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About Indian Oil Corporation Limited

Only three decades ago, India looked to the world for help in the quest of oil. Then

slowly the scenario changed. Indian Oil Corporation Limited was incorporated in

September 1964 by amalgamating Indian Refineries Limited with Indian Oil

Company played a leader role in this transformation.

It has following features:

India’s flagship national oil company.

India’s sole representative in the fortune’s prestigious listing of the world’s

500 largest corporations, ranked 191 for the year 2003.

17th largest petroleum company in the world.

Ranks at 325 in the latest forbes’ international listing of “global 500” largest

public companies.

Accounts for

- 53% petroleum products market share

- 42% national refining capacity

- 67% downstream pipeline t’put capacity

Controls 10 of india’s 18 refineries with current combined rated capacity of

49.30 mmtpa. These include subsidiaries viz. CPCL & BRPL.

Owns & operates country’s largest network of cross-country crude oil and

product pipelines of 7,170 km with a combined capacity of 52.75 mmtpa

Well spread marketing infrastructure having

- 21,000 sales points

- 191 bulk storage terminals, installations & depots

- 94 aviation fuel stations

- 83 LPG bottling plants

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Panipat Refinery

1. Introduction:-

Panipat Refinery is the 7th refinery of Indian Oil commissioned in 1998. Referred to,

as country’s technically advanced refinery is situated in the village Baholi in Panipat

District of Haryana. Built at the cost of Rs.3,868 crore, it has an installed capacity of

6.0MMTPA. Backed by global, state-of-the-art technologies from IFP-France, Haldor

Topsoe-Denmark, UNOCAL/UOP-USA, Stone & Webster-USA, and Delta-Hudson-

Canada. The refinery is designed for processing both indigenous and imported crudes.

It receives crude oil through the chaksu-Kamal branch pipeline of the Salaya-Mathura

pipeline Vadinar Gujarat coast to Panipat through a 1339 km long pipeline.

The various products of the refinery are:

01. Liquified Petroleum Gas

02. Naphtha

03. Motor Spirit

04. Aviation Turbine Fuel

05. Mineral Turpentine Oil

06. Superior Kerosene

07. High Speed Diesel

08. Heavy Petroleum Stock

09. Bitumen

10. Sulphur

Around 66% of these products are transported through environment-friendly

pipelines, while both rail and road account for 17% each.

Panipat Refinery meets demands of petroleum products not only of Haryana but also

the entire Northwest Region including Punjab, J&K, Himachal, Chandigarh, Western

U.P. and part of Rajasthan and Delhi.

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Expansion Projects At Panipat Refinery

The project to increase the capacity of Panipat Refinery to 12 MMTPA is already

under implementation, which also takes into account future fuel quality requirements

for 2005. The expansion project is expected to be completed in 2005.

1. PXPTA at Panipat Refinery The project envisages putting up of facilities at Panipat Refinery for separation of

para-xylene from 110-150 degree C Naphtha cut by pooling the feedstock from

Mathura and Panipat Refineries. The project considers facilities like splitter,

reformer, extraction plant, and toluene disproportion plant besides utilities for

production of para-xylene.

Project Cost: Rs. 5104 crore

Expected Commissioning: August 2005

On implementation, the production of para-xylene/PTA will result in import

substitution and value addition besides having an export potential.

2. Panipat Refinery Expansion by 6 MMTPA The proposed facilities comprise an additional CDU of 6 MMTPA along with

Hydrocracker, Delayed Coking Unit, Diesel Hydrotreater, Hydrogen Plant and

Sulphur Recovery Plant.

Project Cost: Rs. 4165 crore

Expected Commissioning: October 2005

To meet the growing deficit of petroleum products in the high demand Northwest

region of India.

Apart from these, there are pipeline projects linked to Panipat refinery expansion.

Indian Oil Corporation Limited (IOCL) at Panipat consists of various units. Among

them major once are:

1. Atmospheric and Vacuum Distillation Unit(AVU)

2. Continuous Catalytic Reformer Unit(CCRU)

3. Visbreaking Unit(VBU)

4. Hydrogen Generation Unit(HGU)

5. Resid Fluidized Catalytic Cracking Unit(RFCCU)

6. Once Through Hydrocracker Unit(HCU)

7. Diesel HydroDeSulphurisation Unit(DHDS)

8. Amine Regeneration Unit(ARU)

9. Sour Water Stripper Unit(SWSU)

10. Bitumen Blowing Unit(BBU)

11. Sulphur Recovery Unit(SRU)

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1.1 Atmospheric and Vacuum Distillation Unit(AVU)

AVU is designed to process 6.0 MMTPA Bombay High and Arab Mix crudes in

blocked out operation. AVU, a fully integrated unit, consists of the following

sections. Crude Distillation Unit, Vacuum Distillation Unit, Naphtha Stabiliser,

Naphtha Splitter, Mineral Turpentine Oil Splitter, LPG Vaporizer, and Treating Units

for Fuel Gas, LPG and Naphtha.

The Unit was mechanically completed in February 1998 and trial operation of the

various sections started in phases starting from May 1998. The Unit was

commissioned on 2nd October 1998.

1.2 Continuous Catalytic Reformer Unit(CCRU)

M/s. IFP, FRANCE licenses the CCRU. This unit is designed to process 0.5 MMTPA

of SR Naphtha from Arab mix and/or Bombay High crude.

This unit consists of Naphtha Hydro Treating, Catalytic Reforming and Catalyst

Circulation and Regeneration Sections.

1.3 Visbreaking Unit(VBU)

Visbreaking Unit (VBU) is designed to process 0.4 MMTPA Arab mix vacuum

residue. This unit is a soaker Visbreaker, which reduces the viscosity of feed at lower

temperature.

The unit was mechanically completed in March 1998 and the trial operation started in

July, 98. The unit was commissioned on 29th October 1998.

1.4 Hydrogen Generation Unit(HGU)

The Hydrogen Generation Unit is designed for the production of 38,000 Metric

Tonne of Hydrogen per year. This unit is licensed by M/s. Haldor Topsoe-Denmark,

which consists of DeSulphurisation, Reforming and CO-conversion sections. With

PSA system of M/s. UOP-Belgium, Hydrogen requirement with purity of 99.9% vol.

produced. These units have been provided to cater the Hydrogen requirement of

Hydrocracker unit as well as Diesel Hydro DeSulphurisation Unit (DHDS). The unit

was mechanically completed in November 1998 and was commissioned on 11th

February 1999.

1.5 Resid Fluidized Catalytic Cracking Unit(RFCC)

This is the first Resid Fluidized Catalytic Cracking Unit (RFCC) unit in the country;

capacity of the unit is 0.7 MMTPA. The unit is licensed by M/s. Stone and Webster

Engineering Corporation Limited-USA. The unit was mechanically completed in

November 1998 and commissioned on 28th January 1999.

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1.6 Once Through Hydrocracker Unit(OHCU)

The capacity of the unit is 1.7 MMTPA and is the highest capacity Hydrocracker Unit

in the country. This unit is designed to convert vacuum gas oil to middle distillates

and FCC feed stock. The unit is licensed by M/s. UNOCAL/UOP-USA and is

designed to operate at a pressure of 162 kg/cm2g and 4200C. It has 3 reactors, each

weighing about 500 Metric Tonne and wall thickness of 256mm to take care of this

high pressure. The unit was mechanically completed in November 1998 and was

commissioned on 26th April’99.

1.7 Diesel HydroDeSulphurisation Unit(DHDS)

DHDS unit has been designed to reduce the sulfur content in High Speed Diesel to

less than 0.05% wt. The process technology for this unit was built within the record

time on LUM SUM TURN key (LSTK) basis by M/s. L&T. The capacity of the unit

is 0.7 MMTPA. The unit was mechanically completed in March’99 and

commissioned on the 12th July.

1.8 Amine Regeneration Unit(ARU)

ARU is designed to process Hydrogen Sulfide rich amine from amine Absorption

units and recover amine after releasing the acid gas to the Sulphur Recovery Unit.

This unit was mechanically completed in February’99 and was commissioned on 6th

March’99.

1.9 Sour Water Stripper Unit(SWSU)

The unit consists of 2 Sour Water Stripping Units, one for the sour water from the

Hydrocracker unit and the other for the sour water from the remaining units. This unit

was mechanically completed in December’98 and was commissioned on 15th

February’99.

1.10 Bitumen Blowing Unit(BBU)

Bitumen Blowing Unit (BBU) has been designed to produce 3 grades of Bitumen,

viz.: 80-100, 60-70 and 30-49 from vacuum residue of high Sulfur Crudes. The

capacity of the unit is 0.5 MMTPA. This unit was mechanically completed in March

1998; trial run of the unit was taken in July 1998 and was commissioned on 12th

December 1998.

1.11 Sulfur Recovery Unit(SRU)

SRU is designed to process Hydrogen Sulfide rich acid gas recover elemental sulfur.

