BOSICOR PAKISTANLIMITEDMKP-1 OIL REFINERY.

INTERNSHIP REPORT (March17,2009 - April 17,2009)

Dawood college of engineering and technology karachi

Submited by:- Muqeem khan

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ACKNOWLEDGEMENT:

Writing this report we felt highly privileged that we have worked as anInternee in BOSICOR Pakistan limited and this successful knowledge trip wouldnot have been possible without adequate support of the Esteemed ENGINEERS outthere in BPL we would like to acknowledge some of the most eminent personswho supported us in not only understanding the theoretical aspects but getting theknowledge in practical form .We feel highly delightful to acknowledge all of theManagement of BPL especially :

Engineer Haroon Rasheed Ansari (Manager Technical) Engineer Muzaffar Malik (Technical Services) Engineer Asad Raza (Technical Services) Sheikh Jameel ahmed (Manager Q.L Laboratory) Shahzad Kalim khan (Junior officer ) Iftakhir Ahmed (trainee) Engineer Faraz Sheikh (Senior Manager Operations) Engineer Furqan Ali (Manager Operations) Engineer Arif Rehman (Senior Engineer Operations) Engineer Tallat Nabi Engineer Nauman Khan (Oil moments & Logistics) Engineer Siddique (Oil moments & Logistics) Engineer Saud (Shift Incharge) Engineer Rizwan Mustufa (Shift Engineer) Mr. Malik Abdul Rehman (Shift Operator) Mr.Atta muammad (Shift Operator)

Along with Plant Management we would also like to acknowledge the Plantoperators and Foremen who gave us plethora of advices from their practicalexperience.

We are affirmative that the knowledge we got over there would accompanyus till our Job Carriers.

Once again WE ARE thankful to all of the concerned personnel who havesupported us in our knowledge seeking trip to BOSICOR PAKISTAN LIMITEDWe are LOOKING forward To Working with you soon.

Thank you BOSICOR PAKISTAN LIMITED

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DAWOOD COLLEGE OF ENGINEERING AND TECHNOLOGY KARACHI Federal Degree Awarding Institution

FOREWORD:

Reaching Bosicor Pakistan Limited for internship program I had in my mind that this Internship was not an opportunity Rather it was a responsibility and in the field I entered with the passion to learn and understand the true Chemical engineer’s Dream that is to be a part of a petroleum refinery and we had to get acquainted with the concepts of operation and we were given great response. We not only understood the Mechanism but also the types and designs of the Machines that were being used in BPL along with the Product specifications and the Storage and Transportation techniques Whatever I got there I have made sure to include that in this report of INTERNSHIP so as to reflect the inner sense of my Understandings

The Report I am writing it actually is of seven major steps:

i. Bosicor’s Introductionii. Petroleum and Its Fractions

iii. Environment, Health & Safetyiv. Laboratoryv. Utilities at Plant site

vi. Equipmentsvii. Operation of Bosicor Refinery MKP-1(On Flow Basis)

viii. Oil moments & logistics

From these descriptive topics I have covered all the knowledge that I had gathered in last 12 weeks. No Doubt I have gained a lot of Knowledge during internship period.

REGARDS Engineer Muqeem khan Dept. of chemical engineering (Dawood college of engineering and technology Karachi)

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CONTENTS

S.No. TOPICS Page No.

1. BOSICOR’S PROFILE 5

2. PETROLEUM 6

3. ENVOIRNMENT, HEALTH & SAFETY (EHS) 8

4. LABORATORY 11

5. UTILITIES 15

6. EQUIPMENTS 17

7. OPERATIONS 30

8. OIL MOMENTS & LOGISTICS 49

9. ABBREVIATIONS 54

10. REFERENCE 55

BOSICOR’S PROFILE

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COMPANY NAME Bosicor Pakistan Limited (MKP-1)OWNED BY BOSICOR GROUPESTABLISHED January 19951st COMESHNING Dec 2007REVAMP Sept – Oct 2003

ADDRESS

PLANT ADRESSMouza Kund Plant, Sub Tehsil Gidani, Near Hub PowerCompany Ltd. Power plant (HUBCO), District Lasbela,BalouchistanMANAGING OFFICEBosicor Pakistan Limited Oil Marketing Unit 6th Floor,Business Plaza,, Mumtaz Hassan Road, KarachiPhone: 021-111-222-081 (EXT: 519)

STATUSBosicor Pakistan Ltd is the fifth Oil refinery in Pakistan.

CRUDE TYPEImported (QATAR MARINE CRUDE OIL) & IRANIAN CRUDE. Collected from Ships at ZOT(PSO), Port Qasim & Local crude.

PLANT CAPACITY 30,000-35,000 barrels per day% CONTRIBUTION TO TOTAL FUEL PRODUCTION OF PAKISTAN

5% to the total Crude Production of Pakistan

Major CLIENTS PSO

STATISTICSSales(2007) 9999 Million RsNet profit(2007) 633 Million Rs

FUTURE PROJECTS

1. Additional Storage Facility2. Sub-Sea Pipeline Project (ITT)3. Isomerization Unit4. BOPL

PRODUCTION PERCENTAGE OF BPL:

FURNACE OIL 38 – 40 %HIGH SPEED DIESEL 21 – 22 %

KERO 18 – 21 %NAPHTA 18 – 20 %

LPG 6 – 8 %

PETROLEUM

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Petroleum is a naturally occurring, flammable liquid found in rock formations in the Earth, consisting of a complex mixture of hydrocarbons of various molecular weights, plus other organic compounds.

CHEMISTRY OF PETROLEUM: Crude petroleum is primarily a liquid of widely varying physical and

chemical properties.

PHYSICAL PROPERTIES:

• Color: Common colors are green, brown and black and occasionally almost white or straw color (although it may be yellowish or even greenish).

• Specific gravity: Specific gravity can range from 0.73 – 1.02; however, most crudes are between 0.80 & 0.95.

• Viscosity: Data for a large number of crudes indicate kinematics viscosities from 0.007 to 13 stokes at 100oF, though most of them range from 0.023 to 0.23 stoke.

COMPOSITION:

The hydrocarbons in crude oil are mostly alkanes, Naphthenes (cycloalkanes) and various aromatic hydrocarbons,• Alkanes, also known as paraffins, are saturated hydrocarbons with straight or

branched chains which contain only carbon and hydrogen and have the general formula CnH2n+2.

• Cycloalkanes, also known as napthenes, are saturated hydrocarbons which have one or more carbon rings to which hydrogen atoms are attached according to the formula CnH2n. Cycloalkanes have similar properties to alkanes but have higher boiling points.

• Aromatic hydrocarbons are unsaturated hydrocarbons which have one or more planar six-carbon rings called benzene rings, to which hydrogen atoms are attached with the formula CnHn. They tend to burn with a sooty flame, and many have a sweet aroma.

While the other organic compounds contain nitrogen, oxygen and sulfur, and trace amount of metals such as iron, nickel, copper and vanadium. The exact

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molecular composition varies widely from formation to formation but the proportion of chemical elements varies over fairly narrow limits as follows:

Element % RangeCarbon 83-87%

Hydrogen 10-14%

Oxygen 0.1-2%Nitrogen 0.1-1.5%

Sulfur 0.5-6%

CLASSIFICATION:

Crudes are commonly classified according to the residue of their distillation, this depending on their relative contents of three basic hydrocarbons: paraffins, naphthenes, and aromatics. About 85% of all crude fall into following three classifications:

• Asphalt-base: containing very little paraffin wax and a residue primarily asphaltic (predominantly condensed aromatics). Sulfur, oxygen, and nitrogen contents are often relatively high. Light and intermediate fractions have high percentages of naphthenes. These crude oils are particularly suitable for making high quality of gasoline, machine lubricating oils, and asphalt.

• Paraffin-base: containing little or no asphaltic materials, are good source of paraffin wax, quality motor lube oils, and high-grade kerosene. They usually have lower non hydrocarbon content than do the asphalt base crudes.

• Mixed-base: containing considerable amounts of both wax and asphalt. Virtually all products can be obtained, although at lower yields than from the other two.

Generally Crude consists of following fractions:

Name of fraction Carbon atom range Boiling point range(oC)Natural gas C1 – C4 Below 20

LPG C3 – C4 Below 20Light naphtha C6 – C7 60 – 100

Gasoline C5 – C10 40 – 200kerosene C12 – C18 175 – 325

Gas oil or Diesel oil C12 and higher 250 – 400Lubrication oil C20 and up Non-volatile liquids

ENVOIRNMENT, HEALTH & SAFETY (EHS)

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SAFETY: Safety is the state of being "safe", the condition of being protected against

physical, social, spiritual, financial, political, emotional, occupational, psychological, educational or other types or consequences of failure, damage, error, accidents, harm or any other event which could be considered non-desirable. This can take the form of being protected from the event or from exposure to something that causes health or economical losses. It can include protection of people or of possessions

GENERAL SAFETY: Safety is generally interpreted as implying a real and significant impact on

risk of death, injury or damage to property. Safety measures are activities and precautions taken to improve safety, i.e. reduce risk related to losses.

SAFETY AGAISNT FIRE: The biggest danger which BOSICOR can face is fire. As it is an oil refinery

which deals with the fuel which in any condition can burn steadily and can destroy the plant area and even the workers working there.

THE FIRE TRIANGLE:

Fire can be produced by the presence of all the three mediums present in the fire triangle:

• Fuel.• Oxygen (20.9% in Air).• Burning medium or Heat.

If it is needed to remove the fire from any place the fire triangle must be broken. Meaning any of the 3 members must be removed to stop the fire.

TYPE OF FIRE: There are 4 types of fire:• Solid / Combustible.• Liquid / Flammable.• Gas / Electric.• Metal.

