Mathura Refinery Report

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Certificate of Training issued by Industry/firm/company

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ABSTRACT

Indian Oil Corporation Limited (Indian Oil) is the largest commercial enterprise in India

with a sales turnover of Rs.150, 677 crores and profit of Rs. 4, 891 crores for the fiscal

year 2004.

Indian Oil is India’s number one company in Fortune’s prestigious listing of the

world’s 500 largest corporations, ranked 170 based on fiscal 2004 performance. It is also

the 18th largest petroleum company in the world and adjudged number one in petroleum

trading among the 15 national oil companies in the Asia-Pacific region. Indian Oil alone

accounts for 56 % petroleum product market share among PSU companies, 42% National

refining capacity and 68% downstream pipeline throughput capacity. Indian Oil group

owns and operates 10 of India’s 18 refineries with a current combined rated capacity of

54.2 Million metric tons (MMTPA). These include subsidiaries viz. Chennai Petroleum

Corporation Ltd and Bongaigaon Refinery & Petrochemicals Ltd. It owns and operates the

country’s largest network of cross-country crude and product pipelines, with a combined

length of 7,730 km with a combined capacity of 56.85 MMTPA. For the year 2004-05,

Indian Oil sold 50.1 million tones of petroleum products, including exports of 1.96 million

tones. Indian Oil’s countrywide network of over 23,000 sales points is backed for supplies

by its extensive, well spread out marketing infrastructure comprising 165 bulk storage

terminals, installations and depots, 95 aviation fuelling stations and 87 LPG bottling plants.

Its subsidiary, IBP Co. Ltd, is a stand-alone marketing company with a nationwide network

of over 3,000 retail sales points.

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Mathura Refinery was commissioned in the year 1982. At present it has the capacity of

processing 8.0 MMTPA of crude oil. The refinery meets the demand of Northwest region

of India including Delhi. The crude oil with low sulphur from Bombay High, imported

crude with low sulphur from Nigeria, and crude with high sulphur from Middle East

Countries are processed at this refinery.

The original refinery configuration had one primary Atmospheric Vacuum unit and

the secondary units were the Vis-breaker Unit, Bitumen Unit, Sulphur Recovery unit and

Fluidized Catalytic cracking Unit. Gradually Mathura Refinery in Uttar Pradesh made

certain changes to follow the strict product specification that aroused due to environmental

considerations. The secondary units such as Once Through Hydro-cracker unit (OHCU),

S.No. NAME OF PROCESSING UNITS CAPACITY (MMTPA)

1 Atmospheric & vacuum distillation unit 8.0

2 Vis-breaker unit 1.0

3 Fluidized catalytic cracking unit (FCCU) 1.48

4 Continuous catalytic reforming unit (CCRU) 0.466

5 Once through Hydrocracker unit (OHCU) 1.2

6 Hydrogen generation unit (HGU -I) 0.034

7 Hydrogen generation unit (HGU - II) 0.074

8 Diesel hydrodesulphurization unit (DHDS) 1.1

9 Bitumen blowing unit (BBU) 0.576

10 MEROX

11 ATF 1.5

12 VBN 0.058

13 Amine recovery unit 1.5

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Catalytic Reforming Unit (CRU), MS quality up gradation, Diesel hydro de-sulphurisation

Unit, (DHDS), new Sulphur Recovery unit (SRU), DHDT etc were integrated in the

refinery configuration. These changes in the configuration of the Refinery were made so

that there is minimal impact on the environment.

Mathura Refinery has taken a number of initiatives to save the environment, public

health and also to preserve the national monuments in and around the city of Mathura. A

lot of research has been done to produce more and more clean fuels that would have

minimal negative effect on the environment. Mathura refinery has been producing highly

eco-friendly petrol and diesel for the NCT, NCR and Agra region. The Refinery enjoys the

distinction of being the first refinery in India capable of producing 100% auto fuels that

meets Euro - III norms.

Products from this refinery are dispatched through rail, road and Mathura-Delhi –

Ambala - Jalandhar pipeline. The LPG bottling plant situated within Mathura refinery

premises bottles nearly seven million cylinder per annum for catering domestic market.

Major fertilizer industries at Kanpur, Panipat, Nangal, Bhatinda, and Kota are supplied

with Naphtha or furnace oil. Also thermal power plants of Nangal, Obra, and Badarpur get

fuel oil supply from this refinery.

Mathura refinery was the first in Asia and third refinery in the world to have

been honored with the coveted ISO- 14001, certification on July 22- 1996.

It was also awarded the Golden peacock national quality award 1996.

It bagged first prize in national energy conservation award in 1996 in public sector in

ministry of power.

Jawaharlal Nehru Cenetery award for achieving the best improved method of

energy conservation compared to its past best performance of 1994 & 1996.

Highest ever ATF (AVIATION TURBINE FUEL) and bitumen production of 617.6 &

430.2 TMT achieved surpassing the previous best of 613.4 TMT in 1993/94 & 425.2 TMT

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in 1993-94 respectively. Highest ever distillated yield of 73.14% on crude achieved

surpassing of previous best of 72.78% on crude in 1987-88.

VISION:

A major diversified, translational, integrated energy company, with national leadership and

a strong environment conscience, playing a national role in oil security and public

distribution.

MISSION:

To achieve international standards of excellence in all aspects of energy and

diversified business with focus on customer delight through value of products and services

and cost reduction.

To maximize creation of wealth, value and satisfaction for the stakeholders.

To attain leadership in developing, adopting and assimilating state of the art

technology for competitive advantage.

To provide technology and services through sustained research and development.

To cultivate high standards of business ethics and total quality management for a

strong corporate identity and brand equity.

To help enrich the quality of life of the community and preserve ecological balance

and heritage through a strong environment conscience.

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ACKNOWLEDGEMENT

It is great that Indian Oil Corporation Limited provides training to a large number of

students like us for practical assimilation of knowledge pertaining to our respective

disciplines.

I am thankful to Mr. C.S.Sharma, Senior Manager (MS & training) for his hospitality,

guidance & co-operation.

I am heartily thankful to all unit heads and all technical & Non-technical staff of

MATHURA REFINERY for their great efforts to enhance my practical knowledge.

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CONTENTS

1. ATMOSPHERIC AND VACUUM DISTILLATION UNIT (AVU) ............................ 1

1.1. INTRODUCTION ...................................................................................................... 1

1.2. TYPES OF CRUDE ................................................................................................... 1

1.3. PRODUCTS FROM CDU/VDU MAIN COLUMNS.............................................. 2

1.4. STEPS OF OPERATION IN AVU PROCESS ....................................................... 3

1.5. FEED SUPPLY........................................................................................................... 3

1.6. SYSTEM DESCRIPTION......................................................................................... 4

1.6.1. FURNACE OPERATION .................................................................................. 4

1.6.1.1. CDU FIRED HEATER ............................................................................... 5

1.6.1.2. VDU FIRED HEATER ............................................................................... 6

1.6.2. CRUDE DISTILLATION UNIT ....................................................................... 6

1.6.3. STABILIZER ...................................................................................................... 7

1.6.4. VACUUM DISTILLATION UNIT ................................................................... 7

2. VIS-BREAKING UNIT .................................................................................................... 9

2.1. INTRODUCTION ...................................................................................................... 9

2.2. SYSTEM DESCRIPTION......................................................................................... 9

2.3. THEORY OF VIS-BREAKING ............................................................................. 11

2.4. VIS-BREAKER FURNACES ................................................................................. 12

2.5. V.B. FRACTIONATOR .......................................................................................... 13

2.6. STABILIZER ........................................................................................................... 14

2.7. PROCESS VARIABLES ......................................................................................... 15

2.7.1. FEED RATE ...................................................................................................... 15

2.7.2. SOAKER OUTLET TRANSFER LINE TEMPERATURE ........................ 15

2.7.3. VB TAR QUENCH TO THE COLUMN OUTLET ...................................... 15

2.7.4. FRACTIONATOR PRESSURE ...................................................................... 16

2.7.5. FRACTIONATOR TOP TEMPERATURE .................................................. 16

2.7.6. VB TAR QUENCH TOP FRACTIONATOR BOTTOM ............................. 16

2.7.7. VB TAR QUENCH TO VB TAR STRIPPER BOTTOM ............................ 16

2.7.8. STABILISER TEMPERATURE AND PRESSURE ..................................... 17

3. FLUID CATALYTIC CRAKING UNIT (FCCU) ....................................................... 18

3.1. INTRODUCTION .................................................................................................... 18

3.2. CRACKING SECTION........................................................................................... 19

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3.3. CATALYTIC SECTION ......................................................................................... 21

3.3.1. TYPE OF CATALYSTS .................................................................................. 23

3.4. FRACTIONATION SECTION .............................................................................. 23

3.5. GAS CONCENTRATION SECTION.................................................................... 24

3.6. CO BOILER ............................................................................................................. 24

4. MEROX UNIT (MERCAPTAN OXIDATION) .......................................................... 24

4.1. INTRODUCTION .................................................................................................... 24

4.2. MEROX PROCESS DESCRIPTION .................................................................... 26

4.2.1. PRETREATMENT ........................................................................................... 27

4.2.2. EXTRACTION SECTION .............................................................................. 27

4.2.3. SWEETENING ................................................................................................. 29

4.2.4. POST TREATMENT ....................................................................................... 30

4.2.5. MEROX CATALYSTS .................................................................................... 30

5. CONTINUOUS CATALYTIC REFORMING UNIT (CCRU) .................................. 31

5.1. INTRODUCTION .................................................................................................... 31

5.1.1. NAPHTHA SPLITTING UNIT ....................................................................... 32

5.1.2. NAPHTHA HYDROTREATER UNIT .......................................................... 32

5.1.3. REFORMING UNIT ........................................................................................ 33

5.2. REACTORS.............................................................................................................. 34

6. ONCE THROUGH HYDROCRACKER UNIT (OHCU) .......................................... 34

6.1. INTRODUCTION .................................................................................................... 34

6.2. PROCESS DESCRIPTION..................................................................................... 35

6.2.1. REACTOR FEED SYSTEM ........................................................................... 35

6.2.2. FRACTIONTATION SECTION .................................................................... 37

6.2.3. DE-ETHANISER .............................................................................................. 37

7. DIESEL HYDRO DESULFURIZATION UNIT (DHDS) .......................................... 37

7.1. INTRODUCTION .................................................................................................... 37

7.2. CATALYSTS ............................................................................................................ 38


7.4. PROCESS VARIABLES ......................................................................................... 40

7.4.1. HYDROGEN PARTIAL PRESSURE ............................................................ 40

7.4.2. TEMPERATURE ............................................................................................. 40

8. HYDROGEN GENERATION UNIT (HGU) - I .......................................................... 41

8.1. FEED ......................................................................................................................... 41

8.2. DESULPHURIZATION .......................................................................................... 41

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8.3. REFORMING SECTION ....................................................................................... 42

8.3.1. PRE-REFORMER ............................................................................................ 42

8.3.2. TUBULAR REFORMER ................................................................................. 42

9. BITUMEN BLOWING UNIT (BBU) ........................................................................... 43

9.1. INTRODUCTION .................................................................................................... 43


9.2.1. FEED SUPPLY SYSTEM ................................................................................ 44

9.2.2. COLD FEED PUMPS AND FEED PREHEATING ..................................... 44

9.2.3. REACTORS ...................................................................................................... 45

9.2.4. FINISHED BITUMEN CIRCUIT ................................................................... 45

9.2.5. REACTOR OVERHEAD SYSTEM ............................................................... 46

9.2.6. OXIDATION GAS SEPARATORS ................................................................ 46

10. AMINE RECOVERY UNIT (ARU) ............................................................................. 47

10.1. INRODUCTION ...................................................................................................... 47


10.2.1. AMINE FLASH DRUM ................................................................................... 47

11. SULFUR RECOVERY UNIT (SRU) ............................................................................ 49

11.1. INTRODUCTION .................................................................................................... 49


12. OIL MOVEMENT AND STORAGE I ......................................................................... 51

12.1. STORAGE SECTION ............................................................................................. 51

12.1.1. FIXED ROOF TANKS ................................................................................. 51

12.1.2. FLOATING ROOF TANK .......................................................................... 51

12.1.3. FLOATING CUM FIXED ROOF TANKS ................................................ 52

12.2. DISPATCH SECTION ............................................................................................ 52

12.2.1. PRODUCT DISPATCH BY RAIL .............................................................. 53

12.2.2. PRODUCT DISPATCH BY PIPELINE ..................................................... 53

13. OIL MOVEMENT AND STORAGE II ....................................................................... 54

13.1. BITUMEN DRUM FILLING SECTION .............................................................. 54

13.2. LPG SECTION......................................................................................................... 55

13.2.1. LPG BOTTLING PLANT ............................................................................ 55

13.2.2. BULK LOADING ......................................................................................... 55

13.2.2.1. BULK LOADING BY ROAD .................................................................. 55

13.2.2.2. BULK LOADING BY RAIL .................................................................... 56

13.2.3. CHARACTERISTICS OF LPG .................................................................. 56

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13.3. EFFLUENT TREATMENT PLANT (ETP) .......................................................... 56

13.3.1. TREATMENT PRINCIPLE ........................................................................ 57

13.3.1.1. PHYSICAL TREATMENT ..................................................................... 58

13.3.1.2. BIOLOGICAL TREATMENT ................................................................ 58

13.3.1.3. CHEMICAL TREATMENT.................................................................... 59

14. QUALITY CONTROL LABORATORY ..................................................................... 61

14.1. PROCESS CONTROL LABORATORY .............................................................. 61

14.2. FINISHED PRODUCT LABORATORY .............................................................. 62

14.3. ANALYTICAL AND DEVELOPMENT LABORATORY ................................. 62

14.4. ATF LABORATORY .............................................................................................. 62

14.5. POLLUTION CONTROL LABORATORY ......................................................... 62

14.6. DESCRIPTION OF TESTS .................................................................................... 63

14.6.1. CLOUD POINT ............................................................................................. 63

14.6.2. COLD TEST (FREEZING POINT) ............................................................ 64

14.6.3. CETANE NUMBER ..................................................................................... 64

14.6.4. DISTILLATION ........................................................................................... 65

14.6.5. DUCTILITY .................................................................................................. 67

14.6.6. FLASH POINT .............................................................................................. 67

14.6.7. GAS CHROMATOGRAPHIC ANALYSIS ............................................... 68

14.6.8. OCTANE NUMBER (RESEARCH METHOD AND MOTOR

METHOD) ....................................................................................................................... 68

14.6.9. PENETRATION OF BITUMEN ................................................................. 69

14.6.10. POUR POINT TEST..................................................................................... 70

14.6.11. SMOKE POINT ............................................................................................ 70

14.6.12. REID VAPOUR PRESSURE OF HYDROCARBON LIQUID ............... 71

REFERENCES ........................................................................................................................72

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1. ATMOSPHERIC AND VACUUM DISTILLATION UNIT (AVU)

1.1. INTRODUCTION

The ADU (Atmospheric Distillation Unit) separates most of the lighter end products such

as gas, gasoline, naphtha, kerosene, and gas oil from the crude oil. The bottoms of the

ADU are then sent to the VDU (Vacuum Distillation Unit).