The unit was designed by M/s. EIL for a capacity of 84tonnes per day 96% recovery

efficiency, which has further been revamped to 115 tonnes per day and 99% recovery

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efficiency based on the process technology of M/s. Delta Hudson, Canada. This unit

was mechanically completed in March’99 and was commissioned on 30th March’99.

1.12 Other Facilities :

1.12.1 Offsites

The offsites facilities at Panipat Refinery are spread over an area of 115 acres. There

are 77 Storage tanks having storage capacity of 400,000KL Crude Oil and 830,000KL

of Petroleum products. There are 7 nos. of pump stations, a blending station and

connecting pipelines. There are 7 nos. of LPG Horton Spheres each of 1500KL

capacity. The offsites operation is controlled from the centralized DCS control room

of OM&S. The special feature of offsite operation is that Tank Truck loading (TTL)

and Tank Wagon Loading (TWL) facilities are provided at the Marketing Terminal,

which is adjacent to the refinery. Offsite operation of the Refinery started with the

receiving of the first batch of crude oil in Refinery Storage Tanks on 30th

November’97.

1.12.2 Thermal Power Station & Utilities

The Power and Steam requirement of the refinery is met from the Captive Power

Plant designed and constructed by BHEL in consultation with NTPC. Capacity of the

power plant is:

Steam Turbine Generator – 3 x 25 MW.

Gas Turbine Generator – 30 MW.

Steam boiler – 3 x 160 T/hr.

Heat Recovery Steam Generator: 125 T/hr.

The first boiler was commissioned in May’97 and first TG was commissioned in

August’97.

1.12.3 Nitrogen Plant

Nitrogen is produce in a cryogenic separation plant by air distillation after liquefying

the same. M/s. BHPV constructed the plant on a turnkey basis. The capacity of the

plant is 800 NM3/hr. The plant was commissioned on December’97.

1.12.4 Miscellaneous

One raw water reservoir of capacity 200,000KL Raw water treatment plant of capacity 2100KL/hr. Four chains of DM Water treatment plant Compressed air system with 4 nos. of compressors and 3 nos. air drier. Cooling tower with 5 cells for TPS and 8 cells for process units.

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Atmospheric and Vacuum Unit

1. Introduction

Atmospheric and vacuum unit is considered to be the mother unit of the refinery as it

converts the crude into several products and feed for the other units.

1.1 Sections in the Unit: AVU consists of following sections. .

a) Crude desalting section.

b) Preflash section.

c) Atmospheric Distillation section.

d) Stabiliser section.

e) Naphtha splitter and Caustic wash section.

f) MTO splitter section.

g) Vacuum Distillation section.

h) LPG Amine & caustic wash section.

i) Centralised Sour Fuel gas Amine treatment section.

j) LPG vaporiser section.

1.2 Products Extracted from Cdu/Vdu Main Columns

S.no Short name Long name Cut range º c Usage

1. GAS Fuel gas C1-C2 Internal fuel

2. LPG Liquefied Petroleum Gas C3-C4 Domestic fuel Gas

3. NAP Naphtha C5-120 MS Component

4. HN Heavy Naphtha C5-120 HSD Component

5. KERO Kerosene 140-270 Domestic fuel

6. ATF Aviation Turbine Fuel 140-240 Aeroplanes

7. LGO Light Gas Oil 240/270-320 HSD Component

8. HGO Heavy Gas Oil 320-370 HSD Component

9. VD Vacuum Diesel 370 HSD Component

10. LVGO Light Vacuum gas Oil 370-425 Feed to HCU/FCCU

11. HVGO Heavy Vacuum Gas Oil 425-550 Feed to HCU/FCCU

12. V.SLOP Vacuum Slop 550-560 IFO Component/ feed

to RFCCU

13. VR Vacuum Residue 560+ Bitumen/ VBU feed

1.4 Other Products

1) C5-90 º C cut: Naphtha splitter overhead product for feed to Hydrocarbon unit.

2) 90-120 º cut: Naphtha splitter bottom product for feed to Reformer.

3) MTO: Mineral turpentine oil ex MTO splitter middle.

4) HY. KERO: MTO splitter bottom (BH) product mainly used as a cutter stock

for VB fuel Oil & FFS.

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2. Process Description

SH Steam

Crude Filter Desalter

Furnace

Atmospheric

Column

Unstablised Gasoline

Inter Naphtha

Heavy Naphtha

Kerosene/ATF

Light Gas Oil

Heavy Gas

Oil

SH Steam

Atmospheric Residue

Non-Condensable

Vacuum Residue

Heavy Vacuum

Gas Oil

Light Diesel Oil

Light Vacuum

Gas OilVacuum

Column

Fig. Block Flow Diagram of AVU

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2.1 Feed Supply

Crude oil is stored in eight nos. storage tanks located in offsite area, each tank having

a nominal capacity of 50,000 KL. Booster pumps located in offsite area are taking

suction from one of these tanks and delivering crude to suction of unit feed pumps.

2.2 Feed Pre-Heat Circuit

Crude oil from crude charge pumps is charged to preheat exchanger trains in two

parallel streams. Provision has been kept to inject caustic and demulsifier solution at

suction of crude charge pumps.

Crude oil is heated upto 136-141º c in the first preheat train of heat exchangers

operating in two parallel sections.

2.3 Desalting

The process of desalting consists of three main stages viz. heating, mixing &

separation.

The desalter in an electrostatic coalescer used for purification of crude from sludge,

salts and corrosion inducing salts. Sludge and salts like NACI generally gets

deposited on the tubes of exchangers and thus reduces preheat temperature. Salt if not

removed will cause corrosion in distillation column

These water-soluble impurities are brought along with the residual water content into

the crude oil. Much of the sediment also may be associated with this dispersion of

water. Water drops ordinarily are so small that gravity would require a prohibitively

long time to draw all of the drops to the bottom of a storage tank, even if the tank

were free from convection currents. Moreover this water dispersion, or in other

words, the emulsion received at the Refinery has been ‘aged’ over an extended period

by stabiliser. These stabiliser are molecules or groups of molecules, asphalts, etc. in

the oil that are least similar to the bulk oil (i.e. least similar to the most prevalent oil

molecular species), and therefore subject to less intermolecular force. Being less

attracted to the internal body of the oil, the exceptional material will be rejected to the

interface of the oil water drops. Such rejected surface active materials comprise a

physical barrier that prevents water drops getting close enough to bring about

coalescence. Before the drops can coalesce, therefore the stabiliser film must be

reduced in thickness and tenacity, and ruptured. An effective means for aiding this is

heat. Heat increases the solvency of the bulk oil for the stabiliser, reduces the

viscosity of the oil and decreases the viscosity and cohesion of the film. These effect

though very much beneficial are normally not adequate to permit coalescence.

Furthermore, another important consideration is that the chance of collision among

drops in this space population of drops is relatively few. The limitation of distance

between drops is dealt with by dispersing about 5% of fresh water to the oil. Thus the

water has been increased about 25 times and the distance between drops surfaces

reduced by 10. Even so, the added water is not likely to combine with a satisfactory

portion of the brine particles and coalesce effectively without additional means.

In desalting, the electric field is a powerful tool for overcoming the resistance of

stabilizing films. The collision and coalescence of drops is accomplished by an

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induced dipole attraction between them. That is the electrical charges inherent in each

droplet are separated so that positive charges move to one end of the droplet and

negative charges move to the other end.

As droplets then approach each other, the force between them becomes very great.

The stabilizing films are squeezed between drops and coalescence is rapid. In a 5%

emulsion, drops average about two diameters apart; coalescence proceeds almost

instantaneously. The distance between drops then increases as drops fall due to

gravity. For a 1 percent emulsion, drops are four diameters apart and coalescence

slows. When the emulsion content is 0.1%, drops are eight diameters apart on the

average. The forces of dipole attraction, diminished by a factor of 250, are

insignificant at this distance and the final emulsion content shall depend on this to

about 0.1%.

A two-stage bielectric desalter has been designed for 99% salt removal with an outlet

salt PPM of <0.1% wt. at outlet. It is designed to use stripped sour water for desalting

which is being taken ex stripped sour water unit. Provision to use DM water/service

water is also provided the desalter water vessel is maintained by level indicator

controller. 2nd stage desalting pumps are used for injecting stripped water into crude

line upstream of 2nd stage mixing valve under flow control after heating it with hot

brine from the 1st stage desalter in an exchanger. The 2nd stage aqueous phase is

transferred to 1st stage desalter by pumps under interface level control.

Then the desalted crude is further heated to 180ºc in the 2nd pre-heat train.

2.4 Crude Pre Flashing

Crude oil at 179-180º C enters pre-flash drum where 3-4% wt. of light ends are

removed. The flashed vapor is sent to flash zone of and also provision is there to

route it to Hy. Naphtha section of crude column. Crude after flashing in the preflash

drum is pumped through 3rd preheat train where it gains temperature upto 259-

289ºc.