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QUENCHING THE FIRE: Following are some of the ways through which we can remove the fire:• Smothering• Starvation• Cooling

Few types of equipment are used which help us controlling fire:• DCP (Dry Chemical Powder)• Carbon dioxide• Foam (Chemical and mechanical)• Water

SAFETY DEPARTMENT: BOSICOR has it department for safety. The work of this department is to

monitor all the plant area and take all the precautions to protect the plant and even to protect all the workers at the plant. More then that it is also capable for tackling any emergency situation at the plant area or at the whole covered area.The objectives of this department are as follow:

• To ensure there is no fire at the plant area, and taking it out if any.• To ensure that fire extinguishers are placed at the plant in good and working condition where ever it is needed.• To ensure that every worker at the plant is wearing PPE (Personal Protective Equipments).• To ensure no one carries any thing which can burn or can help burning. e.g. (match boxes, lighters, mobile phones, or batteries).• To provide electronic equipments with IS (Intrinsically Safe) batteries.

PRACTICING THE CAPABILITIES: Apart from all the safety provided by the department, this department also

tests its and the workers skills at times:• Fire drills are held time to time to train workers of different department.• Safety alarms are rung to prepare workers for any emergency situation.• To check emergency equipments from time to time.

PRECAUTIONS: BOSICOR uses the following sources or equipments for safety:

PPEs (Personal Protective Equipments):Safety features are followed by every worker at the industry. All the workers wear PPEs for their safety. This includes:

• Hard Helmets• Safety Shoes• Safety Cover (Dungaree)• Gloves, Air Filters, Goggles at sensitive areas

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• Body Safety Harness at height.

SAFETY EQUIPMENTS: This includes equipments which help in alerting from emergency situations:• Fire Alarms• Smoke Detectors• PCV (Pressure Control Valves)• TCV (Temperature Controlling Valves)• LCV (level Control Valves)• Trippers• Safety Valves• Triggers

WORK PERMITS (PTW): These permits are classified by the work that is required to be done:

• Hot Work Permit: This includes the work in which sparks are produced.• Cold Work Permit: Activates involve working in plant areas• Excavation Work Permit: Including civil work• Confined Space Entry Certificate: e.g. Work inside Confined Spaces.

Quality control section of BOSICOR

The laboratary of BPL is a well equipped lab. Even though it is not an ISO 17004 certified lad but the apparatus are regularly calliberated and record is well maintained. The staff is very helpful and hardworking and they have command over their work. Research work is also carried out for the better product yield and best quality products. During my visit research work was taking place to bring down the pour point of furnace oil according to the demand of the customer. The laboratary works 24 hrs a day.

QUALITY TEST: Quality is controlled in the industry to make there products marketable.

Standards are set and maintained which is an important thing. The quality is tested time by time and is reported to the engineers where they compare the results with the standard.

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Compounds being tested in BPL LAB 1. Qatar marine crude oil2. LPG3. Naphtha4. Motogas5. Kerosene6. HSD7. Furnace oil8. Boiling and cooling water

General test performed in BPL LAB

TEST TEST METHOD

1. canradson carbon residue ASTM-D189

2. ASTM colour ASTM-D156

3. Cloud point and Pour point ASTM-D97

4. Oxidation stability of Gasoline -

5. Sulphur in petroleum products ASTM-D1551

6. Doctors test for petroleum distillate

ASTM-D484

7. Cu strip test ASTM-D130

8. Distillation of petroleum products ASTM-D484

9. Flash point ASTM-D93

10. Specific gravity ASTM-D1298

11. Reid Vapor pressure ASTM-D323

12. Otane no research ASTM-D269913. Cetane index ASTM-D976

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LABORATORY SPECIFICATIONS LPG:Time: 11:00 pm TEST # V-4: Batch # 030/08

TEST RESULTSSpecific Gravity 0.5620

Weathering +1Cu Strip Ia

Vapor Sulfur 36RSH 32

Vapor Pressure 140

QATAR MARINE CRUDE OIL:TMB COMPOSITE TOP MID BOTTOM

Specific Gravity 0.8776 0.8768 0.8768 0.775Bs & W 0.5 0.4 0.4 0.5

DISTILLATION:

IBP (OC)

5% 10% 20% 30% 40% 50% 60%

60 92 122 178 233 287 333 358Cracking Point = 363; Total Recovery =63 %

KEROSENE:20 % Recovery max 200 CE.pt max 300 C

DISTILLATION:

TEST RESULTSSpecific Gravity Max. 0.820

Color Min. 20Flash Min. 37oC

Smoke Point Min. 22oCTotal Sulfur max 0.15Doctor Test -ve

Odor marketable

MOTOR SPIRIT:Specific Gravity = 0.7687

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DISTILLATION:IBP (OC)

5% 10% 20% 30% 50% 70% 90% 95% F.B.P

47 60 77 178 103 115 130 144 153 159

TEST RESULTSRVP Max.9RSH <0.01

Cu Corrosion IaEx. Gum Max.4

Oxidant Stability > 240Doctor Test -ve

RON Min. 85

HSD (ULTRA WINTERIZED): Specific Gravity = 0.8221DISTILLATION:

IBP (OC) 10% 50% 90% F.B.P167 189 238 309 338

TEST RESULTSCOLOUR max 3

Total Sulfur max 1Flash Point min 65 C

Viscosity 44 ssuCloud Point max 30Pour Point max 20

CCR max 0.1Ash max 0.1

Sediments max 0.1Water max 0.05

C I max 47TAN max 0.5SAN NIL

FURNACE OIL: Specific Gravity = 0.9 – 0.97

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TEST RESULTSTotal Sulfur max3.5Flash Point min 660 C

Viscosity 600-1000Pour Point max 240 C

CCR min 0.25Ash max 0.1

Sediments max 0.15Water max 0.5

C V 17400SAN NIL

BOILER FEED WATER :

TEST RESULTSPH 8.2-10

Total Hardness max 2 ppm

BOILER BLOW DOWN WATER:

TEST RESULTSPH 10.5-11.5

TDS, ppm max 3500ppmOH alkalinity, ppm min 100ppm

Sulphite, ppm 30-70ppmPhosphate, ppm 20-50ppm

T. Iron, ppm max 2 ppm

COOLING WATER:

TEST RESULTSPH 8-9

TDS 1500-1800 ppmTotal Hardness max 800 ppmTotal Alkanity 250-300 ppm

Total Zinc 2-3 ppmFree Chlorine 0.3-0.6 ppm

T. Iron max 1 ppm

UTILITIES

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Utilities play an important role in process of any Industry. Following are few of the utilities used in BOSICOR:

BOILER: The steam requirement of the industry is fulfilled by two boilers in

BOSICOR.Types of both of them are:

• Fire Tube Boiler• Water Tube boiler

Water from reservoir is soften first by the help of chemical injection and all salts of Mg+2 and Ca+2 which produce hardness are converted into the salts of Na+ which don’t produce hardness.

Capacity: 10 ton Pressure: 120 psi

Then it is passed through Deaerator where salts of PO4-3 and SO3-1 are injected where oxygen is removed from the water. After that it is injected to Economizer and then to the Boiler. Where water is converted into steam and then it is used further.

sBoiler on panel specification:-

S.No RANGES ResultsFeed water totalizer flow 4900lb/hr 4800Steam flow totalizer flow 4400lb/hr 4300

Steam pressure 115psi 114psiSteam temperature 200C 176CStack temperature - 206C

Fueal oil flow 130lb/hr 120lb/hrWater level gauge 50 46.7 15

COOLING TOWERS:

Cooling towers are heat removal devices used to transfer process waste heat to the atmosphere. Cooling towers may either use the evaporation of water to remove process heat and cool the working fluid to near the wet-bulb air temperature or rely solely on air to cool the working fluid to near the dry-bulb air temperature.It is an important part of any refinery it is used to cool hot water circulated from the refinery, which is re-used after cooling.

In BOSICOR we have two cooling towers: • THE OLD TOWER:

The old cooling tower consists of six fans and it is of counter current type.• THE NEW TOWER: The new tower consists of one fan which is cross flow type.

CHEMICAL DOSING : Following are few of the chemicals which are injected in cooling water:• SCGon 345• SCGon 019• Biocon 975• Calcium Hypo chloride

There chemicals are for different purposes:• Corrosion inhibiters and Anti- scaling• Hardness maintaining• Maintains the pH• Anti- microbes

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TEST RANGESpH 8-9

TDS 1500TH 1000T, A 250Zinc 2-3Fe Max. 1

ELECTRIC GENERATION: BPL has its own dependable electric power generation facility consist of 6

generators out of which 4 meets plant requirements, 3 in working condition ,1 stand-by. Each having 1.5 MW capacity producing 60Hz of electricity. Apart from that 2 for electrical official requirement, 1 in working 1 stand-by producing 500KVA 50Hz.

INSTRUMENTAL AIR:

Nearly all of the instruments are pneumatic. So pressurized air is required for there working.

The air is supplied by the compressors one of which is in working condition and other is stand-by. The compressor has its capacity 650 m3/hr and its working pressure is 7.6 – 8.4 bar. The other standby is 345 m3/hr it can produce 6.5 – 8.5 bar pressure.

EQUIPMENTS:

In this section the brief detail of some most important equipments, whichacts as a backbone of an oil refinery, is given,without the knowledge of which, it is

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impossible to understand the processs.

HEAT EXCHANGER: A heat exchanger is a device built for efficient heat transfer from one medium toanother; both the Medias are separated by a solid wall so that they never mix. Theyare extensively used in petroleum refineries over a wide range for variouspurposes, such as:• Heating the crude streams up to desired temperature before entering thedesalters.• Cooling the product streams to ambient temperatures. e.t.c.• As a condenser for condensing the vapors.• As a reboiler for maintaining the columns bottom temperature.