Crude oil is preheated by the bottoms feed exchanger, further preheated and

partially vapourized in the feed furnace and then passed into the atmospheric tower where

it is separated into off gas, gasoline, naphtha, kerosene, gas oil and bottoms.

Atmospheric and Vacuum unit (AVU) of Mathura Refinery is designed to process

100% Bombay High Crude and 100% Arab Mix crude (consisting of Light and Heavy

crude in 50:50 proportion by weight) in blocked out operation @ 11.0 MMTPA.

AVU consists of following sections:

Crude Desalting section

Atmospheric Distillation section

Stabilizer section

Vacuum Distillation section

1.2. TYPES OF CRUDE

Low Sulphur

Indian: Bombay High

Nigerian: Girasol, Farcados, Bonny light

High Sulphur

Imported: Arab Mix, Kuwait, Dubai, Ratawi, Basra etc

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1.3. PRODUCTS FROM CDU/VDU MAIN COLUMNS

SHORT

NAME

LONG NAME CUT RANGE ºC

USAGE

Gas Fuel gas C1 –C2 Internal Fuel

LPG Liquefied Petroleum Gas C3-C4 Domestic Fuel

NAP Naphtha C5-120 MS Component

HN Heavy Naphtha 120-140 HSD component

KERO Kerosene 140-270 Domestic Fuel

ATF Aviation Turbine Fuel 140-240 Aero planes fuel

LGO Light Gas Oil 240/270-340 HSD Component

HGO Heavy Gas Oil 320-370 HSD Component

VD Vacuum Diesel 370+ HSD Component

LVGO Light Vacuum Gas Oil 370-380

Feed to

OHCU/RFCCU

LDO Light Diesel Oil 380-425 Fuel

HVGO Heavy Vacuum Gas Oil 425-550

Feed to

OHCU/RFCCU

V. SLOP Vacuum slop 550-560 IFO Component

VR Vacuum Residue 560 + Bitumen /HPS

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1.4. STEPS OF OPERATION IN AVU PROCESS

CDU

CRUDE RECEIVING

CRUDE PREHEATING (FIRST STAGE)

DESALTING OF CRUDE

CRUDE PREHEATING (SECOND STAGE)

PREFRACTIONATOR DISTILLATION

CRUDE PREHEATING (THIRD STAGE)

RAISING TEMPERATURE WITH FIRED HEATERS

ATOMOSPHERIC DISTILLATION

NAPHTHA STABILISATION

PRODUCT ROUTING AFTER HEAT RECOVERY

VDU

FEED TEMPERATURE INCREASE WITH FIRED HEATER

VACUUM DISTILLATION

PRODUCT ROUTING AFTER HEAT RECOVERY

1.5. FEED SUPPLY

Crude oil is stored in eight storage tanks (six tanks each having a nominal capacity of

50,000 m3 whereas remaining other 2 tanks are of 65,000 m

3 nominal capacity). Booster

pumps located in the off-sites are used to deliver crude to the unit feed pumps. Filters are

installed on the suction manifold of crude pumps to trap foreign matter. For processing

slop, pumps are located in the off-site area, which regulate the quantity of slop into the

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crude header after filters. Provision to inject proportionate quantity of demulsifier into the

unit crude pumps suction header with the help of dosing pump is available.

1.6. SYSTEM DESCRIPTION

Crude Oil is heated up to 136 -141 ºC in the first train of heat exchangers operating in two

parallel sections up to the desalter which is connected in series. Desalting temperature as

required can be maintained manually by operating the bypass valve of heat exchangers.

A two-stage desalter has been designed for 99% salt removal. It is designed to use

stripped sour water for desalting which is being taken from the stripped sour water unit.

Provision to use DM water/ services water is also provided. The electric field in the

desalter breaks the emulsion and the outlet brine from the 1st stage desalter is sent to ETP

on level control.

The crude after leaving the desalter is preheated to 250 to 265 ºC. The preheated

crude is further heated and partially vapourized in Atmospheric Furnace (four furnaces

with four pass each). Heater is a box type vertical furnace with up-firing burners. 7 nos. in

each section are provided on the floor with FG and FO firing facilities. Each crude furnace

has fourteen burners.

1.6.1. FURNACE OPERATION

CDU Fired Heater

VDU Fired Heater

Like any conventional process heater, these heaters are also having two distinct heating

sections:

(i) A radiant section, which houses the burners and forms the combustion chamber or

fire box and

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(ii) A convection section which receives heat from the hot flue gases leaving the

radiant section and is therefore placed above the radiant section.

1.6.1.1. CDU FIRED HEATER

The convection section has 8 rows of tubes with 8 nos. tubes in each. The two rows of

shock tubes, i.e. the two rows just above the radiant section are plain tubes without studs.

The rest six rows are of extended surface type having cylindrical studs. All the convection

bank tubes are of 152mm X 8mm dimension and 5Cr 1/2 Mo material of construction. Of

these 64 tubes in the convection section, 4 no’s studded tubes are for the service of

superheating MP steam for strippers; and the rest 60 nos. tubes are for crude oil service.

Crude oil to be heated enters the convection section in four passes. From outlets of the

convection bank, it passes through crossovers provided inside the furnace into bottom coils

of the radiant section. Steam flow is of single pass to superheating coils. Provision exists to

vent out MP steam ex- super heating coils of furnaces to atmosphere through silencers.

In the radiant box, 84 nos. tubes are arranged horizontally along the height of the

two sidewalls. The tubes are of 152mm x 8mm dimension and 5 Cr 1/2 Mo material of

construction. There are 21 tubes in each pass and the pass flows are up the radiant section

to the heater outlet from top of radiant box to join the 900mm dia. Transfer line going to

crude fractionator. Heater tubes rest on wall-supported hangers and are arranged in such a

fashion as to facilitate free expansion. The floor of furnace is elevated above grade and the

hot air duct (supplying combustion air to burners) runs across the length of the furnace

below the furnace floor. The skin temperature of tubes is limited to 550 0C.

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1.6.1.2. VDU FIRED HEATER

The convection section has 13 rows of tubes with 8 nos. tubes in each. The top three rows

are for the service of superheating LP steam for vacuum column and the rest 10 rows are

for RCO service. The three rows of shock tubes, i.e. the three rows just above the radiant

section are plain tubes without studs. The next seven rows are of extended surface type

having cylindrical studs. Provision exists to vent out MP steam ex- super heating coils of

furnaces to atmosphere through silencers.

There are 5 rows of tubes in arch zone and 9 rows of tubes in radiation zone for

each pass for heating the RCO. The tubes material of construction is 9Cr 1Mo.

The floor of furnace is elevated above grade and the hot air duct (supplying

combustion air to burners) runs across the length of the furnace below the furnace floor.

The skin temperature of tubes is limited to 542 0C.

The furnaces are of balanced draft type with forced draft (FD) fans to supply combustion

air and induced draft (ID) fan to take suction of the flue gases through air-preheating

system and discharge the same to stack.

1.6.2. CRUDE DISTILLATION UNIT

The column is provided with 56 trays of which 8 are baffle trays in the stripping section.

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

the column at tray no. 46 at 355 ºC/365 ºC. Hydrocarbon vapours flash in this zone and

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

RCO.

MP steam having some degree of superheat is introduced in the column below tray

no. 46 at approximately 3.5 kg/cm2 (g) and 290 ºC for stripping of RCO. Steam stripping

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helps to remove lighter constituents from the bottom product (RCO). Hydrocarbon vapours

liberated by flashing move up along with the steam in the column for further mass transfer

at trays in the upper section.

Reduced crude oil product is collected at the bottom of the column and the

overhead vapours are totally condensed in overhead air condenser and train condenser.

This condensed overhead product is separated as hydrocarbon and water in the reflux

drum. Water is drawn out under inter-phase level control and sent to sour water drums.

1.6.3. STABILIZER

Unstable Naphtha containing Fuel Gas, LPG and Naphtha is sent to stabilizer under

cascaded flow control. LPG is pumped to MEROX for treatment.

Fuel Gas generated during BH/AM operation is routed to Fuel Gas Amine treatment Unit

to remove H2S before being routed to the plant Fuel Gas Distribution Header.

1.6.4. VACUUM DISTILLATION UNIT

Hot RCO from the atmospheric column bottom at 355 ºC is mixed with slop recycle from

vacuum column, heated and partially vapourized in 8-pass vacuum furnace and introduced

to the flash zone of the vacuum column. The flash zone pressure is maintained at 115-120

mm of Hg. Steam (MP) is injected into individual passes and regulated manually. Three

injection points have been provided on each pass. This is to maintain required velocities in

the heater, which is Fuel Gas, Fuel Oil or combination fuel fired. Each cell is provided

with 10 burners fired vertically upshot from furnace floor along the centerline of the cell.

The vapourized portions entering the flash zone of the column along with stripped

light ends from the bottoms rise up in the vacuum column and are fractionated into four

side stream products in 5 packed sections. The hydrocarbon vapours are condensed in the

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Vac Slop, HVGO, LDO and LVGO sections by circulating refluxes to yield the side draw

products.

Vacuum is maintained by a two-stage ejector system with surface condensers. The

condensed portion from the condensers are routed to the hot well from where the non-

condensable are sent to the vacuum furnace low-pressure burners or vented to the

atmosphere. Oil carried over along with the steam condensate is pumped to the vacuum

diesel rundown line by overhead oil pumps.

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2. VIS-BREAKING UNIT

2.1. INTRODUCTION

Vis-breaking (Viscosity Breaking or VB) is an important application of thermal cracking

used to produce Fuel Oil (FO) of lower viscosity while increasing the proportion of light

products. The vacuum residue needs further processing either through vis-breaking to

produce FO of acceptable quality or can be hardened to be sold as Bitumen. In India,

secondary processing facilities are available in 7 refineries, of which only IOC's Koyali

uses both the Hydro cracking and the Catalytic cracking method. All other refineries use

the carbon rejection process. The Vis-Breaking unit is a thermal cracking unit, designed for

processing a mixture of atmospheric and vacuum residue from 1:1 mixture of Light

Arabian and North Rumila crudes. It reduces the viscosity and pour point of heavy

petroleum fractions so that product can be sold as fuel oil. The design capacity of the plant

is 1000,000 TPA. The unit produces Gas, Naphtha, Heavy Naphtha, VB Gas Oil and Vis-

Breaker fuel oil (a mixture of VB gas oil and VB tar). A provision is also made by a small

modification to route V.B. gas oil to HSD pool over and above its original routing

provision to V.B. tar (fuel oil).

2.2. SYSTEM DESCRIPTION

The feed passes through the furnace, where cracking reaction takes place and the

conversion in the coil is about 50 to 60 %. The effluent from the furnace is routed to the

soaker drum for completion of vis-breaking reaction. The soaker effluent is quenched

before entering fractionator by injecting column bottom product (VB Tar). The quenched

effluent then enters the VB fractionator. In the bottom of the fractionator, steam is

introduced to remove lighter fractions.

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VB Tar is removed as the bottom product. The overhead fraction is unstable naphtha and

gas. The naphtha is stabilized and sent to MEROX unit for sweetening.

The feed stock, a mixture of atmospheric and vacuum residue, is received in the

surge drum. Pump takes suction from heat exchanger and discharges through a set of

preheat exchangers and boosters into two furnaces operating in parallel. Each furnace has

two passes and provides heat required for preheating. Feed ex furnace outlet enters soaker

drum bottom. Feed comes out from the top after getting cracked under controlled

conditions. A residence time of 1/2 hr is given in the soaker. Soaker effluent is quenched

by injecting cooled vis-breaker tar to arrest further cracking. There is also provision of

processing slop in the unit.