2.5 Fired Heater

The preheated crude is further heated and partially vaporized in Atmospheric Heater

having eight passes. (Four sections with 6 inches sch. 40 tubes).

The atmospheric heater is a box-type vertical furnace with up firing burners, 8 Nos. of

burners in each section are provided on the floor with FG and FO firing facilities. A

total 32 nos. of burners have been provided in CDU heater. Out of 32 burners, 28

nos. of burners have both FO and FG firing facility and 4 burners, called LP burners

have facility to fire off- gas from VDU column and FG (called support burners).

This heater is having two distinct heating sections i.e.

A) Radiant Section: It houses the burners and forms the combustion chamber or

fire box. Tubes are arranged in a vertical arrangement along the walls of each cell

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with tube arrangement itself forming the cell.

B) Covection Sections: It receives heat from hot flue gases leaving the radiant

section. Tubes are arranged in horizontal bank and positioned above radiant section.

Preheated Crude oil enters the convection section in eight passes. Convection outlet

of each pass again enters the Radiation Zone of furnace. The floor of the furnace is

elevated above grade and the hot air duct supplying combustion air to burners runs

across the length of the furnace.

A return line is provided on fuel oil header to the burners of each furnace to maintain

desired circulation flow to avoid dead end of the header and associated problems i.e.

difference in pressure availability between extreme end burners, congealing of

stagnant portion etc. Shut down valves are also provided on the main fuel gas, IFO

(S) & IFO(R), support burners of LP gas burners respectively. These shutdown

valves shall be activated w.r.t trip logic’s provided.

Peep holes are provided on side walls of the furnace to inspect all radiant section

tubes. 24 Nos. of soot blowers are provided to keep the convection bank clean.

Furnace has total 32 low Nox burners. Each cell has 8 burners along the center line

of the cell. One central burner is for combination fuel gas & hot well off gases firing

while the balance burners are for combination IFO & FG.

Air Pre-Heater Section

To recover the waste heat from fuel gases, two sets of cast and glass air preheaters in

parallel are provided along with two forced draft fans for air and one induced draft

fan for flue gases.

An air bypass damper to bypass APH is provided for bypassing the

combustion air, either partly or fully.

2.6 Crude Distillation Section

The column is provided with 56 trays of which 10 are baffle trays in the stripping

section. In addition 6 nos. of chimney trays are also provided in the column. Feed to

the column is on tray # 10. The vaporised portion of the feed along with the light

ends from the Preflashing Vessel are fractionated on trays above the flash zone to

yield liquid side draw products, pumparounds (circulating refluxes) and overhead

vapor stream.

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

zone of the column at tray no. 10 at 360-370 º C (LS crude)/370-380º C (HS crude).

Hydrocarbon vapours flash in this zone and get liberated. Non flashed liquid moves

down which is largely bottom product, called RCO. Certain degree of over flashing

of crude is desirable for proper stabilisation of RCO and fractionation of gas oil

components. Over flash is achieved by setting up COT at slightly higher value than

actually required. This over flashed material mostly condenses on 11th tray. The

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condensed liquid withdrawn from 11th tray is put back on 10th tray into the column.

Over flash liquid travels down form tray 11 to tray 10. It strips out heavier vapour

components coming up from RCO stock collected at column bottom and which

otherwise could move and cause coloration of gas oil stream. Flow of over flash

liquid could be increased by either increasing COT or condensing more material on

11th tray or by reducing HGO draw off and dropping more HGO components on 11th

tray. However, this will result is less gas oil yield and higher energy consumption

without any advantage. Too large flow of over flash liquid may result in drop in

bottom temperature and lighter bottom product, RCO.

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

1, at approximately 3.5 Kg/Cm2 (g) and 290º C for stripping of RCO. Steam

stripping helps to remove lighter constituents from the bottom product RCO by

reducing their partial pressure and helping them vaporise without requiring

additional heat. Hydrocarbon vapours liberated by flashing move up along with

steam in the column for further mass transfer at trays in upper section.

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

3. Atmospheric Column Outlets

3.1 Over Head Section

The overhead vapours are totally condensed in Crude Overhead Air Condensers and

trim 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 stripper or to ETP. Unstabilised naphtha containing Fuel Gas,

LPG and Naphtha is partially refluxed and partially pumped to the Stabilizer. Reflux

demand is set by column top temperature. The column overhead pressure is

maintained by split range PIC control with FG back up & flare connections.

3.2 Heavy Naphtha Section

Heavy Naphtha is with drawn as side product from tray # 44 to the Side Stripper.

Light ends in Hy. Naphtha are stripped in the Hy. Naphtha Reboiler using LGO as

the hot medium. Stripped vapours from the side stripper are routed to tray # 46 of the

Atmospheric Column. Hy Naphtha under flow control cooled in Hy Naphtha /BFW

Exchangers followed by a trim cooler and sent to storage.

3.3 Kero Section Kero is withdrawn as side product from tray # 31 to the Kero side stripper under

level control. Light ends in Kero are stripped in the Kero Reboiler using HVGO CR

as the hot medium. Stripped vapours from the side stripper are routed to tray # 33 of

the Atmospheric Column. The bottom product is routed to MP Steam Generator

followed by LMP Steam Generator and Crude Preheat exchanger (to reduce vapour

pressure & hence increase available NPSH) before being pumped. The discharge is

routed to crude preheat exchangers and finally cooled in air cooler and trim cooler

before being routed under flow control to storage.

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3.4 Light Gas Oil Section

LGO is withdrawn as side product from tray # 22 to the LGO side Stripper. Light

ends in LGO are stripped using MP steam. Stripped vapours from the side stripper

are routed to tray # 24 of the Atmospheric Column. The bottom product is pumped

through Hy. Naphtha Reboiler, Crude preheat exchangers and finally cooled in

tempered water exchanger , air coolers and trim cooler before being routed to

storage.

3.5 Heavy Gas Oil Section HGO is withdrawn from tray # 15 to the HGO side stripper under level control. Light

ends in HGO are stripped using MP steam. Stripped vapours from the side stripper

are routed to tray # 18 of the Atmospheric Column. The bottom product is routed to

preheat exchanger (to improve NPSH available) before being pumped through

preheat exchangers, tempered water exchanger and coolers before being finally

routed to storage on Flow Control.

3.6 Reduced Crude Stripped RCO drawn from the bottom of is pumped by RCO pumps to the Vacuum

heater of vacuum Distillation Unit on Level control. Single pump will operate during

turndown operation for both AM/BH operations. Starts up lines connect RCO to VR

pump discharge line.

3.7 Circulating Refluxes

In order to maximise heat recovery and balance tower loadings, heat is removed by

way of circulating reflux (or pump arounds) from each of the sections. These pump

arounds are withdrawn and pumped through preheat train for maximum heat

recovery, thus cooling these streams. Duty controllers are provided for removing the

requisite duty. HGO CR is used to reboil the Stabilizer Bottom in the Reboiler. LGO

CR is used for generating LP Steam. For turndown operations single pump will

operate for HN/Kero/LGO/HGO CR pumps.

3.8 Naphtha Stablizer and Caustic Wash Sections

Unstabilised Naphtha from Crude Column overhead is pumped to the Naphtha

Stabilizer after preheating with stabilizer bottoms in the Feed/Bottom exchanger. A

bypass of 03-E-52 has been provided to maintain NSU feed temperature in the range

of 85-90 º C and stabiliser feed temperature about 125- 128 º C. This column has 40

trays with feed entering on the 21st tray. Necessary heat to reboil is provided by

HGO-CR to the Horizontal Thermosyphon Reboiler on Flow control (opposite

acting). Temperature on tray # 3 regulates HGO CR flow through the reboiler.

A) LPG

Stabiliser overhead vapors are condensed in the overhead condenser and then flow

into the reflux drum. Any water present with the overheads and separated in the

Reflux drum and part of Hydrocarbons refluxed. The balance (LPG) is pumped to

Caustic & Amine treating Unit for treatment

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

(located within CDU/VDU unit) to remove H2S before being routed to the Fuel gas

KO Drum and then to the plant Fuel Gas Distribution Header.

B) Stabilized Naphtha

Naphtha from stabiliser bottom after exchanging heat with feed Naphtha is routed to

the Naphtha Splitter. In case naphtha splitter is shutdown, the stabilised naphtha is

cooled and sent to rundown through CRU naphtha caustic wash system.

3.9 Naphtha Splitter Section

In the Naphtha Splitter, stabilized Naphtha is split to C5-65/90º C and 65/90-120/140

ºC cuts as overhead and bottom product respectively. This column has 26 trays with

feed entering on 12th tray. Provision to route feed to tray # 16th and 9th are also

provided.

A) Naphtha Overhead Product The overhead vapour is condensed in Air cooler and the condensed product flows

to the reflux drum from where a part is refluxed back to the column. This

overhead product is further cooled to 40º C before being routed to storage via

Caustic Wash.