SHELL & TUBE HEAT EXCHANGERS:

The shell & tube heat exchanger is a bundle of tubes connected together ateach end in plates called tube sheets. The tube sheet provides the seal between thetube bundle & the shell, which isolates the process from the service. It is veryimportant that the seals are leak-proof to prevent cross-contamination of the fluidson the tube & shell sides. The basic shell & tube heat exchanger serves equally wellas a cooler, heater, evaporator, condenser with minor design changes in shape andarrangement.The shell is a cylinder into which the tube bundle is housed. The ends of the shellare sealed with plates called heads. The head can be flat or dish-shaped in design.Following are the few main parts of the heat exchanger:• Shell• Tubes• Floating head• Channel head• Baffles

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CONDITION THAT AFFECTS HEAT TRANSFER: • Proper Mixing of Medium• Transfer Area• Evaporation of Medium• Arrangement of Shell and Tubes

Flow arrangement Heat exchangers may be classified according to their flow arrangement. In parallel-flow heat exchangers, the two fluids enter the exchanger at the same end, and travel in parallel to one another to the other side. In counter-flow heat exchangers the fluids enter the exchanger from opposite ends. The counter current design is most efficient, in that it can transfer the most heat from the heat (transfer) medium. See countercurrent exchange. In a cross-flow heat exchanger, the fluids travel roughly perpendicular to one another through the exchanger.

For efficiency, heat exchangers are designed to maximize the surface area of the wall between the two fluids, while minimizing resistance to fluid flow through the exchanger. The exchanger's performance can also be affected by the addition of fins or corrugations in one or both directions, which increase surface area and may channel fluid flow or induce turbulence.

The driving temperature across the heat transfer surface varies with position, but an appropriate mean temperature can be defined. In most simple systems this is the log mean temperature difference (LMTD). Sometimes direct knowledge of the LMTD is not available and the NTU method is used.

Fig. 1: Shell and tube heat exchanger, single pass (1-1 parallel flow)

Fig. 2: Shell and tube heat exchanger, 2-pass tube side (1-2 crossflow)

Fig. 3: Shell and tube heat exchanger, 2-pass shell side, 2-pass tube side (2-2 countercurrent)

FOULING: Deposition of undissolved particles in the exchngers that reduces the flow iscalled fouling can be caused by:• Frequent use of the Heat Exchanger.

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• Not cleaning the Heat Exchanger regularly.• Reducing the velocity of the fluids moving through the heat exchanger.• Over-sizing of the heat exchanger.

FURNACE:

An industrial furnace or direct fired heater is equipment used to provide heatfor a process or can serve as reactor which provides heats of reaction, and is used inall petroleum refineries. Furnace is that part of petroleum refinery which controlsthe economics of whole plant. So efficient operation of furnace is vital.Fuel flows into the burner and is burnt with air provided from an air blower. The flames heat up the tubes, which in turn heat the fluid inside in the first part of the furnace known as the radiant section or firebox. In this chamber where combustion takes place, the heat is transferred mainly by radiation to tubes around the fire in the chamber. The heating fluid passes through the tubes and is thus heated to the desired temperature. The gases from the combustion are known as flue gas. After the flue gas leaves the firebox, most furnace designs include a convection section where more heat is recovered before venting to the atmosphere through the flue gas stack. Following are some of the main parts of the furnace:

Radiant Section : The radiant section is where the tubes receive almost all its

heat by radiation from the flame. Convection section: The convection section is located above the radiant

section. Heat transfer takes place by convection here, and the tubes are finned toincrease heat transfer.

• Burner : The burner in the vertical, cylindrical furnace is located in the floor and fires upward. The burner is made of high temperature refractory and is where the flame is contained in. Air registers located below the burner. A furnace can be lit by a small pilot flame. Most pilot flames now a days are lit by an ignition transformer (much like a car's spark plugs). The pilot flame in turn lights up the main flame. When using liquid fuels, an atomizer is used, otherwise, the liquid fuel will simply pour onto the furnace floor and become a hazard.

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• Furnace draft: This draft, or difference of pressure is caused by the differencebetween the weight of the vertical column of the hot flue gas in the furnace stack and the weight of the column of the cooler outside air of the same height. The cooler, outside air is heavier. As outside air enters the opening around the furnace burners, it’s greater weight causes it to rush through these opening and push the lighter, hotter flue gases up the stack.. In this manner the movement of air through the furnace becomes continuous.

• Soot blower: Soot blowers are found in the convection section. As this sectionis above the radiant section and air movement is slower because of the fins, soottends to accumulate here. Soot blowing is normally done when the efficiency ofthe convection section is decreased.

• Stack: The flue gas stack is a cylindrical structure at the top of all the heattransfer chambers. The breeching directly below it collects the flue gas andbrings it up high into the atmosphere where it will not endanger personnel.

• Insulation: Insulation is an important part of the furnace because it preventsexcessive heat loss. Refractory materials such as firebrick, castable refractoriesand ceramic fiber, are used for insulation.

Centrifugalpump

A centrifugal pump is a rotodynamic pump that uses a rotating impeller to increase the pressure of a fluid. Centrifugal pumps are commonly used to move liquids through a piping system. The fluid enters the pump impeller along or near to the rotating axis and is accelerated by the impeller, flowing radially outward into a diffuser or volute chamber, from where it exits into the downstream piping system.

Centrifugal pumps are used for large discharge through smaller heads

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How it works

A centrifugal pump works by the conversion of the rotational kinetic energy, typically from an electric motor or turbine, to an increased static fluid pressure. This action is described by Bernoulli's principle. The rotation of the pump impeller imparts kinetic energy to the fluid as it is drawn in from the impeller eye (centre) and is forced outward through the impeller vanes to the periphery. As the fluid exits the impeller, the fluid kinetic energy (velocity) is then converted to (static) pressure due to the change in area the fluid experiences in the volute section. Typically the volute shape of the pump casing (increasing in volume), or the diffuser vanes (which serve to slow the fluid, converting to kinetic energy in to flow work) are responsible for the energy conversion. The energy conversion results in an increased pressure on the downstream side of the pump, causing flow.

Multistage Centrifugal Pumps

A centrifugal pump containing two or more impellers is called a multistage centrifugal pump. The impellers may be mounted on the same shaft or on different shafts. A multistage centrifugal pump has the following two important functions:

To produce a high head, and

To discharge a large quantity of liquid.

If a high head is to be developed then the impellers are mounted on same shaft (series) while for large quantity of discharge of liquid, the impellers are mounted on different shafts (parallel).

Net Positive Suction Head NPSH is an acronym for Net Positive Suction Head. It shows the difference, in any cross-section of a generic hydraulic circuit, between the pressure and the liquid vapor pressure in that section.

NPSH is an important parameter, to be taken into account when designing a circuit : whenever the liquid stagnation pressure drops below the vapor pressure, liquid boiling occurs, and the final effect will be cavitation: vapor bubbles may reduce or stop the liquid flow. Centrifugal pumps are particularly vulnerable,

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whereas positive displacement pumps are less affected by cavitation, as they are better able to pump two-phase flow (the mixture of gas and liquid), however, the resultant flow rate of the pump will be diminished because of the gas volumetrically displacing a disproportion of liquid.

The violent collapse of the cavitation bubble creates a shock wave that can literally carve material from internal pump components (usually the leading edge of the impeller) and creates noise that is most often described as "pumping gravel". Additionally, the inevitable increase in vibration can cause other mechanical faults in the pump and associated equipment.

Considering the circuit shown in the picture, in 1-1 NPSH is :

NPSH = P0 + H − Y − Vt

(to be solved with coherent measuring units), where Y is the friction loss between 0-0 and 1-1, and Vt the liquid vapour pressure at the actual temperature in section 1-1.

In pump operation, two aspects of this parameter are called respectively NPSHA or NPSH (a) Net Positive Suction Head (available) and NPSHR or NPSH(r) or NPSH-3 Net Positive Suction Head (required), where NPSH(a) is the suction pressure presented at the pump inlet port, and NPSH(r) is the suction pressure limit at which the pump's total differential head performance is reduced by 3% due to cavitation. It's important to note that cavitation occurs at suction pressure levels above the NPSH-3 level and pump damage can occur from cavitation even though the pump may continue to provide the expected hydraulic performance.

DISTILLATION COLUMN

Design and operation of a distillation column depends on the feed and desired products. Given a simple, binary component feed, analytical methods such as the McCabe-Thiele method or the Fenske equation can be used to assist in the design. For a multi-component feed, computerized simulation models are used both for design and subsequently in operation of the column as well. Modeling is also used to optimize already erected columns for the distillation of mixtures other than those the distillation equipment was originally designed for.

When a continuous distillation column is in operation, it has to be closely monitored for changes in feed composition, operating temperature and product composition. Many of these tasks are performed using advanced computer control equipment.

Column feed

The column can be fed in different ways. If the feed is from a source at a pressure higher than the distillation column pressure, it is simply piped into the column. Otherwise, the feed is pumped or compressed into the column. The feed may be a superheated vapor, a saturated vapor, a partially vaporized liquid-vapor mixture,

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a saturated liquid (i.e., liquid at its boiling point at the column's pressure), or a sub-cooled liquid. If the feed is a liquid at a much higher pressure than the column pressure and flows through a pressure let-down valve just ahead of the column, it will immediately expand and undergo a partial flash vaporization resulting in a liquid-vapor mixture as it enters the distillation column.