The quenched effluent enters the main fractionator where gas and gasoline are

withdrawn as overhead, gas oil as side stream and the V.B. tar as bottoms.

The overheads from the fractionator are condenser and water cooler respectively.

Uncondensed gas goes to FCC for recovery of LPG. A part of gasoline is pumped to

fractionator as reflux while the balance goes to stabilizer. Stabilized gasoline is sent to

storage tank after sulfur removal in Naphtha MEROX Unit.

The Heavy Naphtha (HN) is drawn from the 10th tray and stripped in HN stripper to meet

the flash point specification. It is cooled in part of air cooler and routed to HSD pool.

The gas oil is drawn from the pan of the tower and is steam stripped in the stripper

to meet flash point specification. It is cooled in air cooler and mixed with V.B. tar leaving

the unit or can be routed to HSD pool. The VB tar from the main column bottom flows

into tar stripper where gas oil fractions are evapourated as a result of pressure reduction.

The tar after cooling is partly sent to the bottom of flash fractionator, tar stripper, soaker

transfer line as quench and the rest goes to storage tank after further cooling by either

mixing with gas oil or alone.

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2.3. THEORY OF VIS-BREAKING

The Vis-Breaking unit is essentially a Thermal cracking unit designed to operate at mild

conditions and to retain all the cracked light oils in the bottom product. This results in

reduction of viscosity of bottom product. In the thermal cracking reaction, heavy oil is

kept at a high temperature of a certain amount of time and this causes the larger molecules

to break up. The resulting product has a random distribution of molecular sizes resulting in

products ranging from light gas to heavy gas oil. These products are characterized as

"Cracked" products and contain a certain percentage of olefin compounds. Whenever a

molecule breaks one of the resulting molecules is an olefin.

CH3-CH2-CH2-CH2-CH2-CH2-CH3 CH3-CH2-CH=CH2 + CH3-CH2-CH3

Cracked products are unstable and form gum. The cracked naphtha has higher octane

number than straight run gasoline.

During the cracking operation, some coke is usually formed. Coke is the end

product of polymerization reaction in which two large olefin molecules combine to form

an even larger olefin molecule.

When above reaction gets repeated several times, the end product is coke. This is

usually found inside the walls of furnace tubes and other spots where oil may remain at

high temperature and soak heat for some time. Severity of over-all reaction is determined

by residence time and temperature of cracking. Residence time in the unit can be varied by

varying charge rate and steam injection rate of DMW injection into furnace coils.

Temperature can be varied as per requirement. The cracking reaction usually does not

become evident until transfer temperature crosses 400 C. When transfer temperature

reaches 460 C; sufficient cracking of oil takes place. Gas and Naphtha are produced, the

viscosity of product is lowered and simultaneously coke deposits in the furnace tubes &

12

soaker. Increased severity results in shorter run lengths and unstable fuel oil with

sediments in it.

2.4. VIS-BREAKER FURNACES

Vis-breaker unit is provided with two identical natural draft furnaces. They are up-right

steel structures with outer steel casing lined with refractory material. Each of the furnaces

is independent with radiation section at the bottom. Convection section is at the top of the

radiation section and above convection section is the stack. The convection section is

provided to increase thermal efficiency of the furnace by removing further heat from the

flue gases leaving the radiation section. It is having steam super heater tubes, steam

generating tubes and oil tubes each of these numbering 6, 10 and 14 respectively. The

radiation section houses the radiation tubes numbering 30 in each pass. In this section heat

is transferred primarily by radiation by flame and hot combustible gases.

VBU furnace tubes skin temperature is measured by skin thermocouples provided

on tubes in radiation zone. Furnaces are provided with thermocouple in radiation and

convection zones for measuring tube skin temperatures, box temperatures before and after

steam coils, and flue gas to stack temperatures. Thermocouples are also provided inside

furnace tubes for measuring liquid temperatures at different points. The maximum allowed

tubes skin and box temperature in the heaters is 650 C and 750 C respectively.

There is a provision for on-stream analyzer of SO2 emission from both the stacks. The

purpose of the water injection is to maintain suitable velocity in the furnace tubes and to

minimize coking.

Effluent from these passes is gathered and sent to soaker drum. It enters from the

bottom and leaves from the top. Thermal cracking of the feed, which is initiated in the

furnace, gets completed in soaker drum. Residence time of the order of half an hour is

given in soaker.

13

To arrest cracking reactions, materials from each pass of the two furnaces are individually

quenched by the injection of cooled VB tar at 223oC. To increase turbulence and to prevent

coke deposit in the coils, there is provision to inject steam in each pass. The purpose of the

water injection is to maintain suitable velocity in the furnace tubes and to minimize coking.

2.5. V.B. FRACTIONATOR

Soaker effluent after quenching enters fractionator. Temperature in the flash zone is around

420 C. From the column, gas & gasoline are separated as overhead, gas oil as side stream

and the VB tar as bottoms. The fractionator has 26 valve trays and one blind tray. Feed

enters flash zone below the 26th Valve tray.

The overhead vapours from the column are condensed and cooled in heat

exchangers. The liquid vapour mixture is separated in the reflux drum. Gasoline from flash

fractionator is picked up by reflux pumps and partly pumped to column top as reflux. The

remaining gasoline is routed to stabiliser under reflux drum level controller, which is

cascaded with flow controller. The sour water is drained from the drum boot under

interface level controller and routed to sour water stripper. Main reflux drum and its water

boot are having level glasses. Uncondensed gas from Gas oil stripper goes to FCC/AVU

furnaces / Flare. Column top pressure is around 4.5 kg/cm2 (g). Column overhead line is

provided with working and controlled safety valves.

The heavy naphtha at a temperature of about 170 C is withdrawn from tray no. 10

under level controller. It is stripped in the stripper to maintain its flash point. The heavy

naphtha is routed to HSD. Gas oil at a temperature of about 260 C is withdrawn from the

blind accumulator tray under tray level controller. It is steam stripped in the stripper to

maintain its flash point. Vapour from stripper top returns back to column just above the

blind accumulator tray. A part of gas oil from air cooler is used for washing VB tar filters.

Blind accumulator tray and stripper are provided with level glasses.

14

To remove extra heat and to maintain desired temperature profile in column, a portion of

gas oil from blind tray is taken and pumped in two streams. One stream is used as heating

media in steam generator where it is cooled from 260 C to 214 C. The second stream

supplies re-boiling heat to stabilizer re-boiler and gets cooled from 260 C to 215 C. To

protect column bottom against coking, cooled VB tar at 225 C is injected into bottom as

quench. Gas oil vapours from top of stripper get condensed in air cooler and go to reflux

drum. Safety valve is provided to release gas and protect the vessel from over pressure.

Tar is cooled from 351 C to 225 C in feed exchangers and further cooling to 214

C is done. Pumps are having two filters in the suction line with gas oil flushing facilities.

Only one filter is kept in service while the other remains as spare. Cooled VB tar is partly

used as quench to

1. Fractionator column bottom. Bottom temperature is maintained at 355C.

2. Transfer lines of the two furnaces. Temperature of the combined effluent

entering main fractionator is maintained at 427 C.

3. Gas oil stripper bottom should be protected against coking. Bottom temperature

is maintained at 351C.

VB tar is then cooled in boiler feed water exchanger from 232C to 210C. It is further

cooled to 90C and sent to storage with gas oil.

2.6. STABILIZER

Un-stabilized gasoline from reflux drum is picked up by reflux pump and then it is pumped

to stabilizer through stabilized gasoline exchanger. In heat exchanger, feed is heated from

43 C to 120 C while stabilized gasoline is cooled from 180 C to 120C. The column has

30 trays and the feed enters on the 19th.

15

The overhead product at 60 C goes to water condensers. The condensed liquid is collected

in the reflux drum. Uncondensed gas from the drum goes to FCC/unit fuel gas header.

Pressure at the drum is maintained around 8.4 kg/cm2 (g). In case FCC is shutdown, gas is

burnt in furnaces via gas knock out drum. Column overhead has working and controlled

safety valves, which release gas.

2.7. PROCESS VARIABLES

2.7.1. FEED RATE

When feed rate is increased, residence time in furnace coil and column reduces causing

reduction in severity of cracking reaction resulting in raising the viscosity and pour point

of VB tar and in turn reduction of coke lay down in furnace coils & the column.

2.7.2. SOAKER OUTLET TRANSFER LINE

TEMPERATURE

At constant feed rate, if transfer temperature is raised the amount of cracking increases.

2.7.3. VB TAR QUENCH TO THE COLUMN OUTLET

The VB tar quench reduces the temperature at the column outlet and stops further cracking.

This quench helps in reducing the tendency to lay down coke in the transfer lines and

columns.

16

2.7.4. FRACTIONATOR PRESSURE

A lower pressure causes more vapourisation resulting in heavier naphtha and gas oil.

Higher pressure makes naphtha and gas oil lighter. VB tar viscosity also goes down.

2.7.5. FRACTIONATOR TOP TEMPERATURE

Lowering the top temperature reduces initial boiling point and flash point of gas oil. The

yield of naphtha comes down. Raising the top temperature will increase the FBP of gas oil

will come down. Naphtha production will also reduce.

2.7.6. VB TAR QUENCH TOP FRACTIONATOR

BOTTOM

In order to reduce coke formation in the fractionator bottom, cooled VB tar at 225 C is

given as quench to its bottom.

2.7.7. VB TAR QUENCH TO VB TAR STRIPPER

BOTTOM

To minimise coke formation in tar stripper, cooled VB tar at 225 oC is returned as quench

to its bottom.

17

2.7.8. STABILISER TEMPERATURE AND PRESSURE

The stabiliser removes most of butanes and lower hydrocarbons from unstable Naphtha.

These are removed as gas from the stabiliser overhead. Higher top temperature makes

overhead gas heavies. On the other hand, lower top temperature gives lighter gas. Lower

column pressure causes higher amount of hydrocarbons to be carried into the fuel gas

system.

18

3. FLUID CATALYTIC CRAKING UNIT (FCCU)

3.1. INTRODUCTION

In the newer designs for Fluid Catalytic Cracking Unit, cracking takes place using a very

active zeolite-based catalyst in a short-contact time vertical or upward sloped pipe called

the "riser". Pre-heated feed is sprayed into the base of the riser via feed nozzles where it

contacts extremely hot fluidized catalyst at 1230 to 1400 °F (665 to 760 °C). The hot

catalyst vapourizes the feed and catalyzes the cracking reactions that break down the high

molecular weight oil into lighter components including LPG, gasoline, and diesel. The

catalyst-hydrocarbon mixture flows upward through the riser for just a few seconds and

then the mixture is separated via cyclones. The catalyst-free hydrocarbons are routed to a

main fractionator for separation into fuel gas, LPG, gasoline, light cycle oils used in diesel

and jet fuel, and heavy fuel oil.

During the trip up the riser, the cracking catalyst is "spent" by reactions which

deposit coke on the catalyst and greatly reduce activity and selectivity. The "spent" catalyst

is disengaged from the cracked hydrocarbon vapours and sent to a stripper where it is

contacted with steam to remove hydrocarbons remaining in the catalyst pores. The "spent"

catalyst then flows into a fluidized-bed regenerator where air (or in some cases air plus

oxygen) is used to burn off the coke to restore catalyst activity and also provide the

necessary heat for the next reaction cycle, cracking being an endothermic reaction. The

"regenerated" catalyst then flows to the base of the riser, repeating the cycle.

The gasoline produced in the FCC unit has an elevated octane rating but is less

chemically stable compared to other gasoline components due to its olefin profile. Olefins

in gasoline are responsible for the formation of polymeric deposits in storage tanks, fuel

19

ducts and injectors. The FCC LPG is an important source of C3-C4 olefins and isobutane

that are essential feeds for the alkylation process and the production of polymers such as

polypropylene.

In this process Heavy Gas Oil cut (Raw Oil) from Vacuum Distillation Section of

AVU is catalytically cracked to obtain more valuable light and middle distillates. The

present processing capacity of the unit is about 1.48 MMT/Yr. It consists of the following

sections:

Cracking section

Catalytic section,

Fractionation section and

Gas concentration section.

CO boiler

The unit is designed to process two different types of feed i.e. Arab Mix HVGO and

Bombay High HVGO.

3.2. CRACKING SECTION

Cracking process uses high temperature to convert heavy hydrocarbons into more valuable

lighter products. This can be accomplished either thermally or catalytically. The catalytic

process has completely superseded thermal cracking as the catalyst helps the reactions to

take place at lower pressures and temperatures. At the same time, the process produces a

higher octane gasoline, more stable cracked gas and less of the undesirable heavy residual

product. The process is also flexible in that it can be tailored to fuel oil, gas oil operations

producing high yields of cycle oils or to LPG operations producing yields of C3-C4

fraction.

The fluid Catalytic Cracking process employs a catalyst in the form of minute

spherical particles, which behaves like a fluid when aerated with a vapour. This fluidized

20

catalyst is continuously circulated from the reaction zone to the regeneration zone. The

catalyst also transfers heat carried with it from one zone to the other viz. in the vessels

reactor and regenerator. The reaction and regeneration zones form the heart of the

catalytic cracking unit.