B) Naphtha Bottom Product

The bottom product is cooled in air cooler followed by heat exchanger to 40 º C

before being routed to storage via a separate caustic wash on FIC/LIC control.

C) Naphtha Splitter Fired Reboiler (Furnace) The heat for reboiling is provided by a fired heater 03-F-002. The heater can be

fired with FO/FG or combination fuel. Vacuum heater and Naphtha Splitter fired

reboiler share a common Air preheating system. . For better control Coil Outlet

Temperature, the principles of pass balancing is used. This is a vertical cylindrical

Heater having six flows passes. The radiant section is provided with 6” Sch. 40

tubes having two 8” Sch. 40 tubes as last and second last tubes at the outlet of

each pass while the pass while the connection section is provided with 6” Sch. 40

tubes. The radiant section tubes are disposed in a vertical arrangement along the

walls of the combustion chamber.

The heater is provided with 12 forced drafts, low Nox combination fuel fired

burners (fuel oil & Refinery fuel gas). These burners are arranged in a circle and

are fired vertically upward from the floor.

A combined air preheater system containing one cast Air preheater and one Glass Air

preheater alongwith two forced draft fans and one induced draft fan is provided for

both Vacuum Heater and Splitter Reboiler.

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D) Naphtha Caustic Wash Units The Naphtha Splitter overhead Product & the Bottom product are Caustic washed to

remove H2S, phenols and mercaptans in two separate wash facilities.

3.10 MTO Splitter Section Part of Kero/ATF, upstream of the Product Rundown Control Valve is pumped to the

MTO Splitter after exchanging heat with MTO bottom product (Hy. Kero). The

balance heat required is provided by HVGO CR in the Horizontal Thermosyphon

Reboiler on flow control (opposite acting).

The column is designed with 26 trays with feed entering on the 10th tray. Provision to

route the feed to the 8th tray is also provided.

a) MTO Splitter Overheads

The overheads are condensed in a tempered water Exchanger and routed to the Reflux

Drum from where a part of the condensed products is refluxed and the rest pumped

to Kero/ATF rundown line after cooling.

b) MTO Products

This product is drawn from a total draw tray below tray # 19. A part is refluxed and

the balance cooled before being rundown to storage.

c) Heavy KERO

The bottom product is pumped and finally cooled and routed to storage on flow

control. During AM operation this product is blended with Kero/ATF in the rundown

line.

4. Vacuum Distillation Unit

Hot RCO from the atmospheric column bottom at 355/365º C is mixed with slop

recycle from Vacuum Column, heated and partially vaporised in the 8-pass Vacuum

Furnace and introduced to the flash zone of the Vacuum Column . The flash zone

pressure is 57MM. Velocity Steam (MP) is injected into individual passes and

regulated manually. 3-injection points have been provided on each pass. This is to

maintain required velocities in the heater passes and to prevent coking at high coil

outlet temperatures. The heater can be Fuel Gas, Fuel Oil or Combination fuel fired..

This is a twin cell cabin heater provided with eight flow passes. The radiant sections

of 5: sch. 40 tubes having 8” Sch. 40 tubes as last tubes and 6” Sch. 40 as second last

tube at the outlet of each pass while the convection section is provided with 5” Sch.

40 tubes. The radiant section tubes are arranged horizontally along the side walls and

arch of each cell of combustion chamber. The common convection section has

horizontal bank of tubes positioned above the combustion chamber.

The heater consists of 24 forced draft, low Nox combination fuel fired burners (both

fuel oil and refinery fuel gas). Each cell is provided with 12 burners fired vertically

upshot from furnace floor along the centerline of the cell. Convection section is

16

provided with 16 nos. of soot blowers, which are controlled by automatic sequential

control panel from grade level.

A combined air preheating system has been envisaged for Vacuum heater and

Naphtha Splitter Reboiler Furnace for maximum energy recovery.

4.1 Vacuum Column

The vaporised portion entering the flash zone of the column along with stripped light

ends from the column bottoms, rise up in the Vacuum column and is fractionated into

four side stream products in 5 packed sections. The Hydrocarbon vapours are

condensed in the HVGO, LVGO, and Vac. Diesel sections by circulating refluxes to

yield the side draw products.

The column has been provided for achieving low-pressure drop. Random packings

have been provided inside the column with combination bed in the slop (wash)

section. Demister pads have been provided above the wash zone to prevent

asphaltenes carry over and at the top, to minimize carry over of hydrocarbons to the

ejector section. The stripping section is provided with 10 baffle trays.

5. Vacuum Column Outlets

5.1 Vacuum Diesel Vac. Diesel is drawn from the top most packed section along with Circulating Reflux

(CR) and internal Reflux (IR) from Chimney tray below the Bed # 1 IR is returned to

the LVGO section (bed#2. The CR is returned to the top of the Vac. Diesel packing

(Bed#1) after exchanging heat. Higher overhead temperature would lead to high

Hydrocarbon carry over to ejector.

Slop oil from hot well is also joining to the vacuum diesel at rundown. Facility has

also been provided to route hot vac. diesel to DHDS feed

5.2 Light Vacuum Gas Oil This section comprises of two beds # 2, and # 3, for fractionation and heat transfer

respectively. LVGO is drawn along with CR and from Chimney tray # 2. It is

combined with HVGO CR & routed to the HVGO packing bed # 4 through spray

nozzle distributor. CR is returned to the top of the bed # 3 after exchanging heat with

Crude in exchanger. Product goes through crude preheat exchanger before

exchanging heat with tempered water exchanger.

5.3 Heavy Vacuum Gas Oil HVGO is drawn from the Chimney tray # 3 below bed # 4 along with CR and IR by

HVGO pumps. The IR is returned to the wash zone (Bed#5) through spray

distribution nozzles, on flow control to maintain the required irrigation rate of 0.7-0.3

gpm/ft2 on the wash bed. The CR is used to reboil MTO and kero stripper and crude

preheat train exchangers, before being returned to the top of HVGO section on flow

control. HVGO product goes through crude preheat exchangers and TW exchanger

before being routed to storage.

17

5.4 Vacuum Slop

This section is a combination bed with demister pad provided above the wash zone to

prevent asphaltenes carry over. Slop distillate is withdrawn from chimney tray # 4

below bed # 5 along with slop recycle on gravity to to the slop quench vessel. Slop

distillate is drawn from to the slop quench vessel by slop + recycle pumps. Slop

recycle is routed to Vacuum Heater. The slop product and quench is routed through

crude preheat exchanger and MP stream generator and tempered water exchanger. A

part of this stream is routed to the slop quench vessel.

5.5 Vacuum Residue

The liquid portion of the feed drops into the bottom section of the tower and is with

drawn as Vacuum Residue. MP Steam is used for stripping. In view of steam

requirement for BH operation being very low, separate control valves are provided in

parallel for AM and BH operations. The tower bottom temperature is kept at 350º C

to reduce possible cracking during holdup in the tower by quenching with cooled VR.

Quenching is achieved by returning a quench stream to the tower at a temp of 250º C

after heat exchange with crude in preheats train.

Split range Control Valve bypassed during AM operation. During BH operation it

ensures rundown temperature of 120º C. VR is used to generate LP Steam, before

being cooled in TW exchangers and finally sent to storage.

5.6 Overhead System

Vacuum is maintained by a 3-stage ejector system with surface condensers. The

Vacuum column overhead vapours are routed to the 1st stage ejectors. The outlet from

the 1st stage goes directly to the 1st stage inter condenser. Uncondensed vapours from

1st stage inter condenser are routed 2nd stage ejector. The outlet from the 2nd stage

ejector is routed to the 2nd stage inter condenser from where the uncondensed vapours

are sent to the 3rd stage ejector system. The discharge of the 3rd stage goes to the after

condenser.

The condensed portion from the condensers are routed to the hot well from where the

non condensable are sent to the Crude furnace low pressure burners or vented to the

atmosphere. Condensate from the hot well is pumped to the sour water stripper unit or

to WWTP by sour water pumps. Any oil which is carried over along with the steam

condensate is pumped to the Vacuum diesel run down line by slop oil pumps

intermittently after removing any traces of water in the coalescer. Provision has also

been provided to route the hot well slop oil to hot feed line to DHDS as well as to

DHDS feed tank.

18

Continuous Catalytic Reforming Unit

1. Introduction

Catalytic Reforming is a major conversion process that transforms low octane Naphtha feed

stock to high octane reformate (RON : 98) for use as a gasoline blending component

to make lead free petrol (MS). A rich hydrogen gas (about 90% purity) and LPG are

obtained as valuable by- products. The reformer can also be run for production of reformate

rich in benzene, toluene, and xylenes (BTX).

The catalytic reformer at Panipat Refinery uses continuous catalyst regeneration (CCR)

technology under the trade name Octanizing.