Improving separation

Fig1: Simplified chemical engineering schematic of Continuous Fractional Distillation tower separating one feed mixture stream into four distillate and one bottoms fractions

Although small size units, mostly made of glass, can be used in laboratories, industrial units are large, vertical, steel vessels known as "distillation towers" or "distillation columns". To improve the separation, the tower is normally provided inside with horizontal plates or trays as shown in fig2, or the column is packed with a packing material. To provide the heat required for the vaporization involved in distillation and also to compensate for heat loss, heat is most often added to the bottom of the column by a reboiler, and the purity of the top product can be improved by recycling some of the externally condensed top product liquid as reflux. Depending on their purpose, distillation columns may have liquid outlets at intervals up the length of the column as shown in fig1.

Reflux

Large-scale industrial fractionation towers use reflux to achieve more efficient separation of products. Reflux refers to the portion of the condensed overhead

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liquid product from a distillation tower that is returned to the upper part of the tower as shown in fig1. Inside the tower, the downflowing reflux liquid provides cooling and partial condensation of the upflowing vapors, thereby increasing the efficacy of the distillation tower. The more reflux that is provided, the better is the tower's separation of the lower boiling from the higher boiling components of the feed. A balance of heating with a reboiler at the bottom of a column and cooling by condensed reflux at the top of the column maintains a temperature gradient (or gradual temperature difference) along the height of the column to provide good conditions for fractionating the feed mixture. Reflux flows at the middle of the tower are called pumparounds.

Changing the reflux (in combination with changes in feed and product withdrawal) can also be used to improve the separation properties of a continuous distillation column while in operation (in contrast to adding plates or trays, or changing the packing, which would, at a minimum, require quite significant downtime).

Plates or trays

fig2: Cross-sectional diagram of a binary fractional distillation tower with bubble-cap trays.

Distillation towers (such as in fig1) use various vapor and liquid contacting methods to provide the required number of equilibrium stages. Such devices are commonly known as "plates" or "trays".Each of these plates or trays is at a different temperature and pressure. The stage at the tower bottom has the highest pressure and temperature. Progressing upwards in the tower, the pressure and temperature decreases for each succeeding stage. The vapor-liquid equilibrium for

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each feed component in the tower reacts in its unique way to the different pressure and temperature conditions at each of the stages. That means that each component establishes a different concentration in the vapor and liquid phases at each of the stages, and this results in the separation of the components. Some example trays are depicted in fig2. A more detailed, expanded image of two trays can be seen in the theoretical plate article. The reboiler often acts as an additional equilibrium stage.

If each physical tray or plate were 100% efficient, than the number of physical trays needed for a given separation would equal the number of equilibrium stages or theoretical plates. However, that is very seldom the case. Hence, a distillation column needs more plates than the required number of theoretical vapor-liquid equilibrium stages.

Overhead system arrangements

Fig1 and 2 assume an overhead stream that is totally condensed into a liquid product using water or air-cooling. However, in many cases, the tower overhead is not easily condensed totally and the reflux drum must include a vent gas outlet stream. In yet other cases, the overhead stream may also contain water vapor because either the feed stream contains some water or some steam is injected into the distillation tower (which is the case in the crude oil distillation towers in oil refineries). In those cases, if the distillate product is insoluble in water, the reflux drum may contain a condensed liquid distillate phase, a condensed water phase and a non-condensible gas phase, which makes it necessary that the reflux drum also have a water outlet stream.

COMPRESSORSA gas compressor is a mechanical device that increases the pressure of a gas by reducing its volume.Compressors are similar to pumps: both increase the pressure on a fluid and both can transport the fluid through a pipe. As gases are compressible, the compressor also reduces the volume of a gas. Liquids are relatively incompressible, so the main action of a pump is to pressurize and transport liquids.

Types of compressors

The main types of gas compressors are illustrated and discussed below:

Centrifugal compressors Centrifugal compressors use a muskan rotating disk or impeller in a shaped housing to force the gas to the rim of the impeller, increasing the velocity of the gas. A diffuser (divergent duct) section converts the velocity energy to pressure energy. They are primarily used for continuous, stationary service in industries

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such as oil refineries, chemical and petrochemical plants and natural gas processing plants. Their application can be from 100 hp (75 kW) to thousands of horsepower. With multiple staging, they can achieve extremely high output pressures greater than 10,000 psi (69 MPa).

(Centrifugal compressors)

Reciprocating compressors

Reciprocating compressors use pistons driven by a crankshaft. They can be either stationary or portable, can be single or multi-staged, and can be driven by electric motors or internal combustion engines.[1][4] [5] Small reciprocating compressors from 5 to 30 horsepower (hp) are commonly seen in automotive applications and are typically for intermittent duty. Larger reciprocating compressors well over 1,000 hp (750 kW) are still commonly found in large industrial and petroleum applications. Discharge pressures can range from low pressure to very high pressure (>6000 psi or 41.4 MPa). In certain applications, such as air compression, multi-stage double-acting compressors are said to be the most efficient compressors available, and are typically larger, noisier, and more costly than comparable rotary units.

Diaphragm compressors A diaphragm compressor (also known as a membrane compressor) is a variant of the conventional reciprocating compressor. The compression of gas occurs by the movement of a flexible membrane, instead of an intake element. The back and forth movement of the membrane is driven by a rod and a crankshaft mechanism. Only the membrane and the compressor box come in touch with the gas being compressed.

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ELECTRICAL DESALTER:An electrical desalter is a process unit on an oil refinery that removes saltfrom the crude oil by meals of electrical field. The salt is dissolved in the water inthe crude oil, not in the crude oil itself.

WHY DESALT CRUDE?

• The salts that are most frequently present in crude oil are Calcium, Sodium andMagnesium Chlorides. If these compounds are not removed from the oil severalproblems arise in the refining process. The high temperatures that occurdownstream in the process could cause water hydrolysis, which in turn allowsthe formation of hydrochloric acid.• Sand, Silts, Salt deposit and Foul Heat Exchangers.• Water Heat of Vaporization reduces crude Pre-Heat capacity.• Sodium, Arsenic and Other Metals can poison Catalysts.• Environmental Compliance, i.e., By removing the suspended solids, whichmight otherwise become an issue in flue gas opacity norms, etc.,A typical desalter comprised of a vessel, electric transformer, oil outlet header,electrodes, inlet header, water effluent header, mud wash header and mixing valve.The vessel is a horizontal gravity settling vessel in which brine water is separated from the crude oil..Electrical desalting process consists of two steps. the first step consist of forming an emulsion of crude oil & water. Second step is a demulsification process in which the emulsion of crude oil & water formed in the first step is broken by means of an electrical field.

DESALTER PRINCIPLE:

Oil/water separation in desalter based on a gravitational separation. Because

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water has a higher density than oil, water droplets have a tendency to settle down.Stokes’ Law: which results,“If the particles are falling in the viscous fluid by their own weight due to gravity,then a terminal velocity, also known as the settling velocity, is reached when thisfrictional force combined with the buoyant force exactly balances the gravitationalforce. The resulting settling velocity (or terminal velocity) is given by:

where:• Vs is the particles' settling velocity (m/s) (vertically downwards if ρp > ρf,, in thiscase ρp = ρw & ρf = ρcrude

• g is the gravitational acceleration (m/s2),• ρp is the mass density of the particles (kg/m3), and• ρf is the mass density of the fluid (kg/m3).• Μ is the dynamic viscosity of the fluid, through which the particles are falling.

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OPERATIONS

PROCESS FLOW: This portion includes the brief discussion of, process flow of BPL (MKP-1),

nearly all the aspects are covered including the decantation up to shipping, detail of various equipments has been covered in the last portion, but further explanation of technicalities involved in process is also discussed wherever necessary. Also the PFD’s of different unit’s are given for better understanding of process.The whole process flow is divided into three segments.

PRE-REFINING FLOW: In this division various operations, which are performed before refining area, are discussed.

DECANTING SECTION: This section serves for unloading crude oil being transported from ZOT

through bowsers. Before receiving the crude oil bowsers are inspected for the crude level by dip rod for any loss during transportation. After inspecting the level bowsers are allowed to move towards oil gantries, where crude is pumped from bowsers to the storage tanks located nearby. There are 16 gantries, so at a time 16 bowsers are unloaded. Crude bowsers have nearly 50,000-60,000 Lit. capacity. It takes nearly 45 minutes to withdraw the crude from bowsers.

STORAGE TANKS: There are four storage tanks for crude oil having the total storage capacity of

200000 bbl (approx.). Oil from bowsers is pumped to storage tanks (TK-01/02/03/05), where settling time of 3-4 hr. is provided for settling the water down by gravity, after which water is drained out through drainage line, after this mixer is turned on for homogenizing the crude mixture & mixing the sludge (mainly the heavier particles of crude), settled down at bottom during settling time provided for settling of water.

BOOSTER PUMPS: Crude oil from storage tanks flows into the suction of crude booster pumps D3-0452 A/B. these pumps provide part of necessary head required to move the crude oil through the crude charge system.

REFINING: This section includes various operations & processes performed with crude.

This section is further sub-divided into different sections on the basis of different units of MKP-1.

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CRUDE DISTILLATION UNIT: This unit performs the basic distillation process and separates the crude feed

into different fractions. This section includes mainly desalters, PF tower, furnace, distillation column, naphtha splitter& strippers. After fractionation the different fractions goes to different units for further processing.

MAIN PFD LINEUP:

CHEMICAL INJECTION:

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Two chemicals are injected into crude oil line ahead of crude charge pumps by PD pumps, for diverse purposes. Chemicals & their relative details are given in the table.

