bottom while propane and butane from top are accumulated for further treatment.

4.3.3- Molex UnitMolex unit is installed to separate n-paraffin and iso-paraffin which are made in Panex

unit. It contain rotary valve and adsorption chamber.

The molex feed from penex stabilizer bottom, is pumped to chloride guard bed. Chloride guard bed remove chlorides from the molex feed. Cartridge filter is installed to make more pure from contaminants.

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a- Rotary ValveThe adsorbent is equally divided into eight beds contained in one chamber. At one time

there are two streams entering and two streams leaving the chamber through the bed lines connected to the rotary valve.

b- Adsorbent ChamberThe streams entering the chamber are the feed and DE-sorbent. Extract and raffinate exit

the chamber. The pump around stream continually circulates from the pump around pump to the top of the chamber, through the chamber, and back to the pump. The pump around stream is used to control the rate of flow through discrete sections of the chamber referred to as zones.

1- Adsorption Chamber (Zone 1)The normal paraffin in the feed are adsorded by the adsorbent and the iso-paraffin are

rejected.

2- Purification Chamber (Zone 2)The beds between the extract bed line and the feed bed line. Zone II acts as a non-

selective void flushing zone or purification zone.

3- Buffer (Zone 3)The bed between the DE sorbent bed line and raffinate bed line. Zone III acts as a buffer

zone separating adsorption and desorption zones.

4- Desorption (Zone4)The beds between the extract bed line and DE sorbent bed line. In zone IV the normal

paraffin in the adsorbent are desorbed and exchanged with the DE sorbent. This is referred to as the desorption zone.

c- Extract ColumnAfter passing through rotary valve the feed is then passed to the extract column. The

normal paraffin in the feed is adsorbed by the adsorbent and the iso-paraffin are reject. The extract contains straight chain hydrocarbons. The extract contains the n-paraffin and DE sorbent, leaves the chamber between zone 2 and 3.it flows through the rotary valve, protective strainers, extract mixing drum and then to the extract column.

d- Raffinate ColumnThe raffinate is the final product contains iso-pentanes and iso-hexanes and collected as

raffinate. The raffinate containing the higher octane iso-paraffin and DE sorbent leaves the chamber between zones 1 and 4, flowing through the rotary valve, and to the raffinate mixing drum. The raffinate column sends the lighter DE sorbent components overhead and drops the n-paraffin out the column bottom. The iso-paraffin are sent to storage after being cooled in the raffinate bottoms.

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5- Oil Movements

Oil movements are related to handling of crude oil before process and final products after process. It deals lodging, preparation, monitoring and transport of crude oil while it deals with achievement, supply and tank control of final product.

There are 37 tanks are installed for final product while 6 tanks for crude oil storage. Four type tanks are used for storage of oil which are following:

5.1- External Floating TankExternal floating tanks are used for crude oil storage.

5.2- Internal Floating TankInternal floating tank is used for storage of volatile products. It helps to control formation

of vapors which can cause increase in pressure.

5.3- Fixed RoofFixed roof tank is used for heavy products

5.4- Pressurized TankPressurized tank is used for gas e.g. LPG.