2. Process Description In a CCRU, the Naphtha feed after adequate hydrotreatment is passed over a slow moving

bimetallic catalyst bed in a series of adiabatic reactors in presence of hydrogen under low

pressure and high temperature conditions. The catalyst is continuously circulated and

regenerated in a Regenerator. The reformate obtained is then stabilized and routed for

blending into MS pool. The hydrogen rich gases produced in reformer are recycled partly to

reformer and balance to the naphtha hydrotreatment section and Hydrogen unit.

LPG

Reformate

H2 Rich Gas

Fuel Gas

LPG

Absorber

StabliserRecontacting

Drum

Hydrotreater Recycle

Gas Compressor

Hydrotreater

Naphtha

Feed

Seperator Stripper

Reforming

Reactors

Seperator

Purge to

ATU

Recycle Gas

Compressor

H2 Rich Gas

Compressor

Hydrotreated

Naphtha

Storage

Fig. Process Flow Diagram of CCRU

19

At Panipat Refinery, Catalytic Reformer includes following three sections:

1. Naphtha Hydrotreating

2. Catalytic Reforming

3. Catalyst circulation and regeneration

2.1 Naphtha Hydrotreating

The objective of this section is the elimination of the poisons or undesirable compounds

contained in the feed which contaminate the reformer catalyst and inhibit its metallic and

acidic functions.

These poisons are: Sulfur, Nitrogen compounds, Halogens, Oxygen, Water, Metals and the

undesirable compounds are Diolefins, Olefins.

Hydrotreatment is a catalytic process based on IFP's technology involving

HydroDeSulphurisation and hydrodenitrification reactions, which are carried out in a fixed

bed axial reactor in presence of hydrogen. The hydrotreater feed is a mixture of straight run

naphtha, hydrocracker naphtha and vis-breaker naphtha. Recycle H2 is mixed with the feed

prior to its entering the reactor. The major contaminants like S,N, O are converted to H2S,

NH3 or H2O respectively in the hydrotreater reactor. The liquid product from reactor is

then stripped to remove H2S, water, NH3 and light hydrocarbons in a stripper column. The

stripper bottom (Hydro- treated Naphtha) is then directly fed to the Reforming Section or

routed to storage.

2.1.1 Chemical Reactions

All the reactions described below take place on a Nickel-molybdenum catalyst in presence of

hydrogen. Generally hydrogen is consumed during these reactions. Mainly two different

kinds of reactions occur.

Hydrorefining

Hydrogenation

Hydrorefining : Elimination by production of volatile compounds

A. Sulfur (Desulfurisation)

R-SH + H2 RH + H2S

R-S-R + 2 H2 RH + RH + H2S

R-S-S-R + 3 H2 2RH + 2 H2S

B. Oxygen

Oxygen or oxygen compounds modify the acidic function of the reforming catalyst. They

are eliminated by production of water. The oxygen compounds of a straight run are

peroxides and phenols.

OH

+ H2 + H2O

20

Hydrogenation: 1. Olefinic hydrocarbons at high temperature provoke coke deposit on the aromizer (or

reformer) catalyst as well as in the furnaces coils. They are eliminated by transformation into

paraffins.

2. Aromatics hydrogenation occurs as a consequence of temperature and hydrogen partial

pressure.

Role of the catalyst: Cobalt-molybdenum and Nickel molybdenum catalysts are used to promote the

hydrodesulfurization and hydrodenitrification reaction.

Active form of the catalysts is their sulphided states. The active sulfide form is maintained, in

normal operation, by the partial pressure of H2S in the reactor.

Process Variables

a) Temperature

b) Space velocity

c) Hydrogen partial pressure or H2 recycle

d) Quality of the feed

2.1.2 Hydrotreater reaction section

A filter, 08-GN-00-101, to stop gums compounds, and an antipolymerization inhibitor

injection (to eliminate free radicals) are installed to eliminate the problems of fouling

in the pretreater.

The naphtha is introduced by means of pump 08-PA-CF-101 A/B under flow control

from a surge drum. The surge drum 08-VV-00-101 allows a steady feeding of the

unit. The feed is mixed with the recycle gas before being preheated in reactor

feed/effluent exchanger 08-EE-00-101A/B/C/D/E/F, heated up to reaction

temperature in heater 08-FF-00-101 and fed into the catalytic reactor 08-RB-00-101.

Reactor 08-RB-00-101 inlet temperature is controlled by fuel oil or fuel gas rate to

the burners of 08-FF-00-101. Hydrogenation, desulfurization and hydrotreating

reactions are conducted in pretreater reactor 08-RB-00-101.

The reactor feed effluent cooler is cooled down successively in 08-EE-00-101

A/B/C/D/E/F, then air cooler 08-EA-LP-101 and in water cooler 08-EE-00-102. The

make up gas, coming from catalytic reforming section, is fed at 08-EA-LP-101 inlet.

An online water injection is performed in order to wash the chlorides, sulfides and

ammonium salts which may deposit in solid form when the temperature is low.

In the pretreater separator drum 08-VV-00-102, in addition to the water settled, two

hydrocarbons phases are recovered:

* The hydrocarbons vapors

The most part of the hydrocarbons vapor phase represents the recycle gas which is

taken up by hydrotreater recycle compressor 08-KA-RP-101 A/B through compressor

Knock-out drum 08-VV-00-103.The other part of the vapor phase is sent under flow

control to the amine treating unit.

* The hydrocarbons liquids Are withdrawn under flow control reset by 08-VV-00-102 level control and sent to

21

the stripper 08-CC-00-101.

Before feeding 08-CC-00-101, the feed is preheated in 08-00-103 A/B feed/bottom

exchanger, against stripper bottom product.

Hydrotreater - Striping Section

The duty of the stripper is to eliminate from the reformer feed the light ends,

mainly the hydrogen sulfide.

An injection of corrosion inhibitor is performed in 08-CC-00-101 overhead product.

Then the vapors are condensed and cooled down in 08-EA-LP-102 air condenser

and water condenser and collected in 08-VV-00-104 stripper reflux drum.

A gas purge is done from 08-VV-00-104 under pressure control to the amine treating

unit. The condensed hydrocarbons are returned by stripper reflux pump 08-PA-CF-

104 A/B under flow control reset by 08-VV-00-104 reflux drum level control to

the stripper 08-CC-00-101. The decanted sour water is recovered in 08-VV-00-104

boot and can be purged to the sour water treatment.

Stripper bottom product, after cooling in 08-EE-00-103 A/B is sent to the reforming

unit. The heat necessary for stripper reboiling is supplied by 08-FF-00-102 stripper

reboiler, 08-CC-00-101 bottom product is circulated to 08-FF-00-102 by pump 08-

PA-CF-105A/B. Partial vaporization occurs in 08-FF-00-102. Reboiling is controlled

by 08-CC-00-101 sensible tray temperature. Fuel oil or fuel gas can be used for 08-

FF-00-102 firing.

3. Reformer & Regenerator

The objective of the Octanizing process is to produce a high octane number reformate which

is a main component of the gasoline pool and a hydrogen rich gas It includes two sections:

The naphtha catalytic reforming

The catalyst circulation and continuous regeneration

The reforming reactions take place in moving bed catalytic reactors from which the catalyst

is withdrawn, then regenerated and recycled. The catalyst circulation and regeneration are

performed on a continuous basis with full automatic control of all the operations. A high

temperature (in the range of 500 deg. C) is required to promote the chemical reactions, which

improve octane number. Hence the feed is heated up before entering the reactor. Moreover,

some of the desirable reactions are highly endothermic. This leads to splitting of the bulk of

the catalyst into several reactors with intermediate heaters.

The high performance of the Octanizing process is largely owed to low pressure operation

which in conventional fixed bed reactors would lead to very short cycle length. Hence

Octanizing involves continuous catalyst regeneration. Continuous regeneration eliminates

the need of shutdown for regeneration of the fixed bed reformers. It also minimizes the

amount of catalyst in the unit, while allowing high reformate yield and quality.

22

Main Products: There are essentially four primary products from the CCR

Reformer:

High octane reformate stream,

Rich hydrogen gas stream,

Light reformate (benzene cut)

LPG stream (with or without C5)

There is an additional small secondary purge gas stream to fuel gas from the LPG

absorber drum. This is mostly C1, C2 light ends from the cracking reactions.

3.1 Chemical Reactions and Kinetics Naphtha feed to a CCR Reforming unit typically contains C6 to C11 paraffins, naphthenes and

aromatics. The purpose of this reforming process is to produce high octane aromatics

from naphthenes and paraffins either for use as a high octane gasoline blending component

as in this case or as a source of specific aromatic compounds.

Naphthenes convert rapidly and efficiently to aromatics. Paraffin’s do not under go

conversion easily, requiring higher severity conditions and even then conversion is slow

and inefficient.