CHEMICAL NAME PURPOSE FEED RATE/RATIOCaustic solution Controlling the pH 10-20 ppm

Demulsifier Breaking the emulsion. 0-10 ppm

CHARGE PUMPS: The crude pumped by booster pumps divided into two streams ahead of

crude charge pumps & then flows separately into the suction of crude charge pumps D3-201/202 & D3-601A/B. These pumps provide remainder necessary head required to move the crude oil through the crude charge system. Crude from the\ discharge of charge pumps then separately flows into heat exchanger trains (named old & new), for recovering the heat (energy) from hot product streams & attaining the temperature necessary for desalting & again exchanging heat separately with various streams for achieving the temperature necessary for pre-flash tower operation (note: exchanger trains are sub-classified as A & B on the basis of pre-desalter & post-desalter streams)

OLD TRAIN (A): Crude from charge pump D3-201/202 via FCV-609 divided into two parallel

streams, one flowing to the tube side of crude v/s FFO exchangers (D2-204-A/B/C) & other flowing to the tube side of heat exchanger (D2-205-A/B/C). Both streams leaving the exchangers recombine and flow to tube side of crude v/s OH exchanger (D2-201) & then flowing to the tube side of crude v/s FFO exchanger (D2- 206). The stream from here goes to the desalter 2.

NEW TRAIN (A): Crude from discharge of charge pump D3-601-A/B divided into two streams,

one flowing through shell side of crude v/s TPA exchanger(D2-601) & the other flowing through crude v/s HSD exchanger(D2-602), the two streams leaving the exchangers recombine & then again splitting into two stream, one flowing through tube side of crude v/s kero exchanger(D2-603) & other flowing through crude v/s FFO exchanger(D2-604-A/B). The two streams then recombine and flowing to the tube side of crude v/s TPA exchanger (D2-605). This stream then goes to desalter 1.

DESALTERS: Streams from old & new exchanger trains separately flows to desalter-2(D8-

VXX20) & desalter-1 (D8-207) respectively. At the inlet of desalters fresh water is injected at the rate of 4-5%vol. of crude into these two streams, which then passes along with crude through the static mixer to form the emulsion. In the desalters the water with salts is separated from crude oil, drawn up from vessels by means of interface level controllers and then flows through the shell side of desalter water

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exchanger where it is cooled, by exchanging heat with fresh water inlet stream of desalters, and sent to oily sewer.

OLD TRAIN (B): Crude from desalter-2 enters the shell side of crude v/s HSD exchanger (D2-

213) and than passes from tube side of crude v/s HSD (D2-208) exchanger, then splitting into two streams one flowing through the tube side of crude v/s FFO exchanger(D2-216-A/B) & other flowing through tube side of crude v/s FFO(D2-210) exchanger. The two streams then combine and then flow through HE (D2-610) & goes to pre-flash tower.

NEW TRAIN (B): Crude from desalter-1 enters the tube side of crude v/s HSD exchanger (D2-

606), then splitting into two streams, one flowing through the shell side of HE (D2- 608-A/B) & other flowing through the tube side of crude v/s HSD exchanger (D2- 607).The two streams then recombine and pass through shell side of crude v/s FFO exchanger (D2-609-A/B) and then goes to pre-flash tower.

PRE-FLASH TOWER: Crude through new train & old train by a PCV-680 & PCV-670 combines

and enters at the tray#16 of pre-flash tower (D8-601). Pre- flash tower recover most of the light ends and a part of the light naphtha. PF tower OH via fan cooler (D2-613) goes to PF OH drum. Where un condensates (gases) are removed from top & from bottom naphtha is obtained, a part of which returns back to the tower as a reflux & remaining part is sent to the naphtha splitter. PF tower bottom is pumped by the pumpD3-604-A/B, then divided into two streams, one flowing through PF bottom v/s HSD exchanger (D2-615) & the other flowing through PF bottom v/s FFO exchanger (D2-614), the two streams then combine and again splitted into two streams, one flowing through shell side of HE (D2-616) & the other flowing through tube side of HE (D2-617-A/B). The two streams then combine and goes to born heater.

BORN HEATER: Crude from bottom of PF tower after exchanging heat in various heat

exchangers flows to the born heater which provides the temperature necessary for desired distillation. Crude before entering the heater divided into two streams, the flow of both streams is controlled by FCV-604 & FCV-605. These two streams enter the convection section of heater, where it is heated by the hot flue gases. Saturated steam also enters the convection section & gets superheated, which is in turn use for injecting into crude tower. Crude oil from convection section then enters into tubes located in radiation section and heated up to temperature of 350~360oC. After attaining the required temperature the crude streams leave the heater and combines then goes to crude tower. Crude oil entering the crude tower has the vapor-liquid composition of 60% &40% respectively. Heater has 10 burners and is dual fired thus having the both options of firing with fuel oil or fuel gas, or with both at a time.

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Fuel oil comes through PCV------& fuel gas through PCV-118. Atomizing steam is also provided for proper dispersion of fuel oil which is necessary for good & complete combustion of fuel oil; otherwise fuel will not burn completely &falls on floor. For proper atomizing the SH steam & FO mixture in the ratio of 1.5:1 is good choice.

CRUDE TOWER: The vapor liquid mixture of crude oil from crude heater enters the flash zone

of crude tower (D8-02010) for desired distillation. Also the SH steam is injected at the bottom of tower for stripping (removing) the lighter ends from reduced crude. Above the designed capacity steam feed rate will add to the heat liad of the tower.

Steam rate below the designed rate will allow excessive amount of middle distillates to be included in the reduced crude from the bottom of tower.

CRUDE TOWER TOP REFLUX: The top reflux controls the tower top temperature. The crude tower OH

vapors along with stripping steam is condensed first in HE(D2-201), then in air cooler(D2-202) and finally in trim cooler(D2-203) & then accumulated in OH reflux drum(D8-205). Pressure in reflux drum is controlled 8 – 10 psig. The liquid hydrocarbon from OH reflux drum are pumped by reflux pump(D3-203) as top reflux to tower. Top reflux flow controls the tower top temperature. The remaining liquid from drum under level controller is sent as feed to naphtha splitter.

TOP PUMP AROUND REFLUX (TPA):

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To provide reflux for the middle / upper section of the tower, a hot stream from plate#08 is taken out. TPA pumps(D3-205) pumps this stream to shell side of crude v/s TPA exchanger(D2-605) & then passes through shell side of HE(D2-602) where it preheats the crude, TPA is further cooled in air cooler(D2-207). The cooled TPA returns to crude tower plate#06.

NAPHTHA SPLITTER: Naphtha from PF tower & crude tower OH system through pumps D3-603-

A/B & D3-203/204 respectively is pumped to PF tower. Both the streams combine ahead of splitter tower to form a single stream. Which then flows through the tube side of splitter feed v/s bottom reboiler(D2-330) and through the tube side of hot oil v/s naphtha feed reboiler(D2-331) temperature of feed is controlled through TCV- 262 by controlling the hot oil flowing through the reboiler. The stream then enters the splitter tower (D8-330). In which light & heavy naphtha fractions are separated. Light naphtha from OH flows to the fan cooler (D2-332-A/B) & then through the trim cooler (D2-333) and ultimately goes to reflux drum (D3-331). The reflux drum is installed in vertical position and is operated at maximum liquid level to avoid separation of LPG from liquid. Light naphtha from including LPG from reflux drum os drawn off by pump D3-331/332. Part is sent back to splitter as reflux, and remaining portion is sent as a feed to LPG unit for the separation of LPG. An independent stream is drawn from the bottom of the splitter. It passes through the shell side of splitter reboiler (D2-334) where it is heated by hot oil passing through the tube side of reboiler, hot oil flow is controlled by TCV-233 to control splitter bottom temperature. Reboiler stream is flashed back into splitter. The flashed hot liquid vaporizes the light ends from the heavy naphtha flowing down in splitter. Heavy naphtha from the bottom of splitter is pumped by pump D3-333/334 to shell side of HE (D2-330) where it is cooled by splitter feed. The heavy naphtha is further cooled in air cooler (D2-335) and then in trim cooler (D2-211-A/B) wherefrom it is sent to HDT feed tank. This can be routed to merox unit for sweetening.

STRIPPERS: All side streams drawn from crude tower first flow through the strippers for

the removal of lighter ends from respective streams. Steam is injected at the bottom of strippers for stripping the lighter ends. There are two strippers in function at present. One stripper (D8-203) strips the lighter ends from kero. Kero is drawn from the tray#19 of crude tower. The second stripping column (D8-204) strips the lighter ends from HSD, HSD is drawn from tray#24, the lighter ends removed from HSD are returned back to tray#26. HSD obtained from the bottom of column is sent to storage. While kero is sent to merox unit for sweetening.

LPG SEPARATION UNIT: This unit separates the LPG from light naphtha, simply by removing

propane & butane from L/N & thus this unit also serves as naphtha stabilizing unit. L/N from the top of naphtha splitter is the feed of this unit, which comes to LPG feed tank 21-T-1, wherefrom it is pumped to depropanizer column (21-D-2). In this

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column propane is removed from L/N. one side stream is drawn from the top side which after passing through HE(21-E-5) goes to reflux drum(21-T-3) where one stream is drawn from the bottom and pumped by pump(21-P-4-A/B), a part of this stream goes back to the top of the column, Top flow is controlled by FCV-11, and remaining part is sent to storage which is propane. One stream is drawn from the bottom which goes to kettle type reboiler (21-E-6), where it is heated by hot oil circulation. Two streams are drawn from reboiler, one goes back to the column for maintaining the column bottom temperature, and the other stream is sent as feed to debutanizer (21-D-3). In this column butane is removed. One stream is drawn from the top side which after passing through HE (21-E-7-A/B) goes to reflux tank (21-T- 4), the bottom stream is pumped by (21-P-5-A/B), a part of this stream goes back as reflux & remaining part is the butane which is sent to LPG storage. The stream drawn from the bottom of debutanizer column passes through reboiler (21-E-8) from where a part is sent back as boilup and remaining part after passing through HE (21-E-9-A/B) is sent to light naphtha merox unit for sweetening.