Feed to the FCC Unit is gas oils obtained by vacuum distillation of long residue

from the crude distillation unit. In our unit the vacuum cut boiling in the range 380-530 C

will be used as feedstock to the FCC Unit. Carbon content in the feedstock should be

limited to 0.5% by wt. maximum. This carbon content increases with heavier charge stock.

Catalyst section consists of the reactor and regenerator together with the standpipes and

riser form the catalyst circulation circuit. The catalyst circulates up the riser to the reactor,

down through the stripper to the regenerator across to the regenerator standpipe and back

to the riser. The vertical riser is in fact the reactor in which the entire reaction takes place.

The reactor is a container for cyclone separators at the end of vertical riser.

Fresh feed after heat exchange and heating up to 340-360 C in a feed pre-heater

enters through 4 fresh feed nozzles to the riser. Recycle is introduced by 2 HCO and 2

Slurry feed nozzles to the riser. The feed is vapourized and raised to the reactor

temperature by the hot catalyst flowing upward through the riser. Cracking reactions start

immediately as the gas oil comes into contact with the hot catalyst. These reactions

continue till the oil vapours are separated from the catalyst in the reactor. T head separators

mounted on top of the riser separate the catalyst from the oil vapours. This separation is

required to prevent secondary reactions, which will result in higher gas production.

Entrained catalyst and hydrocarbon vapours, after cracking, flow upwards and pass

through two cyclone separators attached to top of the reactor. These cyclones remove most

of the entrained catalyst. Oil vapours containing a small quantity of catalyst pass overhead

through the vapour line into the fractionator.

21

Coke is deposited on the catalyst in the reaction zone. The spent catalyst flows downwards

into the stripping section of the reactor. After steam stripping to remove oil vapours from it

the catalyst flows from the reactor standpipe to the regenerator through a slide valve in the

regenerator, the coke is burnt off, oxygen for burning being supplied by an air blower. Air

from the blower is uniformly given to the regenerator through a pipe grid at its bottom.

The heat of combustion raises the catalyst temperature to more than 600 C. Most of the

heat in the catalyst is given to the feed in the reactor riser to raise it to the reaction

temperature and to provide the heat of reaction. The regenerated catalyst from the

standpipe flows into the riser through a slide valve to complete the catalyst circulation

cycle. Catalyst particles in the flue gas leaving the regenerator are separated at the top of

regenerator by three sets of two-stage cyclones. The flue gas contains both CO and CO2 as

carbon is burnt off partly to CO and partly to CO2 in the regenerator. The sensible and

chemical heat in flue gas is utilized to generate steam in CO Boiler. The flue gas 'is passed

through' the orifice chamber & regenerator. Pressure is controlled by double disc slide

valve. Orifice chamber holds backpressure downstream of double-disc slide valve. By

reducing the pr. drop across slide valve, operating life of slide valve is greatly extended by

avoiding sudden accelerations of catalyst, bearing flue gas stream.

3.3. CATALYTIC SECTION

The Fluid Catalytic Cracking process employs a catalyst in the form of minute spherical

particles, which behaves like a fluid when aerated with a vapour. This fluidized catalyst is

continuously circulated from the reaction zone to the regeneration zone.

Feed to the FCC Unit is gas oils obtained by vacuum distillation of long residue

from the crude distillation unit. In our unit the vacuum cut boiling in the range 380-530°C

is used as feedstock to the FCC Unit. Conradson carbon content in the feedstock should be

22

limited to 0.5% by wt. maximum. Metal contaminants of the feedstock are also to be

limited to a metal factor of 2.5 maximum.

Metal Factor = Fe + V + (Ni + Cu)

Catalyst section consists of the reactor and regenerator together with the standpipes

and riser form the catalyst circulation circuit. The catalyst circulates up the riser to the

reactor, down through the stripper to the regenerator across to the regenerator standpipe

and back to the riser. The vertical riser is in fact the reactor in which the entire reaction

takes place. The reactor is a container for cyclone separators at the end of vertical riser.

Fresh feed after heating up to 350 C in a feed pre-heater along with recycle

streams enters the base of the riser. In the riser the combined feed is vapourized and raised

to the reactor temperature by the hot catalyst flowing upward through the riser. Cracking

reactions start immediately as the gas oil comes into contact with the hot catalyst.

Entrained catalyst and hydrocarbon vapours, after cracking, flow upwards and pass

through two cyclone separators attached to top of the reactor. These cyclones remove most

of the entrained catalyst. Oil vapours containing a small quantity of catalyst pass overhead

through the vapour line into the fractionator.

Coke is deposited on the catalyst in the reaction zone. The spent catalyst flows

downwards into the stripping section of the reactor. After steam stripping to remove oil

vapours from it the catalyst flows from the reactor standpipe to the regenerator through a

slide valve in the regenerator, the coke is burnt off, oxygen for burning being supplied by

an air blower. The heat of combustion raises the catalyst temperature to more than 600 C.

Most of the heat in the catalyst is given to the feed in the reactor riser to raise it to the

reaction temperature and to provide the heat of reaction. The regenerated catalyst from the

standpipe flows into the riser through a slide valve to complete the catalyst circulation

23

cycle. Catalyst particles in the flue gas leaving the regenerator are separated at the top of

regenerator by three sets of two-stage cyclones. The flue gas contains both CO and CO2 as

carbon is burnt off partly to CO and partly to CO2 in the regenerator. The sensible and

chemical heat in flue gas is utilized to generate steam in CO Boiler.

3.3.1. TYPE OF CATALYSTS

The unit requires two types of catalysts, viz.

(i) Fresh catalyst

(ii) Equilibrium catalyst

The unit is designed for use of high ZEOLITE catalyst, which is microspheriadical in

shape, as fresh catalyst.

3.4. FRACTIONATION SECTION

In this section, the vapours coming out of the reactor top at very high temperature are

fractionated into wet gas and un-stabilized gasoline overhead products, heavy naphtha, and

light cycle oil as side products. Heavy cycle oil drawn from the column is totally recycled

along with the feed after providing for the recycle stream to the column.

The column bottom slurry containing a small quantity of catalyst is sent to a slurry

settler. From the settler bottom, the thickened slurry is recycled back to the riser for

recovering catalyst and further cracking. From the top of slurry settler, clarified oil product

is taken out after cooling, which goes for blending in Fuel Oil.

24

3.5. GAS CONCENTRATION SECTION

The wet gas from the fractionator overhead receiver is compressed in a two-stage

centrifugal compressor and sent to a high-pressure (HP) receiver after cooling. Gas from

the HP receiver is sent to the Primary Absorber for recovery of C3's and heavier

components by absorption with stabilized gasoline taken from the debutanizer column

bottom and un-stabilized gasoline from main column overhead receiver. Rich gasoline

from absorber bottom is recycled back to the HP receiver. The stripped gasoline is further

stabilized in the debutanizer removing C3 and C4 components from it as cracked LPG and

bottom product as stabilized FCC gasoline. Both LPG and gasoline are MEROX treated

before routing to storage.

3.6. CO BOILER

The flue gas leaving the regenerator via orifice chamber contains 8-13% carbon monoxide,

the rest being inert like nitrogen, steam, carbon dioxide, etc. In the CO Boiler, flue gas is

burnt with air converting carbon monoxide to carbon dioxide, thus releasing the heat of

combustion of CO in the boiler. This heat as well as the sensible heat in flue gas available

at a high temperature is utilized for raising medium pressure steam.

4. MEROX UNIT (MERCAPTAN OXIDATION)

4.1. INTRODUCTION

The MEROX process efficiently and economically treats petroleum fractions to remove

mercaptan sulfur (MEROX extraction) or to convert mercaptan sulfur to less-

objectionable disulfides (MEROX sweetening). This process can be used to treat liquids

such as liquefied petroleum gases (LPG), natural-gas liquids (NGL), naphtha, gasoline,

25

kerosene, jet fuels, and heating oil. It can also be used to treat gases such as natural gas,

refinery gas, and synthetic gas in conjunction with conventional pre-treatment and post-

treatment processes.

Straight-run LPG, gasoline and kerosene fractions obtained from atmospheric

distillation may contain hydrogen sulfide and mercaptans, the extent of which mainly

depends upon the type of crude processed. Similar products from secondary processes such

as FCC also contain hydrogen sulfide and mercaptans to a greater degree compared to

straight-run products. Hydrogen sulfide is corrosive and should be removed in order to

meet specifications on corrosion rate. The specification for LPG, gasoline, Kerosene and

ATF include copper strip corrosion test which is a measure of rate of corrosion on copper

containing materials. Mercaptans are substances with obnoxious odor and, therefore, in

order to handle and store them, mercaptan level will have to be brought down to an

acceptable odor level. The specifications of above products include 'Doctor Test' which

must be negative and is generally related to the extent of mercaptan present. Hydrogen-

sulfide can be easily removed by washing with dilute caustic solution. However, for

reducing the mercaptan level many processes are available like:

Strong alkali-wash

Copper sweetening

Doctor sweetening

MEROX process

Hydro desulphurization

Alkali-wash is effective only if low molecular weight mercaptans are involved. Hydro

desulphurization is normally employed only if reduction of total sulphur level is also

required. Both investment and operating costs are higher in case of hydro desulphurization.

26

4.2. MEROX PROCESS DESCRIPTION

MEROX process equipment

Pretreatment

Extraction section

Sweetening

Post treatment

MEROX catalysts

The MEROX process licensed by M/S Universal Oil Products Co., (UOP), USA, is for the

chemical treatment of LPG, gasoline and distillates to remove mercaptans into disulfides.

The removal of mercaptans may be either partial or full. The chemical treatment is based

on the ability of MEROX catalysts to promote the oxidation of mercaptan to disulfide

using air as the source of oxygen. The overall reaction is as follows:

2RSH + 1/2O2 RSSR + H2O

The oxidation is carried out in the presence of an aqueous alkaline solution such as sodium

hydroxide or potassium hydroxide. The reaction proceeds at an economical rate at normal

rundown temperature of refinery streams.

Low molecular weight mercaptans are soluble in caustic solution and therefore

when treating LPG and light gasoline fractions, the process can be used to extract

mercaptan to the extent, they are soluble in caustic. Extraction of mercaptan reduces the

sulphur content of the treated product. Alternatively mercaptans can be converted to

disulfides without removing any sulphur from the treated stock in which case the operation

is referred to as sweetening. In the treatment of heavier boiling fractions such as heavy

naphtha and kerosene only sweetening is possible.

27

4.2.1. PRETREATMENT

Petroleum fractions may contain hydrogen sulfide and stocks boiling higher than 180°C

may also contain naphthenic acids. Hydrogen sulfide is not a catalyst poison as such, but

will dilute the caustic containing MEROX catalyst by reacting with caustic. Further it

blocks some of the catalyst activity sites slowing down the normal reaction and also

consumes part of the oxygen available. Hence, it is recommended that hydrogen sulfide is

removed by washing with dilute alkali solution before the distillate is sent to reactor for

treatment.

Naphthenic acids also interfere with treating operations and must be removed prior

to treatment. The reactor contains caustic and if naphthenic acids are not removed, they

form sodium naphthenates, which coat the catalyst and block the pores. For removal of

naphthenic acids, the procedure used is to wash with dilute caustic. Dilute caustic is used

so as to avoid formation of emulsions. There could, however, be some carry-over of haze

depending on the acidity of stock treated. The haze can easily be removed by coalescing

through a sand filter.

Feedstock, where carry-over of water from distillation units can be expected must

be passed through a coalescer for removal of suspended water prior to caustic wash, which

would otherwise dilute the caustic used for pretreatment.

4.2.2. EXTRACTION SECTION

As previously stated, low molecular weight mercaptans are caustic soluble and can easily

be removed by washing with caustic in a counter current tower. Improved extraction is

favored by:

(i) Low temperature

(ii) High concentration of caustic

28

(iii)Lower molecular wt. of mercaptans

Type of mercaptans, viz. normal mercaptans are easily extractable, tertiary mercaptans

least extractable and secondary being in between.

The mercaptan enters the caustic solution and reacts as follows:

RSH + NaOH NaSR + H2O

This being a reversible reaction the degree of completion of reaction is governed by normal

equilibrium laws.

The sodium mercaptide is readily oxidized to disulfide in the presence of MEROX catalyst

as shown:

2NaSR + l/2O2 + H2O 2NaOH + RSSR

This is not a reversible reaction and the reaction rate is sped up by:

(i) Raising the temperature

(ii) Use of excess air

(iii)Increasing the intimacy of contact

(iv) Increasing the catalyst concentration

The oxidation of mercaptides is carried out in oxidizer in the presence of MEROX catalyst.

The disulfides oil, which is formed, separates out from caustic, as it is insoluble in caustic.

Caustic can be reused for extraction. The presence of MEROX catalyst in extraction

caustic does not however, affect the amount of mercaptans extracted and extraction is

dependent only on parameters explained earlier.

29

4.2.3. SWEETENING

Sweetening can be defined as conversion of mercaptan sulphur present in a hydrocarbon

stream to disulfide sulphur without actually reducing sulphur content of treated stock. The

sweetening process is based on the ability of MEROX catalyst to promote the oxidation of

mercaptans to disulfide using air as the source of oxygen. The reaction is as follows:

RSH + NaOH NaSR + H2O

2NaSR + l/2O2 + H2O 2NaOH + RSSR

As can be seen from reactions, the oxidation is carried out only in the presence of alkali

solution.