In this process conversion is achieved by passing the naphtha over a slow moving

bimetallic catalyst bed in adiabatic reactors, in the presence of hydrogen at relatively high

temperatures and low pressure In the CCR process, catalyst is withdrawn from the reaction

section at a fixed rate, regenerated in the continuous catalytic regeneration unit (CCR) and

returned fresh to the reaction section.

The rate of catalyst withdrawal and regeneration ensures a consistently high active catalyst

with a low carbon content and controlled chloride/water content. This maximises yields of

both reformate and H2 rich gas.

CR 201 Catalyst (catalytic reforming catalyst) The main features of CR201 catalyst are

High purity alumina support having strong resistance to attrition.

High selectivity and stability due to platinum associated with other metals

(promoter).

High regenerability matching perfectly with continuous regeneration system.

Reactions:

1. Dehydrogenation of naphthenes The final step in the formation of an aromatic from naphthene is dehydrogenation:

The reaction is rapid and very endothermic. It is promoted by the metal catalyst function

and is favoured by high temp. and low pressure. Naphthenes are obviously the most

desirable feed components because in addition to being easy to promote they produce

by-product hydrogen as well as the aromatic hydrocarbon.

2. Isomerization of paraffins and naphthenes a) Paraffin isomerization occurs readily in reforming reactions. This reaction leads to an

increase in octane when rearranging to the corresponding branched isomer.

23

n-paraffin iso paraffin

b) The isomerization of a cyclopentane to a cyclohexane must occur as the first step in

converting the C5 naphthene to an aromatic.

Alkylcyclopentane Alkylcyclohexane

This isomerization involves ring re-arrangement and the probability of ring opening to form a

paraffin is high.

3. Paraffin dehydrocyclisation Paraffins dehydrocyclisation is the most difficult reforming reaction to promote. It

requires a difficult molecular rearrangement from a paraffin to a naphthene.

+ H2 + 3 H2

This reaction leads to a significant increase in octane number.

3.2 PROCESS DESCRIPTION IN BRIEF

Reaction section

Feed to the catalytic reforming section comes directly from the bottom of the hydrotreater

stripper after feed/bottoms exchange. A chloriding agent and water are injected before the

flow control valve for optimum reforming catalyst performance. After let down through

the feed flow control valve, the naphtha is mixed with recycle hydrogen from 08-KA-CF-

201 in the welded plate exchanger 08-EE-00-201. This is a true counter current exchanger

designed for minimum pressure drop and maximum heat recovery against reactor effluent.

The combined naphtha feed and recycle hydrogen are preheated here against the last

reactor effluent and then are further heated to the required first reactor inlet temperature

in preheater 08-FF-00-201.

In the first reactor 08-RB-00-201, the reactions are predominantly endothermic and

therefore the

reactor effluent requires reheating in the first interheater 08-FF-00-202 to the required

inlet temperature of 08-RB-00-202. The reaction in 08-RB-00-202 are less endothermic

but still require reheating in 008-FF-00-203 before entering 08-RB-00-203. The effluent

from 08-RB-00-203 is cooled in 08-EE-00-201.

24

In the reactor the feed contacts the reforming catalyst which is divided approximately in the

ratio 15/25/60 in three different reactors. In the CCR process the catalyst circulates

continuously:

in the 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 1st reactor.

In the regeneration unit, the catalyst is regenerated by means of an automatic regeneration

loop system. Catalyst circulation is achieved either by gravity flow or by gas lift systems.

Leaving 08-RB-00-203, the effluent after heat exchanging in 08-EE-00-201 against reactor

feed, is cooled by air and water exchange in 08-EA-LP-201 and 08-EE-00-202

respectively before entering the separator 08-VV-201. Gas from the separator goes to recycle

gas compressor 08-KA-CF-201 and a part of the compressed gas is recycled to the reactors.

The remaining gas which constitutes the hydrogen production gas is routed to a

compression and recontacting section to improve hydrogen purity and recover liquid yield.

The separated liquid is pumped by 08-PA-CF-201A/B to be recontacted in the recontacting

section.

Compression and Recontacting section

The hydrogen production gas is routed to the H2 rich gas cooler 08-EE-00-203, the H2

rich gas compressor K.O. drum 08-VV-00-202 and the two stage compressor 08-KA-RP-

202 A/B.

An interstage cooler and knock out drum 08-EE-00-204 and 08-VV-00-203 are provided

between the stages to cool the compressed material and remove the condensed

hydrocarbons. The condensed liquid, on level control of 08-VV-00-202 and 203 is

pressured back to the reactor effluent at inlet of 08-VV-00-201.

The compressed hydrogen production gas is recontacted with the separated liquid from 08-

PA-CF-201 A/B.

The recontacted mixture is then cooled in three stages:

in water cooler 08-EE-00-205 (recontacting drum cooler)

in exchanger 08-EE-00-206 by exchanging heat with 08-VV-00-204 vapour effluent.

in exchanger 08-EE-00-207 by exchanging heat with 08-VV-00-204 liquid effluent.

by refrigeration with chilling medium in exchanger 08-EE-00-208.

Then the stream is fed into 08-VV-00-204 high pressure absorber.

The target temperature is 0 deg C at 25 kg/cm2g in recontacting drum 08-VV-00-204.

The conditions of the final stage separator for the hydrogen production gas are designed

for:

a high recovery of the C3+ contained in the hydrogen,

a high concentration of hydrogen in the hydrogen rich gas product.

The separated liquid in the recontacting drum 08-VV-00-204 after heat up in 08-EE-00-207

is pressured to the LPG recovery and stabilization section under level control.

25

Regeneration loop

Inert gas nitrogen is used as heat and reactant carrier in the catalyst regeneration loop. A

compressor ensures the gas circulation. At the discharge of 08-KA-00-301. The gas is split

into two flows.

The main flow, used in the two combustion zones is preheated in the feed/effluent

exchanger 08-EE-00-301. Electrical heater 08-XY-00-301 allows for a precise adjustment

of the regenerator inlet temperature.

The gas, after preheating the spent catalyst in the top of the regenerator, flows through the

two radial beds.After coke burn off, the reaction heat is recovered in the feed-effluent

exchanger 08-EE-00-301.The secondary flow, used successively for calcination and

oxychlorination is mixed with air in order to reach a concentration of around 4 to 6% of

oxygen, then heated through feed/effluent exchanger 08-EE-00-302 and electrical heater 08-

XY-00-302.

The calcination gas circulates upflow in an axial bed, is collected at the outlet, mixed with a

chlorination agent then circulates upflow through the axial oxychlorination bed.

After heat recovery in the feed effluent exchanger 08-EE-00-302 this gas is mixed with the

main flow. Then there is a mixing with the caustic recycle, the mixed phase is cooled

down in a trim cooler 08-EE-00-303 before entering in the caustic side compartment of the

washing drum.

The regeneration effluent gas is washed by contacting with a caustic solution. The liquid

is injected through a spray nozzle in the line located upstream the trim cooler. Contacting

is performed into a static mixer 08-M-00-303, right after the injection point. Final

cooling is done in the washing drum 08-VV-00-305.

Final washing is done in the washing drum by contacting water on bubble cap trays. The

water has two functions, washing of the gas and cooling. The gas coming out from the

washing drum goes through a dryer 08-LJ-00-301 then through a filter 08-GN-00-303

where the eventual particles are trapped and finally back to the regeneration loop compressor

08-KA-00-301. Pressure is controlled by means of gas purge from washing drum 08-VV-

00-305. The pressure of the regeneration loop is reset by the pressure of the first reactor

26

Visbreaker Unit

1. Introduction

The visbreaker is designed to process 400000 MTPA of Arab mix vacuum residue

from a crude mix of 50:50 Arab heavy and Arab light crudes. The unit consists of a

two pass heater and separation system. The products from the unit are fuel oil,

gasohol, naphtha and fuel gas.

Products

VB Gas 8200 MTPA

VB Naphtha 13600 MTPA

VB Gasohol 44800 MTPA

VB Tar (350 C) 333400 MTPA

2. Process

Visbreaking is essentially a mild thermal cracking operation at mild conditions where

in long chain molecules in heavy feedstocks are broken into short molecules there by

leading to a viscosity reduction of feedstock. During the cracking gas,, naphtha and

gasoil are produced as by products.

SHS

Soaker

AR

Quench

Fractionator

Unstablised

Gasoline

VB Gas Oil

Fig. Block Flow Diagram of VBU

27

2.1 Theory of Visbreaking

Heavy residues are a mixture molecules consisting of an oil phase and an asphaltene

phase in physical equilibrium with each other in colloidal form. During thermal

cracking the long molecules thus depleting the oil phase in the residue. While the

asphaltenes in the feed remain unaffected, additional asphaltenes may be formed by

secondary polymerisation reactions. At a certain and asphaltenes is disturbed and

asphaltenes precipitate. At this stage of conversion the product residue becomes

unstable.