Hydrodesulfurization

Hydrodesulfurization (HDS) is a catalytic chemical process widely used to remove sulfur (S) from natural gas and from refined petroleum products such as gasoline or petrol, jet fuel, kerosene, diesel fuel, and fuel oils. The purpose of removing the sulfur is to reduce the sulfur dioxide (SO2) emissions that result from using those fuels in automotive vehicles, aircraft, railroad locomotives, ships, gas or oil burning

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power plants, residential and industrial furnaces, and other forms of fuel combustion. Another important reason for removing sulfur from the naphtha streams within a petroleum refinery is that sulfur, even in extremely low concentrations, poisons the noble metal catalysts (platinum and rhenium) in the catalytic reforming units that are subsequently used to upgrade the octane rating of the naphtha streams.

The industrial hydrodesulfurization processes include facilities for the capture and removal of the resulting hydrogen sulfide (H2S) gas. In petroleum refineries, the hydrogen sulfide gas is then subsequently converted into byproduct elemental sulfur.

The hydrodesulphurization reaction takes place in a fixed-bed reactor at elevated temperatures ranging from 300 to 400 °C and elevated pressures ranging from 30 to 130 atmospheres of absolute pressure, typically in the presence of a catalyst consisting of an alumina base impregnated with cobalt and molybdenum. Hydrogenation is a class of chemical reactions in which the net result is the addition of hydrogen (H). Hydrogenolysis is a type of hydrogenation and results in the cleavage of the C-X chemical bond, where C is a carbon atom and X is a sulfur, nitrogen (N) or oxygen (O) atom. The net result of a hydrogenolysis reaction is the formation of C-H and H-X chemical bonds. Thus, hydrodesulphurization is a hydrogenolysis reaction. Using ethanethiol (C2H5SH), a sulfur compound present in some petroleum products, as an example, the hydrodesulphurization reaction can be simply expressed as

Ethanethiol + Hydrogen Ethane + Hydrogen sulfideC2H5SH + H2 C2H6 + H2S

The liquid feed is pumped by pump (D3-301/302) up to the required elevated pressure and is joined by a stream of hydrogen-rich recycle gas; the pressure of gas is controlled by PCV-340 the resulting liquid-gas mixture is preheated by flowing through a heat exchanger (D2-301). The preheated feed then flows through a fired heater (D1-301) where the feed mixture is totally vaporized and heated to the required elevated temperature before entering the reactor (D8-301) and flowing through a fixed-bed of catalyst where the hydrodesulfurization reaction takes place. The hot reaction products are partially cooled by flowing through the heat exchanger (D2-301) where the reactor feed was preheated, then flows through fan Cooler (D2-302)and then flows through a trim cooler(D2-303). The resulting mixture of liquid and gas enters the gas separator (D8-302)) vessel at about 35 °C and 3 to 5 atmospheres of absolute pressure.

Most of the hydrogen-rich gas from the gas separator vessel is recycle gas which is routed through an amine contactor for removal of the reaction product H2S that it contains. The pressure of gas is controlled by PCV-235. The H2S-free hydrogen-rich gas is then recycled back for reuse in the reactor section. Any excess gas from the gas separator vessel joins the sour gas from the stripping of the reaction product liquid.

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The liquid from the gas separator vessel flows to the suction of pump (D3- 311/312) routed through a reboiled stripper distillation tower. The bottoms product from the stripper is the final desulfurized liquid product from hydrodesulfurization unit.

Process description

In an industrial hydrodesulfurization unit, such as in a refinery, the hydrodesulfurization reaction takes place in a fixed-bed reactor at elevated temperatures ranging from 300 to 400 °C and elevated pressures ranging from 30 to 130 atmospheres of absolute pressure, typically in the presence of a catalyst consisting of an alumina base impregnated with cobalt and molybdenum.

The image below is a schematic depiction of the equipment and the process flow streams in a typical refinery HDS unit.

Schematic diagram of a typical Hydrodesulfurization (HDS) unit in a petroleum refinery

The liquid feed (at the bottom left in the diagram) is pumped up to the required elevated pressure and is joined by a stream of hydrogen-rich recycle gas. The resulting liquid-gas mixture is preheated by flowing through a heat exchanger. The preheated feed then flows through a fired heater where the feed mixture is totally vaporized and heated to the required elevated temperature before entering the reactor and flowing through a fixed-bed of catalyst where the hydrodesulfurization reaction takes place.

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The hot reaction products are partially cooled by flowing through the heat exchanger where the reactor feed was preheated and then flows through a water-cooled heat exchanger before it flows through the pressure controller (PC) and undergoes a pressure reduction down to about 3 to 5 atmospheres. The resulting mixture of liquid and gas enters the gas separator vessel at about 35 °C and 3 to 5 atmospheres of absolute pressure.

Most of the hydrogen-rich gas from the gas separator vessel is recycle gas which is routed through an amine contactor for removal of the reaction product H2S that it contains. The H2S-free hydrogen-rich gas is then recycled back for reuse in the reactor section. Any excess gas from the gas separator vessel joins the sour gas from the stripping of the reaction product liquid.

The liquid from the gas separator vessel is routed through a reboiled stripper distillation tower. The bottoms product from the stripper is the final desulfurized liquid product from hydrodesulfurization unit.

The overhead sour gas from the stripper contains hydrogen, methane, ethane, hydrogen sulfide, propane and perhaps some butane and heavier components. That sour gas is sent to the refinery's central gas processing plant for removal of the hydrogen sulfide in the refinery's main amine gas treating unit and through a series of distillation towers for recovery of propane, butane and pentane or heavier components. The residual hydrogen, methane, ethane and some propane is used as refinery fuel gas. The hydrogen sulfide removed and recovered by the amine gas treating unit is subsequently converted to elemental sulfur in a Claus process unit.

REFORMER UNIT: This unit accounts for increasing the octane rating of gasoline and HOBC

(reformate) is the product of this unit. This unit consists of following units.

Catalytic reforming is a chemical process used to convert petroleum refinery naphthas, typically having low octane ratings, into high-octane liquid products called reformates which are components of high-octane gasoline (also known as petrol). Basically, the process re-arranges or re-structures the hydrocarbon molecules in the naphtha feedstocks as well as breaking some of the molecules into smaller molecules. The overall effect is that the product reformate contains hydrocarbons with more complex molecular shapes having higher octane values than the hydrocarbons in the naphtha feedstock. In so doing, the process separates hydrogen atoms from the hydrocarbon molecules and produces very significant amounts of byproduct hydrogen gas for use in a number of the other processes involved in a modern petroleum refinery. Other byproducts are small amounts of methane, ethane, propane and butanes.

This process is quite different from and not to be confused with the catalytic steam reforming process used industrially to produce various products such as hydrogen,

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ammonia and methanol from natural gas, naphtha or other petroleum-derived feedstocks. Nor is this process to be confused with various other catalytic reforming processes that use methanol or biomass-derived feedstocks to produce hydrogen for fuel cells or other uses.

Typical naphtha feedstocks

A petroleum refinery includes many unit operations and unit processes. The first unit operation in a refinery is the continuous distillation of the petroleum crude oil being refined. The overhead liquid distillate is called naphtha and will become a major component of the refinery's gasoline (petrol) product after it is further processed through a catalytic hydrodesulfurizer to remove sulfur-containing hydrocarbons and a catalytic reformer to reform its hydrocarbon molecules into more complex molecules with a higher octane rating value. The naphtha is a mixture of very many different hydrocarbon compounds. It has an initial boiling point of about 35 °C and a final boiling point of about 200 °C, and it contains paraffin, naphthene (cyclic paraffins) and aromatic hydrocarbons ranging from those containing 4 carbon atoms to those containing about 10 or 11 carbon atoms.

The naphtha from the crude oil distillation is often further distilled to produce a "light" naphtha containing most (but not all) of the hydrocarbons with 6 or less carbon atoms and a "heavy" naphtha containing most (but not all) of the hydrocarbons with more than 6 carbon atoms. The heavy naphtha has an initial boiling point of about 140 to 150 °C and a final boiling point of about 190 to 205 °C. The naphthas derived from the distillation of crude oils are referred to as "straight-run" naphthas.

It is the straight-run heavy naphtha that is usually processed in a catalytic reformer because the light naphtha has molecules with 6 or less carbon atoms which, when reformed, tend to crack into butane and lower molecular weight hydrocarbons which are not useful as high-octane gasoline blending components. Also, the molecules with 6 carbon atoms tend to form aromatics which is undesirable because governmental environmental regulations in a number of countries limit the amount of aromatics (most particularly benzene) that gasoline may contain.

It should be noted that there are a great many petroleum crude oil sources worldwide and each crude oil has its own unique composition or "assay". Also, not all refineries process the same crude oils and each refinery produces its own straight-run naphthas with their own unique initial and fina Before entering the reactors two chemicals are injected into the feed:

• PERC• Methanol

The purpose of there chemicals is to maintain the chloride level and to support metallic reactions thus increase the rate of reaction.

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Following reaction takes place in the Reformer Unit:• Naphtene Dehydrogentaion• Naphtene Isomerisation• Paraffins Dehydrogentaion• Paraffins Isomerisation• Hydrocracking• Demethylation• Aeromatic Dealkylation

l boiling points. In other words, naphtha is a generic term rather than a specific term.

Some refinery naphthas include olefinic hydrocarbons, such as naphthas derived from the fluid catalytic cracking and coking processes used in many refineries. Some refineries may also desulfurize and catalytically reform those naphthas. However, for the most part, catalytic reforming is mainly used on the straight-run heavy naphthas, such as those in the above table, derived from the distillation of crude oils.

The reaction chemistry

There are a good many chemical reactions that occur in the catalytic reforming process, all of which occur in the presence of a catalyst and a high partial pressure of hydrogen. Depending upon the type or version of catalytic reforming used as well as the desired reaction severity, the reaction conditions range from temperatures of about 495 to 525 °C and from pressures of about 5 to 45 atm.