The Sweetening can be accomplished either as solid bed sweetening, where the

hydrocarbons and caustic are simultaneously controlled over a solid support impregnated

with MEROX catalyst or as liquid-liquid sweetening, where hydrocarbon, air and caustic

containing MEROX catalyst are simultaneously controlled in a mixer.

Solid bed sweetening consists of a reactor, which contains a bed of activated

charcoal impregnated with MEROX catalyst and kept wet with caustic solution.

Impregnation of catalyst on bed is achieved by dissolving the catalyst with ammonia

solution and pumping ammonia solution over charcoal. Air is injected ahead of reactor and

in the presence of MEROX catalyst the mercaptans are oxidized to disulfide. The reactor is

followed by a settler, which serves as reservoir of caustic. Caustic is intermittently

circulated from the settler over the catalyst bed to wet the charcoal.

For liquid-liquid sweetening, the most common type of mixer used is the orifice

plate mixer, which is a vessel, fitted with a series of plates with orifices. The vessel

provides adequate residence time and the orifice plates create enough turbulence to bring

30

about the intimate contact between hydrocarbons, caustic, catalyst and air. The higher the

molecular weight or the more highly branched the mercaptan is, the more difficult it is to

accomplish necessary mixing. Hence heavy gasoline and Kerosene may have to be treated

using fixed bed reactor.

4.2.4. POST TREATMENT

The product from the MEROX reactor will at times contain caustic haze. Post treatment is

required if the product is to go to storage, clear and bright. In most cases provision of

caustic settler and sand filter is adequate to remove caustic haze. However, for treatment of

ATF, which has to meet stringent specifications caustic must be removed by water wash

after caustic settling. Water wash removes entrained caustic as well as water soluble

surfactants. Water wash is followed by a salt filter to remove entrained water and part of

the dissolved water. This may be followed by clay filter to remove copper and water

insoluble surfactants, if present in feed.

4.2.5. MEROX CATALYSTS

There are two types of MEROX catalyst, each one being used for specific service. Catalyst

FB is to be used on units equipped with solid bed sweetening reactors. Catalyst WS is used

for liquid-liquid sweetening in mixers. This is a caustic dispersible catalyst. This is also

used for oxidation of extraction caustic in oxidizers.

31

5. CONTINUOUS CATALYTIC REFORMING UNIT (CCRU)

5.1. INTRODUCTION

A catalytic reforming process converts a feed stream containing paraffins, Olefins and

naphthene to aromatics. The product stream of the reformer is generally referred to as

reformate. Reformate produced by this process has a very high octane rating. Significant

quantities of hydrogen are also produced as a by-product. Catalytic reforming is normally

facilitated by a bi-functional catalyst that is capable of rearranging and breaking long-chain

hydrocarbons as well as removing hydrogen from naphthenes to produce aromatics. The

idea of a Catalytic Reforming Unit is to have RON (Research Octane Number) as high as

possible at the same time keeping the Olefins, Benzene & Aromatics under the specified

limits. The different types of reformers are classified as a fixed-bed type, semi-regenerative

type, cyclic type and the continuous regenerative type. This classification is based on the

ability of the unit to operate without bringing down the catalyst for Regeneration. During

the regeneration process, the refinery will suffer production loss. In the Continuous

Catalytic Reforming unit, the reactors are cleverly stacked, so that the catalyst can flow

under gravity. From the bottom of the reactor stack, the 'spent' catalyst is 'lifted' by

nitrogen to the top of the regenerator stack. In the regenerator, the above mentioned

different steps, coke burning, oxychlorination and drying are done in different sections,

segregated via a complex system of valves, purge-flows and screens. From the bottom of

the regenerator stack, catalyst is lifted by hydrogen to the top of the reactor stack, in a

special area called the reduction zone. In the reduction zone, the catalyst passes a heat

exchanger in which it is heated up against hot feed. Under hot conditions it is brought in

contact with hydrogen, which performs a reduction of the catalyst surface, thereby

restoring its activity. In such a continuous regeneration process, a constant catalyst activity

can be maintained without unit shut down for a typical run length of 3 - 6 years. The

32

purpose of the CCR unit is to produce a high octane no. reformate. The octane no. of the

gasoline coming from the AVU is around 66, whereas the required value of the octane no.

is 87, 88 and 93. The whole CRU can be divided into three subunits as:

Naphtha Splitting Unit (NSU)

Naphtha Hydro-treater Unit (NHU)

Catalytic Reforming Unit

5.1.1. NAPHTHA SPLITTING UNIT

This unit has been designed to split SR naphtha (144 MT/hr for BH and 95 MT/hr for AM)

to C5-80 oC and 80-115 oC cut. Due to the restriction on Benzene content in the final

product (motor spirit), the IBP of the heavier cut is raised to approximately 105 oC. NSU

can be operated with naphtha directly from AVU (hot feed) and from OM&S (Cold feed),

it can also be operated using both the feed simultaneously. For removal of benzene, the

gasoline from storage tanks and CDU is sent to a column, containing 40 valve trays, which

is called naphtha splitter. The bottom product of naphtha splitter is sent to the NHU.

5.1.2. NAPHTHA HYDROTREATER UNIT

The purpose of Naphtha hydrotreater is to eliminate the impurities (such as sulphur,

nitrogen, halogens, oxygen, water, olefins, di-olefins, arsenic and metals) from the feed

that would otherwise affect the performance and lifetime of reformer catalyst. This is

achieved by the use of selected catalyst (nickel, molybdenum) and optimum operating

conditions except for water, which is eliminated in stripper.

In this unit, the naphtha coming from the NSU is mixed with H2 which comes from

the reforming unit. This mixture is heated to 340 OC in the furnace and then passed to the

hydrotreater reactor at a pressure of 22 kg/cm2.

33

In the reactor, there are two beds of catalyst. In one bed, the unsaturated hydrocarbons are

converted to saturated hydrocarbons and in the second bed impurities like N, S, and O are

converted to NH3, H2S and H2O respectively. The effluent of the reactor is sent to stripper

section to eliminate the light end, mainly the H2S and moisture from the reformate feed.

The light gases from the top of stripper are sent to amine wash unit. There is a reboiler

attached to the bottom of the stripper, which maintains the heat requirement. The bottom

product of the stripper is either sent to storage or the reforming unit.

5.1.3. REFORMING UNIT

Feed for the Reforming unit (94 m3/hr at 14 kg/cm

2 and 110

oC) is received directly from

hydrotreater stripper after heat exchanger. The filters must be provided for the protection

of the welded plate exchanger. Feed is filtered to remove any foreign particles. At the D/S

of the feed filter, chloriding agent and water injection are done. CCl4 solution of 1% in

reformate is dosed by pump. Dosing @ 1 ppm wt CCl4 in feed is done when continuous

regeneration unit is down. Water injection (not on regular basis) is done to maintain Cl-OH

equilibrium on the catalyst when regenerator is out of service.

Feed mixed with recycle H2 stream gets preheated in PACKINOX exchanger from

91C to 451C by the effluent from 3rd Reactor which gets cooled down from 497 C to

98C.

Due to the endothermic nature of the reforming reactions, the overall reforming is

achieved in stages with inter stage heater provided to raise the temperature. There are three

Reactors (15R-1, R-2 & R-3) each provided with reaction heater.

34

5.2. REACTORS

In the reactors, the feed contacts the reforming catalyst which is divided approximately in

the ratio 15: 30: 55. In the CCR process, the catalyst circulates continuously in reactors, in

the space between the external grid and the central pipe from the top to the bottom, from

one reactor bottom to the top of the next one, from the last reactor to the regeneration unit

for regeneration. From the regeneration unit, the regenerated catalyst returns to the first

reactor.

Each reactor is a vertical cylindrical vessel with spherical heads. It is equipped with

one inlet & one outlet nozzle for feed & effluent respectively. Catalyst enters the reactor

through 12 nos. of 3" pipes, flows through the space between external grid and the central

pipe from top to bottom and exits through 12 nos. of 2"pipes, slow moving bed of

bimetallic catalyst and exits through the outlet nozzle at the bottom. The radial flow of feed

is achieved by directing the flow through external grid to catalyst bed & exit is made to

central outlet collector pipe. Gas tight baffle is provided on the outlet pipe to avoid short-

circuiting of the feed to outlet pipe at the entrance.

Reactor effluent after passing through PACKINOX exchanger is cooled in air

cooler to 65 C and then by trim cooler to 45C before entering the separator. The

separated gas is compressed in the recycle gas compressor and a part is recycled to the

reactors. The remaining gas is routed to a re-contacting section to improve hydrogen purity

and recover liquid yield.

6. ONCE THROUGH HYDROCRACKER UNIT (OHCU)

6.1. INTRODUCTION

Hydro Cracking Unit is designed for 1.2 MMT/year (165.6 m³/hr, 25,000 BPSD). The

objective of the Hydro Cracking Unit is to produce middle distillate fuel of superior

35

quality. The unit is designed to process two different types of feed i.e. Arab Mix HVGO,

Bombay High HVGO. All the H2S will be removed by absorbing in DEA.

6.2. PROCESS DESCRIPTION

The Hydrocracker Unit consists of four principle sections:

Make-Up Hydrogen Compression

Reaction Section

Fractionation Section

Light Ends Recovery Section

6.2.1. REACTOR FEED SYSTEM

Fresh feed to the Hydrocracker consists of a blend of Arab Mix and Bombay High VGO.

The feed control system allows the operator to control the ratio of Arab Mix and Bombay

High VGOs in order to set the relative rates of each. The preheated and filtered oil feed is

combined with a preheated mixture of make-up hydrogen from the make-up hydrogen

compression section and hydrogen-rich recycle gas from the recycle gas compressor in a

gas-to-oil ratio of 845 Nm3/m

3. The combined oil and gas streams are heated in the

feed/effluent exchangers and then further heated to the desired reactor inlet temperature in

the reactor feed furnace. The reactor system contains one reaction stage consisting of two

reactors in series in a single high-pressure loop. The lead and main reactors contain hydro

treating and hydro cracking catalyst (Si/Al with Ni-Co-Fe) for denitrification,

desulphurization, and conversion of the raw feed to products.

The reactor effluent is initially cooled by heat exchange with the VGO feed and

then by heat exchange with recycle gas and with the product fractionator feed. The effluent

is then used to generate medium pressure [12.0 kg/cm2 (g)] steam.

36

After the effluent stream is cooled, it is sent to the HHPS at 210°C to separate the reactor

products from the excess hydrogen and gases formed in the reactors. Liquid from the

HHPS flows to the power recovery turbine (PRT), where it is let down in pressure before

entering the hot low-pressure separator (HLPS).

The effluent vapour separated in the HHPS contains most of the H2, H2S, NH3, and

light hydrocarbon gases. The effluent vapour is cooled by heat exchange with the CLPS

liquid, where it exchanges heat with the reactor feed gas. Subsequently it enters the

effluent vapour air cooler. Cooled reactor effluent vapour, condensed light hydrocarbons,

and sour water enter the CHPS at 65C. Hydrogen-rich recycle gas separates from the oil

and water phases, exits the CHPS, and enters the recycle gas loop. Liquid hydrocarbon is

drawn off and is sent to the CLPS. The sour water, containing about 7 wt % ammonium bi-

sulfide, is drawn from the separator bottom and sent to sour water stripping.

Hydrogen-rich recycle gas is sent to a High Pressure H2S absorber. The H2S is

removed from the recycle gas by being absorbed by an amine solution (25 wt % Di-ethanol

amine) flowing countercurrent to the recycle gas. The lean amine is heated by heat

exchange with diesel product and then by steam. After heating, the lean amine is sent to a

surge drum before being pumped up to system pressure. The H2S-rich amine stream from

the bottom of the absorber is let down in pressure and sent to a flash drum and amine

regeneration unit. The H2S absorber vapour flows to Porta Separator and then to the

recycle compressor knockout drum, where any entrained liquid is removed.

The hydrogen-rich vapour from the knockout drum flows to the recycle compressor

(Centrifugal Compressor) that restores the pressure losses accumulated as the gas flows

through the high-pressure loop.

Part of the compressed recycled gas is used as quench gas and the remaining recycle gas

combined with make-up hydrogen to form the reactor feed gas.

37

6.2.2. FRACTIONTATION SECTION

The fractionation section consisting of the fractionator, side cut strippers, and heat

exchange equipment is designed to separate conversion products from unconverted feed.

The reaction products recovered from the column are Sour Gas (Off gas), Unstable Light

Naphtha, Heavy Naphtha, Kerosene, Diesel and FCC Feed. The fractionator off-gas and

unstable light naphtha are sent to the light ends recovery section for recovery of LPG and

light naphtha product.

6.2.3. DE-ETHANISER

The de-ethaniser remove light ends (C2), H2S, and water from the light naphtha and LPG.

Feed enters the top of the column. The feed to the de-ethaniser comes from the combined

liquid stream leaving the de-ethaniser reflux drum and is pumped to the top of the de-

ethaniser.

7. DIESEL HYDRO DESULFURIZATION UNIT (DHDS)

7.1. INTRODUCTION

DHDS (Diesel hydro desulphurization unit) is set up for the following purposes:

A step towards pollution control

To produce low sulphur diesel (0.25 w/w %) as per govt. directive w.e.f. Oct. 1999.