The viscosity reduction of a feedstock increases with increased conversion (yield of

gas and naphtha) upto a certain level, where maximum viscosity reduction is

obtained. Increase in conversion beyond this value leads to decrease in viscosity

reduction. There is a limiting conversion upto which a stable product can be obtained.

Conversion beyond this leads to an unstable product which is undesirable. The

conversion at which viscosity inversion takes place may be different for each

feedstock and needs to be established for each feedstock.

Asphaltenes, aromatic and paraffin content in the feedstock affect the limiting

conversion for a stable product in the following manner:

Higher asphaltenes lead to lower conversion.

Higher aromatics lead to higher conversion.

Higher paraffins lead to lower conversion.

2.3 Types of Visbreaking

A given conversion is visbreaker can be achieved by two ways:

High temp. low residence time cracking: Coil Visbreaking.

Low temp. high residence time cracking : Soaker visbreaking.

In coil visbreaking process the desired cracking is achieved in the furnace at high

temp. and the products of cracking are quenched and distilled in a down stream

fractionator.

In the soaker visbreaking process, the furnace operators at a lower outlet temp. and a

soaker drum is provided at the outlet of the furnace to give adequate residence time to

obtain the desired conversion. The products from soaker drum are quenched and

distilled in the down stream fractionator.

28

3. Process Description

The Arab Mix vacuum residue is received from the offsites feed tank into the unit

feed sugre drum under level control. The feed is pumped by the feed charge pumps

through a set of VB Feed/VB Tar Exchangers (where it exchanges heat with the

fractionator bottom). The preheated feed is then pumped by the feed booster pumps

into the two passes of the VB heater under flow control. The visbreaker heater

provides the necessary heat for heating and cracking reactions of the feed under

controlled conditions. The effluents from the heater enter the soaker drum. A

residence time of about 20 mins. is given in the soaker drum.

The effluents from the soaker are quenched with gasoil to seize cracking reactions.

The quenched effluents enters the main fractionator, where gas and naphtha are with

drawn as overhead product, as side stream and VB Tar as bottom product.

The overheads from the fractionator are condensed and cooled in air condensers and

water coolers. Uncondensed gas is routed to the fuel gas collection header and sent to

the Amine Treating Unit for sulphur removal. a part of the condensed naphtha goes

back to the column as reflux and balance is routed to the naphtha stabiliser under

fractionator bottom level control. The stabiliser operators under total reflux and

stabilised naphtha from stabiliser bottom is sent to Reformer Surge Drum.

The gasoil is drawn from the main fractionator and steam stripped in the gasoil

stripper to meet flash point specification. Gasoil after heat recovery in the GO/Slops

Exchanger is cooled in water coolers and sent to the HSD Storage tanks.

29

Hydrogen Generation Unit

1. Introduction The Panipat Refinery Hydrogen Unit is designed to produce 38,000 MTPA of high

purity (99.99%) hydrogen gas Hydrogen is produced in the unit by Steam Reforming

of Naphtha based on the technology from M/S Haldor Topsoe A/S, Denmark.

The process for hydrogen generation involves the following four major steps.

Sulphur removal from Naphtha.

Steam reforming of Naphtha

Medium and low temperature shift conversions.

Hydrogen purification in a PSA unit.

Catalyst Poisons For maintaining long production cycle of hydrogen, the feed stocks for the unit

consisting of naphtha and process steam shall be free from poisons. The catalysts

used in steam reforming naphtha are highly selective, extremely active and very

sensitive. The poisons in hydrocarbon feed stocks are sulphur, chlorine and

organometallic compounds.

2. Chemical Reactions and Kinetics

2.1 Steam to carbon ratio and carbon formation

The strichiometric requirement of steam per carbon atom for steam reforming and

shift reactions is 2.0, but it is always maintained higher as carbon forming reactions

are promoted under steam reforming conditions.

The severity of the carbon formation depends on:

1. The feed stocks

2. The operating conditions (steam to carbon ratio, pressure and temperature)

3. The type of reformer design.

4. The catalyst loading.

5. The state of catalyst

The carbon deposition occurs due to the following reactions.

CH4 C+2H2 Methane Cracking

CO+H2 C+H2O CO Reduction

2CO C+CO2 CO Disproportionation

In steam naphtha reformer cracking of higher hydrocarbons to carbon can also take

place.

30

The risk of carbon formation by cracking is eliminated in the reformers with pre-

reformer configuration.

2.2 Desulphurization Systems

Desulphurization is the 1st step in producing hydrogen. As the reforming catalysts

used in the hydrogen plants are extremely active and sensitive to poisoning by

sulphur, chloride and organometallic compounds. So the removal of sulphur to

extremely low level is very much desirable. This is achieved by the reaction of

organic sulphur compounds, mercaptans with hydrogen to produce hydrogen

sulphide. This is called hydrogenolysis and is carried out using a sulphided cobalt m

molybdenum oxide catalyst is presence of hydrogen. Basically hydrogenolysis refers

to the addition of hydrogen across a sulphur carbon bond.

Some of typical reactions are shown below.

RSH+H2 RH+H2S 1.

RISR2+2H2 RIH+R2H+H2S 2.

RISSR2+3H2 RIH+R2H+2H2S 3.

C2H5 SH+H2 C2H6+H2S 4.

C6+H5SH+H2 C2H6+H2S 5.

CH3S C2 H5+2H2 C2H6+H2S 6.

C2 H5SS C2H5+3H2 2C2H6+2H2S 7.

C4 H8S+2H2

(Tetra hydrothiophene)

C4H10+H2S 8.

C4 H4S+4H2 (Thiophene) C4H10+H2S 9.

COS+H2 CO+H2S 10.

All the above reactions are exothermic bur because of the very low levels of sulphur

compounds found in most feed stocks any temperature rise observed is usually a

result of olefin saturation.

A hydrogen flow NM3/KG of naphtha is required for the hydrogenation of sulphur

compounds. The hydrogen sulphide produced during hydrogenolysis reactions is

adsorbed in sulphur adsorbers. The hydrogen sulphide produced reacts with zinc

oxide to produce sulphide and water according to the following reactions.

ZnO +H2S ZnS +H2O

The rate of reaction is a function of temperature, pressure and diffusion processes.

Each molecule of hydrogen sulphide must diffuse to the zinc oxide before reacting to

procedure the sulphide ion and water. The water then diffuse away from the reaction

zone, while the sulphide ion diffuse into the interior of the grannuler to replace the

oxide ion. This process continues unit the whole mass of zinc oxide is converted into

zinc sulphide.

31

The steam reforming of hydrocarbons can be described by the following reactions.

Cn Hm + nH2O NCO + (n+m/2) H2 Heat 1.

CH2+H2O CO2+H2+ Heat 2.

RISSR2+3H2 RIH+R2H+2H2S

3.

Reactions (1) and (2) are endothermic while (3) the shift reaction is exothermic. The

reforming reaction is strongly endothermic, so the forward reaction is favored by high

temperature as well as by low pressure while the shift reaction is exothermic and is

favored by low temperature but largely unaffected by changes in pressure.

The purpose of pre-reformer is to convert all the higher hydrocarbons into lower

hydrocarbons such as methane. The steam reforming of naphtha takes place in the

heated high alloy steel (25 Cr 35 NiNbTi) reformer tubes.

The reaction equilibrium is controlled by partial pressure of H2, CO, CO2, CH4 and

H2O. In the shift section most of the carbon monoxide in the reformed gas is reacted

with excess steam to produce additional hydrogen and carbon dioxide. The reactions

are taking place in the medium temperature and low temperature shift converters.

These converters are filled with catalysts, which is in the form of oxides of copper,

zinc and chromium for MT and oxides to copper, zinc and aluminum for LT shift

reactors.

3. Process Description

3.1 Naptha Storage

Hydrogen unit feed is C5-90 cut naphtha from splitter unit (NSU) of atmospheric and

vacuum unit. Light naphtha from hydrocracker unit (OHCU) can also be sent to the

hydrogen unit feed tanks

This naphtha is a routed to the naphtha feed surge drum V-205.

The pressure in V-205 is maintained at 3 KG/CM2G. The pressure in the surge drum

is maintained by continuous purge of nitrogen.

3.2 Feed Naphtha

Naphtha feed pump P-201A/B (sundyne pump) takes suction from naphtha surge

drum and discharge naphtha to the feed system at 36 KG/CM2G, pressure.The feed

flow is controlled by FIC-0101 is cascade with the pressure controller PIC-0306C

maintains a constant pressure in the desulphurization section.

DMDS injection is provided in the down stream of the feed flow controller to

maintain a certain minimum amount of sulphur (more than 2 PPM) in the naphtha

feed to prevent stripping of sulphur from the hydrogenation catalyst during

processing of low sulphur naphtha feed.