The commonly used catalytic reforming catalysts contain noble metals such as platinum and/or rhenium, which are very susceptible to poisoning by sulfur and nitrogen compounds. Therefore, the naphtha feedstock to a catalytic reformer is always pre-processed in a hydrodesulfurization unit which removes both the sulfur and the nitrogen compounds.

The hydrocracking of paraffins is the only one of the above four major reforming reactions that consumes hydrogen. The isomerization of normal paraffins does not consume or produce hydrogen. However, both the dehydrogenation of naphthenes and the dehydrocyclization of paraffins produce hydrogen. The overall net production of hydrogen in the catalytic reforming of petroleum naphthas ranges from about 50 to 200 cubic meters of hydrogen gas (at 0 °C and 1 atm) per cubic meter of liquid naphtha feedstock. In the United States customary units, that is equivalent to 300 to 1200 cubic feet of hydrogen gas (at 60 °F and 1 atm) per barrel of liquid naphtha feedstock.[12] In many petroleum refineries, the net hydrogen produced in catalytic reforming supplies a significant part of the hydrogen used elsewhere in the refinery (for example, in hydrodesulfurization processes). The hydrogen is also necessary in order to hydrogenolyze any polymers that form on the catalyst.

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CATALYTIC REFORMING:

The liquid feed from hydrodesulfurization unit is pumped through pump - up to the reaction pressure (5 to 45 atm) and is joined by a stream of hydrogen-rich recycle gas. The resulting liquid-gas mixture is preheated by flowing through a HE (D2-307). The preheated feed mixture is then totally vaporized and heated to the reaction temperature in fired heater (D1-303) before the vaporized reactants enter the first reactor (D8-305). As the vaporized reactants flow through the fixed bed of catalyst in the reactor, the major reaction is the dehydrogenation of naphthenes to aromatics which is highly endothermic and results in a large temperature decrease between the inlet and outlet of the reactor. To maintain the required reaction temperature and the rate of reaction, the vaporized stream is reheated in the second fired heater (D1-304) before it flows through the second reactor (D8-306). The temperature again decreases across the second reactor and the vaporized stream is again be reheated in the third fired heater (D1-305) before it flows through the third Reactor (D8-307). As the vaporized stream proceeds through the three reactors, the reaction rates decrease and the reactors therefore become larger. At the same time, the amount of reheat required between the reactors becomes smaller. Usually, three reactors are all that is required to provide the desired performance of the catalytic reforming unit.

The hot reaction products from the third reactor are partially cooled by flowing through the heat exchanger (D2-307) where the feed to the first reactor is preheated and then flow through a fan cooler (D2-308) & then through water-cooled heat exchanger(D2-309).this cooled stream goes to the gas separator(D8-308).

Most of the hydrogen-rich gas from the gas separator vessel returns to the suction of the recycle hydrogen gas compressor and the net production of hydrogen-rich gas from the reforming reactions is exported for use in hydrodesulfurization. The liquid from the gas separator vessel is routed into a fractionating column called a stabilizer (D8-310). The overhead offgas product from the stabilizer contains the byproduct methane, ethane, propane and butane gases produced by the hydrocracking reactions as explained in the above discussion of the reaction chemistry of a catalytic reformer, and it may also contain some small amount of hydrogen. That offgas is routed to the refinery's central gas processing plant for removal and recovery of propane and butane. The residual gas after such processing becomes part of the refinery's fuel gas system.

The bottoms product from the stabilizer is the high-octane liquid reformate that will become a component of the refinery's product gasoline.

REFORMER UNIT CATALYST QUANTITY IN EACH REACTOR

ReactorType of loading

Type of catalyst

Catalyst percentage

Catalyst quantity (Kg)

Reactor 1

Dense R-56 15% 1214

Reactor 2

Dense R-56 28% 2267

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Reactor 3

Dense R-56 57% 4615

Total 8096

Catalyst R-56 contains following metal composition.Platinum = 0.25 wt%Rhenium = 0.40 wt%Total quantity of Platinum in catalyst = (0.0025) (8096) = 20 kgTotal quantity of Rhenium in catalyst = (0.0040) (8096) = 32 kg

MEROX

Merox is an acronym for mercaptan oxidation. It is a proprietary catalytic chemical process developed by UOP used in oil refineries and natural gas processing plants to remove mercaptans from LPG, propane, butanes, light naphthas, kerosene and jet fuel by converting them to liquid hydrocarbon disulfides.

The Merox process requires an alkaline environment which, in some of the process versions, is provided by an aqueous solution of sodium hydroxide (NaOH), a strong

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base, commonly referred to as caustic. In other versions of the process, the alkalinity is provided by ammonia, which is a weak base.

The catalyst in some versions of the process is a water-soluble liquid. In other versions, the catalyst is impregnated onto charcoal granules.

Processes within oil refineries or natural gas processing plants that remove mercaptans and/or hydrogen sulfide (H2S) are commonly referred to as sweetening processes because they results in products which no longer have the sour, foul odors of mercaptans and hydrogen sulfide. The liquid hydrocarbon disulfides may remain in the sweetened products, they may be used as part of the refinery or natural gas processing plant fuel, or they may be processed further.

The Merox process is usually more economical than using a catalytic hydrodesulfurization process for much the same purpose.

Types of Merox process units

UOP has developed many versions of the Merox process for various different applications:

Conventional Merox for extraction of mercaptans from LPG, propane, butanes or light naphthas.

Conventional Merox for sweetening jet fuels and kerosenes.

Minalk Merox for sweetening of naphthas. This process continuously injects just a few ppm of caustic into the feed naphtha.

Caustic-free Merox for sweetening jet fuels and kerosenes. This process injects small amounts of ammonia and water (rather than caustic) into the feed naphtha to provide the required alkalinity.

Caustic-free Merox for sweetening of naphthas.[7] This process also injects small amounts of ammonia and water (rather than caustic) into the feed naphtha to provide the required alkalinity.

In all of the above Merox versions, the overall oxidation reaction that takes place in converting mercaptans to disulfides is:

4 RSH + O2 → 2RSSR + 2H2O

In some of the above Merox process versions, the catalyst is a liquid. In others, the catalyst is in the form of impregnated charcoal granules.

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Process flow diagrams and descriptions of the two conventional versions of the Merox process are presented in the following sections.

Conventional Merox for extracting mercaptans from LPG

The conventional Merox process for extraction and removal of mercaptans from liquefied petroleum gases (LPG), such as propane, butanes and mixtures of propane and butanes, can also be used to extract and remove mercaptans from light naphthas. It is a two-step process. In the first step, the feedstock LPG or light naphtha is contacted in the trayed extractor vessel with an aqueous caustic solution containing UOP's proprietary liquid catalyst. The caustic solution reacts with mercaptans and extracts them. The reaction that takes place in the extractor is:

2RSH + 2 NaOH → 2NaSR + 2 H2O

In the above reaction, RSH is a mercaptan and R signifies an organic group such as a methyl, ethyl, propyl or other group. For example, the ethyl mercaptan (ethanethiol) has the formula C2H5SH.

The second step is referred to as regeneration and it involves heating and oxidizing of the caustic solution leaving the extractor. The oxidations results in converting the extracted mercaptans to organic disulfides (RSSR) which are liquids that are water-insoluble and are then separated and decanted from the aqueous caustic solution. The reaction that takes place in the regeneration step is:

4NaSR + O2 + 2H2O → 2RSSR + 4NaOH

After decantation of the disulfides, the regenerated "lean" caustic solution is recirculated back to the top of the extractor to continue extracting mercaptans.

The net overall Merox reaction covering the extraction and the regeneration step may be expressed as:

4 RSH + O2 → 2RSSR + 2H2O

The feedstock entering the extractor must be free of any H2S. Otherwise, any H2S entering the extractor would react with the circulating caustic solution and interfere with the Merox reactions. Therefore, the feedstock is first "prewashed" by flowing through a batch of aqueous caustic to remove any H2S. The reaction that takes place in the prewash vessel is:

H2S + NaOH → NaSH + H2O

The batch of caustic solution in the prewash vessel is periodically discarded as "spent caustic" and replaced by fresh caustic as needed.

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Flow diagram

Conventional Merox process unit for extracting mercaptans from LPG

The flow diagram below depicts the equipment and the flow paths involved in the process. The LPG (or light naphtha) feedstock enters the prewash vessel and flows upward through a batch of caustic which removes any H2S that may be present in the feedstock. The coalescer at the top of the prewash vessel prevents caustic from being entrained and carried out of the vessel.

The feedstock then enters the mercaptan extractor and flows upward through the contact trays where the LPG intimately contacts the downflowing Merox caustic that extracts the mercaptans from the LPG. The sweetened LPG exits the tower and flows through: a caustic settler vessel to remove any entrained caustic, a water wash vessel to further remove any residual entrained caustic and a vessel containing a bed

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of rock salt to remove any entrained water. The dry sweetened LPG exits the Merox unit.

The caustic solution leaving the bottom of the mercaptan extractor ("rich" Merox caustic) flows through a control valve which maintains the extractor pressure needed to keep the LPG liquified. It is then injected with UOP's proprietary liquid catalyst (on an as needed basis), flows through a steam-heated heat exchanger and is injected with compressed air before entering the oxidiser vessel where the extracted mercaptans are converted to disulfides. The oxidizer vessel has a packed bed to keep the aqueous caustic and the water-insoluble disulfide well contacted and well mixed.

The caustic-disulfide mixture then flows into the separator vessel where it is allowed to form a lower layer of "lean" Merox caustic and an upper layer of disulfides. The vertical section of the separator is for the disengagement and venting of excess air and includes a Raschig ring section to prevent entrainment of any disulfides in the vented air. The disulfides are withdrawn from the separator and routed to fuel storage or to a hydrotreater unit. The regenerated lean Merox caustic is then pumped back to the top of the extractor for reuse.