Feed consists of different proportion of straight run LGO, HGO, LVGO and TCO. Mainly

two proportions are used:

74% SR LGO, 21% SR HGO, 5% SR LVGO

38

48% SR LGO, 24% SR HGO, 8% SR LVGO, 20% TCO

The DHDS unit treats different gas oils from various origins, straight run or cracked

products. The feed is a mixture of products containing unsaturated components (diolefins,

olefins), Aromatics, Sulfur compounds and Nitrogen compounds. Sulfur and nitrogen

contents are dependent upon the crude.

The purpose of DHDS Unit is to hydro-treat a blend of straight run gas oil and

cracked gas oil (TCO) for production of HSD of sulfur content less than 500 ppm wt.

The Hydrodesulphurization reaction releases H2S in gaseous hydrocarbon effluents.

This H2S removal is achieved by means of a continuous absorption process using a 25%

wt. DEA solution.

In addition to the desulphurization, the diolefins and olefins will be saturated and a

denitrification will occur. Denitrification improves the product stability. The hydrogen is

supplied from the hydrogen unit. Lean amine for absorption operation is available from

Amine Regeneration Unit (ARU). Rich Amine containing absorbed H2S is sent to ARU for

amine regeneration.

7.2. CATALYSTS

Catalysts used for this process are HR-945 and HR-348/448.The HR-945 is a mixture of

nickel and molybdenum oxides on a special support. Nickel has been selected because it

boosts the hydrogenating activity. The HR-348 and HR-448 are desulphurization catalysts;

it consists of cobalt and molybdenum oxides dispersed on an active alumna. Its fine

granulometry and large surface area allow a deep desulphurization rate.

Different catalysts based on Nickel and Molybdenum Oxide are used to enhance

the rate of reactions.

39


Feed can be received from three sources:

From feed tanks

Directly from AVU

TCO from FCC

Feed from above sources pass through feed filter and is received in feed surge drum. The

level of feed surge drum is controlled by controller, which can be cascaded with feed from

storage or feed from AVU. Water if any shall be collected in the water boot of surge drum

and its discharge passes through pre-heat exchangers. Hydrogen recycle joins the feed

before heat exchangers. Feed then enters heater in four passes and then to reactor. The

reactor has two catalyst beds. Recycle gas quench is given in between reactor catalyst beds

to control inlet temperature of lower bed. Reactor effluent from reactor bottom is utilized

for preheating of feed in exchangers. The other part of reactor effluent is utilized to preheat

the stripper feed in exchangers. All the effluent join and enter to reactor effluent cooler and

condenser and finally to cold high pressure separator (CHPS).

The vapour phase from CHPS is sent to high-pressure amine absorber through

high-pressure amine knockout drum. This gas is treated with lean DEA solution in high-

pressure amine absorber. The treated gas goes to recycle gas compressor through recycle

gas compressor knockout drum.

The liquid hydrocarbon under level control from CHPS is sent as feed to stripper

after preheating heat exchanger. Water from CHPS boot is sent partially to water drum and

balance to sour water stripper unit.

Sweet diesel from bottom of stripper exchanges heat with stripper feed in

exchangers and is pumped to storage under stripper bottom level control before routing to

40

storage tank. Diesel is cooled in air cooler and water cooler, then passed through coalescer

preheater. Water if any is separated in coalescer.

7.4. PROCESS VARIABLES

7.4.1. HYDROGEN PARTIAL PRESSURE

The hydrogen partial pressure has to be kept as high as possible, in order to favour the

desirable reactions:

Hydrodesulphurization

Hydrogenation of nitrogen and oxygen compounds

High hydrogen partial pressure decreases the undesirable reactions of:

Hydro cracking

Coking

7.4.2. TEMPERATURE

The reaction temperature must be kept as low as possible because the most desirable

reactions do not need high temperature to remain at desirable rates.

Hydrodesulphurization

Hydrogenation of nitrogen and oxygen compounds

41

8. HYDROGEN GENERATION UNIT (HGU) - I

The Hydrogen plant is designed for production of 34,000 MTPY of Hydrogen. Process

licensor for HGU is HTAS, Denmark. The plant is divided into 3 sections.

Desulphurization

Reforming

CO-Conversion

8.1. FEED

The hydrogen generation unit can be fed either by naphtha or natural gas. The naphtha feed

is pressurized to about 35 Kg/cm2g by one of the naphtha feed pumps and sent to the

desulphurization section.

The pressurized feed is mixed with recycle hydrogen from the hydrogen header.

The liquid naphtha is evapourated to one of the naphtha feed vapourizers. The hydrocarbon

feed is heated to 380°-400 OC by heat exchange with superheated steam in the naphtha

feed pre-heater.

8.2. DESULPHURIZATION

The desulphurization takes place in two steps. The first catalyst in the desulphurization

system is a cobalt-molybdenum hydrogenation catalyst.

R1 – S – R2 + 2H2 → R1 – H + R2 – H + H2S

42

Having passed the hydrogenation catalyst in the first reactor the hydrogenated process feed

is sent to the sulphur absorbers. Here the H2S formed is absorbed by the ZnO absorption

catalyst.

ZnO + H2S → ZnS + H2O

The concentration of sulphur leaving the absorbers shall be lower than 50 ppm.

8.3. REFORMING SECTION

8.3.1. PRE-REFORMER

The mixture of gas and steam (the process gas) is heated to approximately 490OC. The

preheated process gas passes the pre-converter, where all higher hydrocarbons are

converted into methane, hydrogen, carbon monoxide and carbon dioxide.

8.3.2. TUBULAR REFORMER

The pre-converted process gas is further preheated to approximately 650°C in the reformer

feed preheat coil before it is sent to the tubular reformer containing 126 catalyst tubes

maintained at desired temperature. The reformer effluent leaves the tubes at a temperature

of approximately 930 ° C.

43

9. BITUMEN BLOWING UNIT (BBU)

9.1. INTRODUCTION

Asphaltic bitumen, normally called "bitumen" is obtained by vacuum distillation or

vacuum flashing of an atmospheric residue. This is “straight run" bitumen. An alternative

method of bitumen production is by precipitation from residual fractions by propane or

butane- solvent de-asphalting.

The bitumen thus obtained has properties which are derived from the type of crude

oil processed and from the mode of operation in the vacuum unit or in the solvent de-

asphalting unit. The grade of the bitumen depends on the amount of volatile material that

remains in the product: the smaller the amount of volatiles, the harder the residual bitumen.

The blowing process for bitumen preparation is carried out continuously in a blowing

column. The liquid level in the blowing column is kept constant by means of an internal

draw-off pipe. This makes it possible to set the air-to-feed ratio (and thus the product

quality) by controlling both air supply and feed supply rate. The feed to the blowing unit

(at approximately 210 0C), enters the column just below the liquid level and flows

downward in the column and then upward through the draw-off pipe. Air is blown through

the molten mass (280-300 0C) via an air distributor in the bottom of the column. The

bitumen and air flow are countercurrent, so that air low in oxygen meets the fresh feed

first. This, together with the mixing effect of the air bubbles jetting through the molten

mass, will minimise the temperature effects of the exothermic oxidation reactions, local

overheating and cracking of bituminous material. The blown bitumen is withdrawn

continuously from the surge vessel under level control and pumped to storage through

feed/product heat exchangers.

44

Air residue having boiling point 530oC (TBP) is obtained from North Rumaila crude. Air

blowing of vacuum residue at high temperature considerably increases the contents of

gums and asphaltenes at the expense of conversion of a portion of hydrocarbon into

condensed oil. Bitumen is a colloidal solution of asphaltenes and associated high molecular

gums in the medium formed by oils and low molecular gums. Asphaltene content in the

bitumen influences its solidity and softening point. The higher the asphaltene content, the

more solid is the bitumen. Gums increase bitumen binding properties and elasticity.


9.2.1. FEED SUPPLY SYSTEM

The feed to the unit consists of hot SR taken directly from the vacuum unit or cold residue

from tanks. The hot feed goes to reactors at 200-210oC in two parallel streams. Flow

control valves control feed flow to individual reactors. As refinery would be processing

both Imported and Bombay high crude in blocked out cyclic operation, the unit will not get

hot feed during the period AVU processes indigenous crude. To avoid shut down of BBU

under such circumstances or when VDU is down the unit will be supplied cold feed from

the tanks.

9.2.2. COLD FEED PUMPS AND FEED PREHEATING

The unit receives cold feed from storage tanks. The tanks can be used both for storing feed

as well as finished bitumen. The pumps take feed from the tanks and discharge it through

unit heater for heating to the reaction temperature.

45

BITUMEN FURNACE

It is a natural draft furnace with convection and radiation sections. The convection section

forms rectangular box while radiation zone is cylindrical in shape. The two sections are

having horizontal and vertical feed coils respectively. Pumps supply cold feed to furnace at

temperature of 150-180oC. Furnace has two coil passes. Provision also exists to operate the

furnace as a simple coil pass while operating at low turndown ratio. Feed enters through

convection zone at the top and control valves control flow of each stream. The furnace is

provided with one oil-cum-gas burner at its base. The feed first picks up heat from the flue

gases in the convection section and then it is heated in the radiation zone coils. The feed is

heated up to 230oC. The two passes join together at the outlet of furnace and are routed to

reactors in two parallel streams.

9.2.3. REACTORS

Compressed air at 80oC is supplied through spargers provided at the reactor bottom.

Oxidation of the residue is carried out at a temperature of about 240-260oC. In the vapour

space there is steam injection facility to avoid after burning of gases coming from the

reactor. Oxygen content in the reactor overhead gas is not allowed to exceed 5%.

9.2.4. FINISHED BITUMEN CIRCUIT

Finished bitumen from the reactors at 240-260oC is pumped in parallel streams and cooled

in two groups of air-coolers up to 170-200oC. Cooled bitumen is routed to storage tanks

through two separate rundown lines.

46

9.2.5. REACTOR OVERHEAD SYSTEM

From the top of the reactors the hydrocarbon vapours, steam and unreacted air at about

220-240oC go to air coolers where they are cooled to 170

oC. The combined vapour-liquid

mixture from the cooler goes to oxidation gas separators, which operate in parallel.

9.2.6. OXIDATION GAS SEPARATORS

The vapour-liquid mixture from air coolers separate here. Separator bottom at around

170oC is periodically pumped through another cooler. Oil is cooled to 80

oC and sent to

FFS tanks/IFO tanks. The uncondensed gas at 170oC passes through demister pads in the

overhead lines. Liquid separated is drained to OWS. The two gas streams join a common

header and go to the incinerator for final combustion.

INCINERATOR

Overhead gases from separator enter the incinerator from the top where they are burnt at a

temperature of 700-1000oC.

47

10. AMINE RECOVERY UNIT (ARU)

10.1. INRODUCTION

Diethanol amine almost saturated with H2S (rich amine) and received at battery limit from

DHDS, FCC, OHCU unit is processed in unit ARU to separate out H2S and amine solution

(lean amine), which is obtained as bottom product from ARU. H2S and other light

components present in the rich amine are separated out as overhead product.


10.2.1. AMINE FLASH DRUM

The rich amine containing absorbed H2S and CO2 from amine absorber and LPG MEROX

units enter the amine flash column at a pressure of about 5 kg/cm2 and temperature of

55oC. Height of flash column is approximately 11.4 in. and dia. = 500 mm at the top and

1600 mm at the bottom of section. Top section is packed with raschig rings. Rich amine at

5 kg/cm2 is flashed into the column to a pressure of 2.8 kg/cm

2. The bottom section

contains four single pass valve trays. Because of flashing, hydrocarbons in the amine get

liberated, thereby reducing the quantity of hydrocarbons going with sour gas to sulphur

unit, which spoils the catalyst.

The liberated hydrocarbons from the top of the column enter the flare header

through a pressure control valve. The column top pressure is maintained at 2.8 kg/cm2.

When column pressure rises, a valve opens and lets off the liberated hydrocarbons to flare

and when pressure drops pressure valve opens for fuel gas (FG) to enter the column.

48

A slipstream reflux of lean amine solution is fed into the top of column above the packing

to reabsorb any H2S liberated during flashing from the bottom of the flash column.

REGENERATION

In amine regeneration the rich DEA is stripped of its absorbed sour gases H2S and CO2

using steam. So regenerated amine can be reused in absorber. Amine reboiler is heated by

LP steam. Steam strips off the absorbed H2S and CO2 present in the DEA solution.

Reactions involved are:

R2NH3S R2NH + H2S where R = CH3CH2OH

The top temperature of regenerator is about 105oC and middle temperature is about 115

oC.

Pressure is nearly 0.5 kg/cm2. The liberated sour gases leave the regenerator from the top

and enter the overhead condenser where gases are cooled and steam is condensed to 45oC.

Sour gas from the reflux drum top goes to the sulphur recovery plant by the production of

Sulphur.

Reboiler has two compartments separated by a baffle. By heating the compartment

DEA overflow above the baffles to the other compartments from where it flows to

regenerator by gravity.

The excess pressure drop is due to foaming of amine inside the column. So,

antifoaming agent dosing is needed. Foaming is caused due to contamination of amine

solution by condensed light hydrocarbons, fine suspended solids or surface-active agents.

A portion of cold lean amine is passed through charcoal filter to remove iron impurities

due to corrosion and to a sand filter to absorb charcoal and sent to suction line of lean

amine pump.