Conventional Merox for sweetening kerosene

The conventional Merox process for the removal of mercaptans (i.e., sweetening) of jet fuel or kerosene is a one-step process. The mercaptan oxidation reaction takes place in an alkaline environment as the feedstock jet fuel or kerosene, mixed with compressed air, flows through a fixed bed of catalyst in a reactor vessel. The catalyst consists of charcoal granules that have been impregnated with UOP's proprietary catalyst. The oxidation reaction that takes place is:

4 RSH + O2 → 2RSSR + 2H2O

As is the case with the conventional Merox process for treating LPG, the jet fuel or kerosene sweetening process also requires that the feedstock be prewashed to remove any H2S that would interfere with the sweetening. The reaction that takes place in the batch caustic prewash vessel is:

H2S + NaOH → NaSH + H2O

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The Merox reactor is a vertical vessel containing a bed of charcoal granules that have been impregnated with the UOP catalyst. The charcoal granules may be impregnated with the catalyst in situ#chemistry and chemical engineering or they may be purchased from UOP as pre-impregnated with the catalyst. An alkaline environment is provided by caustic being pumped into reactor on an intermittent, as needed basis.

The jet fuel or kerosene feedstock from the top of the caustic prewash vessel is injected with compressed air and enters the top of the Merox reactor vessel along with any injected caustic. The mercaptan oxidation reaction takes place as the feedstock percolates downward over the catalyst. The reactor effluent flows through a caustic settler vessel where it forms a bottom layer of aqueous caustic solution and an upper layer of water-insoluble sweetened product.The caustic solution remains in the caustic settler so that the vessel contains a reservoir for the supply of caustic that is intermittently pumped into the reactor to maintain the alkaline environment.The sweetened product from the caustic settler vessel flows through a water wash vessel to remove any entrained caustic as well as any other unwanted water-soluble substances, followed by flowing through a salt bed vessel to remove any entrained water and finally through a clay filter vessel. The clay filter removes any oil-soluble substances, organometallic compounds (especially copper) and particulate matter, which might prevent meeting jet fuel product specifications.The pressure maintained in the reactor is chosen so that the injected air will completely dissolve in the feedstock at the operating temperature.

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OIL MOVEMENTS & LOGISTICS

STORAGE: The storage and shipments of crude, intermediate and finished products is a necessary part of the refining operations. The purpose of the storage tanks is to ensure the availability of the stocks in adequate quantities for continuous operation or provide storage for the feed stocks to the units on blocked out operation or to have sufficient quantities for the bulk shipments. The storage and shipping operations are carried out by the Oil Movement and Storage Division. The broad functions of the OM & S Division are:

(a) (Decanting) Receiving crude oil and transfer to booster pump

(b) (Booster Pump) Storing and feeding the units with respective feed stocks of crude oil.

(c) (Tank Farm)Receiving the products into tanks, blending of the components produced in

the units into finished products, moving finished products and oil recovery from the API separator system.

(d) (Shipping)Shipment all products including LPG, PMG, Naphtha, HSD & Furnace Fuel

Oil.

 The storage tanks of the products can be broadly classified into two categories: (a) Pressure tanks, (b) Atmospheric tanks. The high vapor pressure products like LPG are stored in the pressure tanks and the low vapor pressure products are stored in atmospheric tanks. The products like gasoline naphtha which have vapor pressure not high enough for pressure tanks, but high enough to have losses due to evaporation are stored in floating roof tanks to minimize the loss of product due to evaporation. The crude oil is brought from ZOT by tankers and is pumped from Decanting to the crude tanks. The crude is then pumped to Plant by Booster pumpD3-201 & D3-202.The LPG, naphtha, kerosene and high speed diesel are received from the units directly in the product tanks.

LOGISTICS: DECANTING SECTION:

This section serves for unloading crude oil being transported from ZOT through bowsers. Before receiving the crude oil bowsers are inspected for the crude level by dip rod for any loss during transportation. After inspecting the level bowsers are allowed to move towards oil gantries, where crude is pumped from bowsers to the storage tanks located nearby. There are 16 gantries, so at a time 16 bowsers are unloaded. Crude bowsers have nearly 50,000-60,000 Lit. capacity. It takes nearly 45 minutes to withdraw the crude from bowsers.

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CRUDE OIL TANKS: Type: EFRT

Particulars Tank no 01 Tank no 02 Tank no 03 Tank no 05

Volume in liter / mm 727 727 731 731

Tank Dia (mm) 30000 30000 30500 30500

Total Height (mm) 16000 16000 16000 16000

Decant line Dia (inch) 10 10 10 10

Feed line Dia (inch) 10 10 10 10

Drain line Dia (inch) 2 2 2 2

PMG TANKS: Type: FRT

Particulars Tank no 11 Tank no 12 Tank no 13 Tank no 14 Tank no 15

Volume in liter / mm 86 86 86 86 86

Tank Dia (mm) 10467 10467 10467 10467 10467

Total Height (mm) 9146 9258 9146 9231 9224

R/D line Dia (inch) 2 2 2 2 3

CR line Dia (inch) 3x2 3x2 3x2 3 3x2

Shipment line Dia (inch) 6 6 6 6 6

Drain line Dia (inch) 2 2 2 2 2

NAPHTHA TANKS: Type: IFRT

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Particulars Tank no 16 Tank no 17 Tank no 18 Tank no 19

Volume in liter / mm 87 86 182 87

Tank Dia (mm) 10527 10467 15226 10527

Total Height (mm) 9146 9000 13500 9225

R/D line Dia (inch) 2 4 4 2

CR line Dia (inch) ** ** ** **

Shipment line Dia (inch) 6 6 6 6

Drain line Dia (inch) 2 2 2 2

HSD TANKS: Type: FRT

ParticularsTank no

22Tank no

23Tank no

24Tank no

25Tank no

26Tank no

31Tank no

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Volume in liter / mm 86 86 114 114 114 72 114

Tank Dia (mm) 10467 10467 12050 12050 12050 12050 12050

Total Height (mm) 9146 9243 10500 10500 10836 6000 10893

R/D line Dia (inch) 6 6 6 6 6 3 6

CR line Dia (inch) 6 6 6 6 6 * 6

Shipment line Dia (inch)

6 6 6 6 6 3 6

Drain line Dia (inch) 2 2 2 2 2 2 2

FFO TANKS: Type: FRT

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Particulars Tank no 27 Tank no 28 Tank no 29 Tank no 32

Volume in liter / mm 182 182 182 182

Tank Dia (mm) 15226 15226 15226 15226

Total Height (mm) 11000 11000 11299 11327

R/D line Dia (inch) 6 6 6 6

CR line Dia (inch) 6 6 6 6

Shipment line Dia (inch) 8 8 8 8

Drain line Dia (inch) 2 2 2 2

KEROSINE JP-1 OIL TANKS: Type: FRT

Particulars Tank no 21 Tank no 34

Volume in liter / mm 86 86

Tank Dia (mm) 10467 10467

Total Height (mm) 9146 9146

R/D line Dia (inch) 3 3

CR line Dia (inch) 3x2 3

Shipment line Dia (inch) 6 6

Drain line Dia (inch) 2 2

LPG BULLET VESSELS:

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Particulars Vessel no 1 Vessel no 2 Vessel no 3 Vessel no 4

Capacity (bbl) 718 815 819 816

Volume < 80% < 80% < 80% < 80%

Pressure (Psig) <140 <240 <240 <240

SLOP TANK :

Particulars Tank no 04

Volume in liter / mm 86

Tank Dia (mm) 10467

Total Height (mm) 9000

Recover line Dia (inch) 6

Transfer line Dia (inch) 6

Drain line Dia (inch) 2

API SEPARATOR & SLOP OIL TANK:

The oil from different sampling points before every new sampling is drained from the lines which then through pipe lines go to the API separator, also any leakage of plant is forced to go to this separator. This separator is simply the tank where water is allowed to settle down under the gravity action and is drained to water pond located nearby through pump. The oil from top is then pumped to the slop oil tank no.04 wherefrom it goes to the booster pump through pipeline and mixed with the feed line of crude oil to plant. Also if any product becomes out of desired set points goes to this slop oil tank

ABBREVIATIONS

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API: American petroleum Institute BPA: Bottom Pump Around BPL: Bosicor Pakistan Limited BS&W: Base Sediments and Water CDU: Crude distillation Unit FCV: Flow Control Valve FFO: Furnace Fuel Oil FO: Furnace Oil HDT: Hydro Theater HE: Heat Exchanger HOBC: High Octane Blending Component HSD: High speed Diesel JP: Jet Fuel Kero: Kerosene Lit: Liters L/N: Light Naphtha LCV: Level Control Valve LPG: Liquid Petroleum Gas OH: Over Head Reflux PCV: Pressure Control Valve PD Pump: Positive Displacement Pump PFD: Process Flow Diagram PMG: Premier Motor Gasoline PR tower: Pre- flash tower RON: Research Octane Number SH: Steam Super Heated Steam TCV: Temperature Control Valve TDS: Total Dissolved Salt TPA: Top Pump Around

REFRENCE: BOOKS:

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PETROLEUM REFINERY ENGINEERING BY W.L.NELSON. Petroleum processing hand book by William. F. Bland. Unit Operations of Chemcial Engineering by Warren L.

Mc. Cabe. Process technology by Thomas. D .Felder.

WEB-SITES:

WWW.WIKIPEDIA.COM. WWW.API.COM WWW.AMSWERS.COM WWW.BOSICOR.COM.PK WWW.GOOGLE.COM WWW.CHEMICALRESOURCES.COM

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