49

11. SULFUR RECOVERY UNIT (SRU)

11.1. INTRODUCTION

The unit consists of three identical units A, B and C. One of them is kept standby. The

process design is in accordance with common practice to recover elemental sulfur known

as the Clause process, which is further improved by Super Clause process. Each unit

consists of a thermal stage, in which H2S is partially burnt with air, followed by two

catalytic stages. A catalytic incinerator for incineration of all gases has been incorporated

in order to prevent pollution of the atmosphere.


The sulfur recovery process applied in the present design, which is known as the Clause

process, is based upon the combustion of H2S with a ratio controlled flow of air which is

maintained automatically in sufficient quantity to evolve the complete oxidation of all

hydrocarbons and ammonia present in the sour gas feed and to burn one third of the

hydrogen sulfide to sulfur dioxide and water.

H2S + 3/2 O2 SO2 + H2O + Heat

The major percentage of the residual H2S combines with the SO2 to form Sulphur,

according to the following equilibrium reaction

2 H2S + SO2 3S + 2H2O + Heat

Sulphur is formed in vapour phase in the main combustion chamber.

50

The primary function of the waste heat boiler is to remove the major portion of heat

involved in the combustion chamber. The secondary function of waste heat boiler is to

condense the sulphur, which is drained to a sulphur pit. At this stage 60% of the sulphur

present in the sour gas feed is removed. The third function of the waste heat boiler is to

utilize the heat liberated there to produce LP steam (4 kg/cm2).

The process gas leaving the waste heat boiler still contains a considerable part of

H2S and SO2. Therefore, the essential function of the following equipment is to shift the

equilibrium by adopting a low reactor temperature thus removing the sulphur as soon as it

is formed.

Conversion to sulphur is reached by a catalytic process in two subsequent reactors

containing a special synthetic alumina catalyst.

Before entering the first reactor, the process gas flow is heated to an optimum temperature

by means of a line burner, with mixing chamber, in order to achieve a high conversion. In

the line burner mixing chamber the process gas is mixed with the hot flue gas obtained by

burning fuel gas with air.

In the first reactor the reaction between the H2S and SO2 recommences until

equilibrium is reached. The effluent gas from the first reactor passes to the first sulphur

condenser where at this stage approximately 29% of the sulphur present in the sour gas

feed is condensed and drained to the sulphur pit. The total sulphur recovery after the first

reactor stage is 89% of the sulphur present in the sour gas feed. In order to achieve a figure

of 94% sulphur recovery the sour gas is subjected to one more stage. The process gas flow

is once again subjected to preheating by means of a second line burner then passed to a

second reactor and the sulphur condensed in a second condenser accomplish a total sulphur

recovery of 94%. A sulphur coalescer is installed downstream the last sulphur condenser to

separate entrained sulphur mist.

51

The heat released by the subsequent cooling of gas and condensation of sulphur in waste

heat boiler and, sulphur condensers results in the production of low-pressure steam.

12. OIL MOVEMENT AND STORAGE I

12.1. STORAGE SECTION

The tank farm accommodates tanks for intermediate and finished products in addition to

crude oil. There are three main types of tanks:

(i) Fixed roof

(ii) Floating roof

(iii)Floating cum fixed roof

12.1.1. FIXED ROOF TANKS

Fixed roof tanks are used for storing products of low volatility. These tanks are vessels

made of vertical cylinder plates with cone roofs fixed over plates – supported by internal

truss. Depending upon the service the tanks are provided with accessories. Products like

SK, HSD, LDO and RCO are stored in fixed roof tanks.

12.1.2. FLOATING ROOF TANK

Floating roof tanks are used for storing products with high vapour pressure. The roof

resting on liquid contributes to the minimization of vapour space between liquid and roof

bringing are increased operational safety, and minimum evapouration loss. The floating

roof is provided with annular pontoon around the periphery.

Foam type seal is used to seal off the clearance between the ring of the roof and

tank shell. The rim is supported, when it is not afloat, by a number of tubular legs. Each

52

leg can freely move within a sleeve attached to the roof, the leg being fixed at one of the

two points by a securing pin. One fixing point corresponds to the minimum height of the

tank in the lowest working position, the other supports the roof giving sufficient clearance

between the tank roof and floor for maintenance work to be carried out. Bleeder vents in

the roof allow air to escape when an empty or near empty tank is being filled and before

the roof is afloat.

12.1.3. FLOATING CUM FIXED ROOF TANKS

Theses tanks have advantages of both floating and fixed roof and are very much suited to

volatile products in which entry of rainwater is not allowed. These tanks are used for

storing ATF, Reformer Naphtha etc. These tanks are having pan type floating roof with

drainage system. They have a fixed roof having opening to permit venting of seals in the

floating deck. These tanks are provided with inverted cone type bottom so that

accumulated water can be taken out from the tanks.

12.2. DISPATCH SECTION

Dispatch of products is of most important functions of OM&S section. For efficient

performance of different modes of dispatch a close co-ordination between Refinery,

Marketing, Pipeline, Railway, Central Excise and other agencies is essential.

Any petroleum product is ready for dispatch only after the laboratory certifies its quality.

In Mathura Refinery, the principal mode of dispatch of finished product is:

(i) By Rail

(ii) By Pipeline

(iii)By Road (OM&S-II)

53

12.2.1. PRODUCT DISPATCH BY RAIL

In Mathura Refinery following products are dispatched by railway tank wagons:

a. Motor Spirit

b. Kerosene

c. ATF

d. HSD

e. LDO

f. Furnace oil

g. Naptha

h. Heavy petroleum stock

i. LPG

j. Bitumen

The facilities for loading LPG and Bitumen wagons are provided in OM&S-II area.

Different types of tank wagons are supplied by railway for different products. These are

three gantries for railway dispatch purposes.

12.2.2. PRODUCT DISPATCH BY PIPELINE

In Mathura Refinery, products are also dispatched by Mathura – Jalandhar Pipeline

(MJPL). In this section, the following four products are dispatched through pipeline:

(a) Motor Spirit (Gasoline)

(b) Superior Kerosene

(c) High Speed Diesel

(d) Aviation Turbine Fuel

54

The four products are supplied to MJPL section from products storage tanks through

pumps. In this section MS/SK/HSD are filtered in one filter and ATF is filtered in another

filter. After filtration the products are pumped to the pipeline to Delhi Station and to other

stations further. Here products are dispatched at a pressure of about 60 kg/cm2.

13. OIL MOVEMENT AND STORAGE II

The oil movement and storage – II unit consists of the following:

Bitumen Drum Filling

LPG Section

Effluent Treatment Plant (ETP)

13.1. BITUMEN DRUM FILLING SECTION

In this section pumps from storage tanks to the supply line to heat exchangers pump the

bitumen. There are filling devices having the capacity of filling 2000 drums a day. The hot

molten bitumen at temperature of about 1050 C is filled in the drums. The capacity of each

drum is 160 kg of bitumen. The filling devices have many facilities like filling weight

indicator valve, steam supply facility. This is an automatic device. The empty drums and

filled drums are transferred to the filling device and other place in section by the roller-

conveyer. Loading the railway wagons dispatches these filled drums. The drums are kept at

yards for 48 hrs for cooling the hot bitumen. On the other, the tankers dispatch bitumen by

road. The plant is semi-automatic, approximately.

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13.2. LPG SECTION

Six Horton spheres each with a capacity of 750 m3 are provided for LPG storage. Of these

three spheres are for storing SR-LPG and other three are for CR-LPG storage. Inter

connections exists between all the six Horton’s spheres to maintain pressure and to enable

storage of CR-LPG in SP-LPG spheres and vice-versa. Methyl Mercaptans are mixed in

LPG for safety to make it full of order.

13.2.1. LPG BOTTLING PLANT

It is semi-automatic bottling plant for bottling LPG. Empty cylinders come via trucks, are

unloaded and mounted over horizontally moving conveyor belt. The belts carry the

cylinders through a set of pneumatic and steam cleaner. The cylinders are then mounted

automatically on a rotating where LPG (calculated amount per cylinder) is pumped into

cylinders. The cylinders are then immersed into the water bath to check against any kind of

leakage of LPG from the cylinders. After the normal cylinders are fitted with plastic cap

and seal the operator has to perform the job of checking the cylinders.

13.2.2. BULK LOADING

This facility is provided for dispatching 97,000 MTPA of LPG by road and rail transport.

13.2.2.1. BULK LOADING BY ROAD

There are four filling points, each having a weight bridge of 30 MT capacity with dial type

seal flexible basis are connected with filling and vapour return lines. A flow meter is

provided on the main filling head.

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13.2.2.2. BULK LOADING BY RAIL

There are five loading points with weight bridge of 50 MT capacity each per simultaneous

loading six rail tankers each filling points per arrangement, similar to that described for

bulk dispatch by road.

LPG is dispatched by following two methods:

Bulk dispatch by road

Bulk dispatch by railway

13.2.3. CHARACTERISTICS OF LPG

Constituentsare mainly butane, propane and unsaturated compounds such as propylene and

butylenes. Product has typical vapour pressure of 7-8 kg/cm2 at 38C and density 0.54-0.55

g/ml, i.e., lighter than water (0.5 times) but 0.5 to 2 times heavier than air. LPG containers

must not be completely filled with liquid and adequate vapour space must be left. As more

LPG is added to the cylinder, the liquid level raises leading to compression and

consequently condensation of vapour to liquid. This condensation generates the heat

resulting in increased pressure. If there is no vapour space the liquid expands and excess

pressure is exerted on containers.

13.3. EFFLUENT TREATMENT PLANT (ETP)

The main objectives of ETP are:

Recovery of Oil

Reduction of BOD

Removal/recovery of suspended solids and other chemical constituents like phenol,

sulphides, etc.

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Wastewater collection system of Mathura Refinery consists of:

Industrial Sewer (IS): In this sewer, processed oily water from units, equipments,

sample points, pump house drains, electric desalter drains, loading gantries, tank

drains, etc. comes.

Salty Waste Water Sewer (CS): In this sewer water from crude tanks and crude

booster pump house drain comes.

Storm Water Sewer (SS): In this, the sewer rain water from tank farm dyed area

comes.

Domestic Sewer (DS): In this, the sanitary sewage from toilets and laboratories

provided in the refinery comes.

Caustic bearing water: Caustic bearing wastewaters from MEROX, VBU and

FCC units come.

13.3.1. TREATMENT PRINCIPLE

Wastewater includes three steps:

Physical treatment

Biological treatment

Chemical treatment

The wastewater streams emanating from different places in the refinery are different in

their characteristics and need different types of treatment. Wastewater from petroleum

refinery complex mainly emanates from process units where crude is distilled by direct

steam. Steam condenses along with petroleum products in coolers and condensers and

forms contaminated water from process unit areas. Rainwater drained from tank farms,

offside areas etc., during rainy season as well as caustic bearing wastes and blow down

from cooling towers also contributes to contaminated effluents arising from refinery. The

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pollutant characteristics of waste water from refinery are basically those of oil content,

suspended solids, spent caustic, sulfides, water soluble organics (phenol) etc.

13.3.1.1. PHYSICAL TREATMENT

In this treatment, physical process in AVI separators separate suspended solids and free

oils. Here the velocity of water is slowed down considerably. At such low velocities solids

settles at the bottom and free oil floats on the water surface. The oil is then skimmed off by

scrapper and sent to slop tanks. After drain of water from tank and heating to 700 C, slop

oil will be pumped to tanks in IFO, where from it will be processed in units with crude.

In the equalizer basin, at inlet, treated water from chemical treatment section also comes

and joins with water from API outlet. Here both hydraulic as well as organic loads of both

streams are absorbed and equalized. Oil skimming facility is provided here to remove free

float oil. Wastewater from here goes to single stage high rate trickling filter. Oily sludge

from oil separators will be pumped to oily lagoons. After removing supernatant, sludge

will be removed manually and disposed off.

13.3.1.2. BIOLOGICAL TREATMENT

Naturally occurring bacteria eat away or oxidize impurities causing reduction of sulphides,

phenols, BOD/COD and oil using proper aerator. The excess and dead bacterium is

periodically removed from the system. Biological treatment takes place in two steps:

Trickling Filters: Water is sprayed on a stone bed using as trickle jet. Aeration is

from bottom of stone upwards due to temp difference of water and ambient air. Bacteria

grow on stone surface as film. These are washed out periodically after decaying and fresh

bacteria grow again. After the filter is put in operation, the surface of media becomes

coated with zoogles (a viscous jelly like substance) and other biots. The film of zoogles

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absorbs and utilities suspended colloidal and dissolve organic matter from waste water.

After the film grows to a limit, the liquid washes off the media and a new lime layer will

start to grow. This is called sloughing.

Activated Sludge Treatment (Aeration Tanks): The process basically consists of

continuously mixing of waste water and activation by motor operated aerators. Here

decomposition takes place. The mixed liquor is then sent to the final clarifier where

bacteria mass is separated from water and bio-sludge is recycled. The metabolic reactions

are:

Food + Microbes + Nutrients + O2 New cells + CO2 + H2O + NO2 + Energy.

13.3.1.3. CHEMICAL TREATMENT

Chemical treatment is required for caustic as it has high concentration of sulphides that

cannot be removed by biological or physical treatment plant. Spent caustic from caustic

storage tank is first sent to PH tank and then it is further sent to the reactor tank where

H2O2 dose is given by using dosing pump at the rate of 60-70 lit/day. Whole reaction

mixture is sent to flocculation tank. Then floe formed out of chemical reaction is settled at

clarifier cum thickener (CCT), where from the clear water goes to equalizer basin inlet.

The settled/thickened chemical sludge is withdrawn at frequent interval in a sump and

pumped to sludge drying beds. Chemical sludge after drying beds will be disposed off

manually.

Functions of Individual Equipment for Waste Water Treatment

API Separators: Physically separate free oil, sludge and solids.

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Equalization Ponds: Helps in supplying consistent quality and quantity of wastewater to

biological section.

Trickling filters: Helps in reducing BOD/COD, sulphides, phenols and oils in contact

with algae grown on stone media.

Aeration tanks: Helps in further reduction of above mentioned pollutants in contact with

bacteria and continuous aeration.

Final Clarifier: Retaining biological sludge from recycle.

Slop Sumps: Receiving API, clarifier, IS and guard basin slop for pumping to slop oil

tanks.

Sludge Sumps: Receiving sludge from API Separator bottom and pumping to oily sludge

lagoon.

Drying Beds: Drying of biological and chemical sludge.

Guard Basin: Storage during peak flow situation.

Polishing Ponds: provide resistance time for finishing touch with natural aeration.

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14. QUALITY CONTROL LABORATORY

Quality control is the primary function of the laboratory, assisting the Refinery’s

Production Units by providing them with quality control data on the product streams at

regular intervals. Apart from routine tests, the laboratory also handles investigation

problems, analysis of process chemicals and water analysis. It is responsible for

certification of the finished products produced and dispatched by Mathura Refinery.

Mathura Refinery QC Laboratory has five main sections:

1. Process Control Laboratory.

2. Finished Product Laboratory.

3. Analytical and Development Laboratory.

4. ATF Laboratory.

5. Pollution Control Laboratory.

14.1. PROCESS CONTROL LABORATORY

In this laboratory routine testing is carried out round the clock in shift. Samples from

production units, finished and intermediate products, cooling water and boiler water from

Thermal Power Station are collected at regular intervals, tested and reported to the

concerned departments through SAP. Thus this section assists the production department in

maintaining the desirable quality of the petroleum products at different stages of refining

and smooth running of different plants.

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14.2. FINISHED PRODUCT LABORATORY

In Finished Product Laboratory, samples from finished product tanks are tested as per

specified methods and certified, if the test results meet the specifications. Some important

tests of intermediate products are also carried out in this section. CFR Research Octane

Number, Motor Octane Number and Cetane Number tests are also performed in this

section. This laboratory works in General Shift only.

14.3. ANALYTICAL AND DEVELOPMENT LABORATORY

In this laboratory both intermediate and finished product samples are tested using modern

equipments like Gas Chromatograph, Spectrophotometer, NCS Apparatus etc. TBP

Distillation of crude oil samples are also carried out in this section. It works in General

Shift.

14.4. ATF LABORATORY

Tests related to Aviation Turbine Fuel are carried out in this laboratory in General Shift.

On the basis of these test results a certificate is issued before dispatch of the material. The

laboratory is equipped with modern test equipments like JFTOT, MSEP, BOCLE etc.

14.5. POLLUTION CONTROL LABORATORY

The rapid growth of industry in our country in recent years has created awareness in the

mind of public regarding environmental pollution and ecological balance. In order to

monitor pollutants and to advice the remedial measures, a pollution control cell has been

set up in Mathura Refinery. In Pollution Control Laboratory, samples from ETP, Guard

Ponds, Sewage Treatment Plant, Drinking Water Treatment Plant etc are tested on regular

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basis and reported to the concerned department for remedial action, if necessary. Levels of

Air Pollution inside Refinery at different locations are also monitor regularly.

Phenol content of effluent water

COD/BOD of effluent water

Oil content of effluent water

Sulphur content of effluent water

Turbidity of effluent water

14.6. DESCRIPTION OF TESTS

14.6.1. CLOUD POINT

Cloud point is the temperature at which a cloud or haze of wax crystals appears at the

bottom of the test jar when the oil is cooled under prescribed conditions, expressed as a

multiple of 1°C.

SIGNIFICANCE

The cloud point of a petroleum product is an index of the lowest temperature of its utility

for certain application.

OUTLINE OF METHOD

The sample is cooled at a specified rate and examined periodically. The temperature at

which haziness is first observed at the bottom of the test jar is noted and recorded as the

cloud point of the material.

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14.6.2. COLD TEST (FREEZING POINT)

This method describes a procedure for the detection of separated solids in aviation turbine

fuels at any temperature likely to be encountered during flight or on the ground.

SIGNIFICANCE

It is the lowest temperature at which aviation fuels remain free of solid hydrocarbon

crystals, which may restrict the flow of fuel, if present, through filters in an aircraft fuel

system. The temperature of the fuel in the aircraft tank normally falls during flight

depending on speed, altitude and flight duration. The freezing point of the fuel must always

be lower than the minimum operational tank temperature. It is a key safety parameter in the

specification and use of fuels.

OUTLINE OF THE METHOD

The sample is cooled with stirring until crystals of hydrocarbon appear. The sample is

allowed to warm up and the temperature at which the crystals disappear is noted.

14.6.3. CETANE NUMBER

This test method determines the rating of diesel fuel oil in terms of an arbitrary scale of

cetane number using a standard single cylinder, four stroke cycle, variable compression

ratio, indirect injected diesel engine. Cetane number is a measure of the ignition

performance of a diesel fuel oil obtained by comparing it to reference fuels in a

standardized engine test.

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SIGNIFICANCE

Cetane number of a diesel fuel provides a measure of the ignition quality of the fuel in

compression ignition engine.


The cetane number of a diesel fuel oil is determined by comparing its combustion

characteristics in a test engine with those for blends of reference fuels of known cetane

number under standard operating conditions. This is accomplished using the bracketing

hand-wheel procedure which varies the compression ratio for the sample and each of two

bracketing reference fuels to obtain a specific ignition delay permitting interpolation of

cetane number in terms of hand-wheel reading.

14.6.4. DISTILLATION

This test is intended for the determination of distillation characteristics of crude oil and

petroleum products.

(i) DISTILLATION AT ATMOSPHERIC PRESSURE

This test is applicable for determination of distillation characteristics of motor gasoline,

ATF, Kerosene, Naphthas, Gas Oils and similar petroleum products. The test method

covers both manual and automatic instruments.


100 ml of sample is distilled in a specified distillation flask under prescribed conditions

and observation of temperature at the instant the first drop of condensate falls from the

lower end of the condensate tube, systematic observation of temperature against volume of

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condensate recovered at specified intervals and the maximum temperature observed during

the test are recorded. Observed thermometer readings are to be corrected to normal

atmospheric pressure by the Sydney Young equation as given below:

Cc = 0.00012 (760 – P) x (273+tc)

Where,

Cc = Correction to be added algebraically to the observed thermometer reading tc.

P = Prevailing Baromatric Pressure at the time of the test, mmHg.

(ii) DISTILLATION AT REDUCED PRESSURE

The test method covers the determination the boiling range of the petroleum products at

reduced pressure that can be partially or completely vapourized at a maximum liquid

temperature of 400°C. It can be done both manually and by an automatic instrument.


The sample is distilled at an accurately controlled pressure between 1.0 and 50.0 mmHg.

Data are obtained from which the initial boiling point, the final boiling point and a

distillation curve relating volume percent distilled and atmospheric equivalent boiling point

temperature can be prepared.

SIGNIFICANCE

Atmospheric distillation provides an idea about the boiling range of the petroleum product.

Distillation at reduced pressure is used for the determination of the distillation

characteristics of the petroleum products and fractions that may decompose if distilled at

atmospheric pressure. The boiling range is directly related to viscosity, vapour pressure,

heating value, average molecular weight and many other physical and chemical properties.

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TBP distillation provides an estimate of the yields of fractions of various boiling ranges of

a crude oil. These information are required for evaluation of a crude, designing of a

petroleum refinery and day to day plant operations.

14.6.5. DUCTILITY

Ductility of bituminous material is measured as distance in centimeters to which it will

elongate before breaking, when a briquette specimen of the material are pulled apart at a

specified speed and at a specified temperature.

14.6.6. FLASH POINT

It is the lowest temperature at which a material gives so much vapour that, these vapour

when mixed with air, forms an ignitable mixture and gives a momentary flash on

application of a small pilot flame.


The sample is heated in a test cup at a specified rate with continuous stirring. A small test

flame is directed in to the cup at regular intervals with simultaneous interruption of

stirring. The flash point is taken as the lowest temperature at which the application of the

test flame causes the vapour above the sample to ignite momentarily.

SIGNIFICANCE

It is one of a number of properties that must be considered in accessing the overall

flammability hazard of a material. Flash point and fire point have importance in connection

with legal requirements and safety precautions involved in fuel handling and storage.

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14.6.7. GAS CHROMATOGRAPHIC ANALYSIS

GC is one of the most efficient and convenient tools for separation, detection and

quantitative estimation of components present in a complex mixture of volatile and

thermally stable samples. This is an analytical technique of separation based on the

solubility or adsorption/desorption of components between a liquid stationary phase and

mobile gaseous phase.


The sample to be tested is injected through a heated injection system and brought to vapour

form instantaneously, mixed with carrier gas and travels through the column to the

detector. The different components of the sample are separated in the column as they travel

through the column depending upon various properties of the material and the column. The

separated components are detected and subsequently quantified with a variety of detectors

like FID, TCD, ECD, FPD etc. The choice of column and detector are based upon the

nature of the sample.

SIGNIFICANCE

The technique can be used for detection and accurate estimation of components in different

refinery gas and liquid samples.

14.6.8. OCTANE NUMBER (RESEARCH METHOD AND

MOTOR METHOD)

Octane number of the spark ignition engine fuels is volume percent of iso-octane in a blend

with n-heptane that matches the knock intensity of the fuel when compared under specified

conditions. The research octane number is determined by knock testing unit (CFR Engine)

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using the standard operating conditions given in ASTM D 2699. Whereas motor octane

number is determined using the standard operating conditions given in ASTM D 2700.

SIGNIFICANCE

Research octane number in conjunction with motor octane number defines the Antiknock

Index of Automatic Spark Ignition Engine fuels in accordance with specification ASTM D

4812. The antiknock index of a fuel approximates the road octane ratings for many

vehicles.

RON + MON

Antiknock Index (AKI) = ----------------

2

14.6.9. PENETRATION OF BITUMEN

Bitumen samples are normally classified into different grades by their penetration test.

Penetration of bituminous material is distance in 1/10th of a millimeter that a standard

needle will penetrate vertically into a sample of the material under standard conditions of

temperature, load and time.

OUTLINE OF METHOD

The sample is melted at a temperature not more than 90°C above its softening point,

poured into a container, and then air cooled under controlled conditions. The sample then

is conditioned at test temperature (25°C) in a water bath. Penetration is measured with a

penetrometer using a standard needle under specified conditions.

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SIGNIFICANCE

Needle penetration is a measurement of hardness of bitumen. Hardness may have a

significant effect upon other physical properties.

14.6.10. POUR POINT TEST

Pour point is the lowest temperature expressed as a multiple of 3°C at which the oil is

observed to flow when cooled and examined under prescribed conditions.

OUTLINE OF METHOD

After preliminary heating the sample is cooled at a specified rate and examined at intervals

of 3°C for flow characteristics. The lowest temperature at which movement of the sample

is observed is recorded as the pour point.

SIGNIFICANCE

The pour point of a petroleum product is an index of the lowest temperature of its utility

for certain applications.

14.6.11. SMOKE POINT

The maximum flame height in millimeters at which kerosene or other volatile liquid fuels

including aviation turbine fuels will burn without smoking, when determined in the

apparatus and under specified conditions.


The sample is burned in a standard lamp in which it is possible to adjust the flame height

against a background of a graduated millimeter scale. The smoke point is measured by

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raising the wick until a smoky flame is produced and then lowering to the point, where the

smoky tail just disappears. The flame height, measured to the nearest millimeter, is the

smoke point of the sample.

SIGNIFICANCE

The test method provides an indication of the relative smoke producing properties of

kerosene and ATF in a diffusion flame. The smoke point is related to the hydrocarbon type

composition of the fuel. A high smoke point indicates low aromatic content of the fuel.

14.6.12. REID VAPOUR PRESSURE OF

HYDROCARBON LIQUID

This method is for the determination of vapour pressure of volatile non-viscous liquid.


The sample chamber filled with the cold sample is connected to the air chamber of the

apparatus fitted with a pressure gauge. The apparatus is then kept at a temperature of 38°C

and shaken periodically until a constant reading is obtained on the pressure gauge.

Necessary corrections are applied to this reading to get the corrected Reid Vapour Pressure

of the sample.

SIGNIFICANCE

Vapour pressure is critically important for both automotive and aviation gasolines,

affecting starting, warm up, and tendency to vapour lock with high operating temperatures

or high altitudes. Vapour pressure of crude oil is important for its safe transportation,

storage and initial refinery treatments.

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REFERENCES

Dr. Ramprasad, Petroleum Refining Technology

en.wikipedia.org

www.britannica.com

www.iocl.com

www.kbr.com

Guide to Refining from Chevron Oil's website

Behind high gas prices: The refinery crunch

Gary, J.H. and Handwerk, G.E. (1984). Petroleum Refining Technology and Economics

(2nd Edition ed.).

Mathura Refinery Report

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