The feed naphtha is mixed with recycle hydrogen in the mixing tank

The liquid naphtha mixed with hydrogen is evaporated in the shell side of one of the

naphtha feed vaporization E-214A/B. The temperature of the feed leaving the

vaporizer is about 215C and is controlled by controlling the pressure of saturated HP

32

steam header used for vaporizing the naphtha feed in E-214A/B. The vaporized

naphtha feed is superheated to about 380-400C in the naphtha feed preheater E-215

by exchanging heat with superheated HP steam.

Recycle H2

Light NaphthaHydro-

Desulphurisation

Sulphur

Absorber 1 & 2

Pre-ReformerTubular ReformerMT-Shift

Converter

Pressure Shift

Adsorber

Product H2

Off Gases

3.2 Desulphurization

The desulphurization of feed naphtha takes place in two steps. The first step is

hydrogenation, where all organic sulphur is converted in to hydrogen sulphide (H2S)

in RB-201. The second step is the absorption of H2S, which takes place on ZnO

catalyst in ZnO absorbers RB-202A/B laid in series.

The vapor naphtha and hydrogen mixture enters the RB-201 hydrogenation reactor at

a temperature of 380C. All organic sulphur is converted to H2S in presence of

sulphided Co-Mo oxide catalyst in the reactor. The hydrogenated naphtha with H2S

enters the sulphur absorber RB-202A/B which are operated in series during normal

operation Sample points AP-0354 and AP-0355 are provided between the first and the

second bed of ZnO catalyst in each of the sulphur absorbers for accessing the life of

the catalyst. Both the sulphur absorbers are provided with nozzles for nitrogen

purging.

Mixing Of Process Feed & Process Steam

The desulphurized naphtha feed and hydrogen is mixed with process steam and

heated in pre-reformer preheat coil E-202 located in the flue gas waste heat recovery

section on the tubular reformer.

Fig. Block Flow Diagram of HGU

33

Part of the process steam is sent through the ejector JA-201 to provide a recycle

across the pre-reformer RB-203.

Pre-Reformer

The mixture of gas (the process gas) and steam is heated to approximately 470-490C

in E-202, the pre-reformer feed pre heat coil in the waste heat recovery section of the

tubular reformer FF-201.The recycle of pre-reformed gas is one of the means of

controlling pre-reformer inlet temperature.

Tubular Reformer

The pre-reformed process gas is further preheated to approximately 630C in the

reformer feed preheat coil E-201 before it is routed to the tubular reformer FF-201

through the 14” line. The heat is transferred in E-201 by radiation as well as by

convection from the flue gas coming from the radiation section.

The tubular reformer is a balanced draught furnace containing 150 catalyst tubes,

installed in two separate chambers. Each chamber is provided with 108 nos. of radiant

wall burners. The burners are mounted equidistantly in 6 horizontal rows on the two

walls of each chamber. This arrangement and the large number of burners enables

easy control of the desired temperatures profile along the height of the reformer tubes

and a uniform distribution through out the length of the combustion chambers.

The tubular reformer is a balanced draught furnace containing 150 catalyst tubes,

installed in two separate chambers. Each chamber is provided with 108 nos. of radiant

wall burners. The burners are mounted equidistantly in 6 horizontal rows on the two

walls of each chamber. This arrangement and the large number of burners enables

easy control of the desired temperatures profile along the height of the reformer tubes

and a uniform distribution through out the length of the combustion chambers.

The major part of the fired heat released from the burners is transferred to the

reformer tubes by radiation from the walls and the balance by convection with the

flue gas, while the remaining part (except for heat losses) leaves the combustion

chambers with the flue gas as sensible heat.

The reformer effluent leaves the tubes at a temperature of approximately 930 C The

firing in the tubular reformer can be carried out by their different fuels. The primary

fuel gas is PSA off gas. Secondary fuel is fuel gas and the third fuel is vaporized

naphtha.

FD fan KA-201 delivers the combustion air for the reformer at a pressure of 200MM

WC. The combustion air is preheated in exchanger E-213 to about 42C in seasons of

low ambient temperature with LP steam to prevent sulphur deposition on the glass

tube air preheater E-205 C. Combustion air is preheated up to 510 C in E-205A/B/C

against flue gas in the flue gas waste heat recovery section of reformer

34

Gas Purification Section

Shift Conversion

The process gas from the tubular reformer is cooled in the waste heat boiler E-206 to

about 280 C and is further cooled in the first BFW pre heater E-207 to 205C, the

inlet temperature of the MT shift converter.

MT Shift Converter

The inlet temperature of the MT shift converter shall be 205C. The temperature at

four different levels of the catalyst LK-811 bed is measured by 8 Nos. of

thermocouples TI-0802 to TI-0809. The performance of the catalyst can be monitored

by means of the CO content in the outlet gas from RB-204. During normal operation

the temperature increase across RB-204 shall be about 125-130C.

The process gas is cooled to approximately 205C in the second BFW preheater E-

208.

LT Shift Converter

The inlet temperature of LT shift converter shall be maintained at about 205C.

The performance of the catalyst can be monitored by means of the CO content in the

outlet gas from RB-205The temperatures are measured at four levels of the catalyst

bed with eight thermocouples TI-0816 to TI-0823. During normal operation the

temperature rise in RB-205 shall be around 24 C.

For heating up the shift sections nitrogen recycle system has been installed consisting

of the N2 compressor KA-205, the cooler E-233 and the separator V-231 and the

heater E-232.

The synthesis gas from RB-205 is cooled to 40C (max.) in third BFW preheater E-

209, deaerator reboiler coil E-210, demineralized water heater E-211 and water cooler

E-212. The condensate is separated in V-202 are finally in V-203.

Residue Fluidised Catalytic Cracking Unit 1. Introduction The demand of the petroleum products in the world is shifting more towards light

distillates because of increasing demand of LPG and Gasolene as a result of the

steady growth in private transportation system and shift towards the cooking gas in

the developing countries. The declining market for fuel oil coupled with anticipated

changes in the future crude quality and the shift in product demand in favour of light

distillate placed and additional emphasis on upgrading the bottom of the barrel i.e. the

heavier residues into more and more light distillates.

35

2. Cracking Processes Cracking is a phenomenon by which large oil Molecules are decomposed into

small lower boiling molecules. At the same time certain of these molecules, which

are reactive, combine with one another to give even larger molecules than those

present in the original stock. The more stable molecules leave the system as

cracked gasoline and reactive ones polymerise forming fuel oil and even coke.

Although primary objective in development of the cracking process had been to get

more and more of gasoline, all other oils having boiling ranges intermediate between

fuel oil and gasoline is also produced.

In modern refining industries there are three basic processes for the conversion of

heavy oil into useful products namely thermal cracking, Fluidised catalytic cracking

and hydrocracking.

Catalytic cracking has many advantages over Thermal cracking viz.

1. Catalytic cracking gives more stable products.

2. For corresponding yield and quality of gasoline, catalytic cracking unit

operates under less severe conditions.

3. Catalytic cracking gives high-octane gasoline (viz. 91 octane).

4. It yields less gas viz. Methane, Ethane and Ethylene.

RFCC is an important secondary process unit of the refinery. The Fluidised Catalytic

Cracking Unit catalytically cracks the Vacuum Gas Oils from VDU, Hydrocracker

bottoms & Vacuum Residues to various high-priced Hydrocarbons.

The Hydrocarbon vapours are separated into following products in the fractionation

and Gas concentration section.

1. Fuel Gas

2. L.P.G.

3. Gasoline of High Octane Number.

4. HSD Component

5. Fuel Oil Component.

36

3. Feed and products

3.1 Feed of the unit: The RFCCU design is based on the following three different

feed mixes.

Feed Case 1: 85.7 wt% Hydrocracker Bottoms and

14.3 wt% of the Arabian Mix Vacuum Resid.

Feed Case 2: 100% Neat Hydrocracker Bottoms.

Feed Case 3: 43% arabian Mix Vacuum VGO

57% Bombay High VGO

3.2 Products: In this unit value-added products are obtained

LPG - finished product

LCN - used for MS blend

HCN - used for HSD blend

LCO - used for HSD blend

CLO/DCO - used for HPS blend

TCO - Mixture of HCN & LCO is the FCC unit product

4. Process Description

RFCCU consists of the following section, which operate in an integrated manner.

(a) Catalyst Section

(b) Fractionation Section

(c) Gas Concentration Section &

(d) Energy Recovery Section(CO Incinerator)

37

HP

Receiver

Na

ph

tha

Sp

litte

r

LCN

HCN

De

bu

ten

ise

r

Compressor

HCO

Flue Gas

to Stack

Main

Column

Air

Blowe

r

Reactor

RG-2

RG-1

DCO

O/H

Receiver

LCO

LPG

Str

ipp

er

Pri

ma

ry

Ab

so

rbe

r

Sp

on

ge

Ab

so

rbe

r

Off

Gas

Rich

Oil

Feed

Slurry +

HCO

Fig. Process Flow Diagram of RFCCU

38

4.1 Catalyst 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

fluidised 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.

The catalyst section consists of the reactor and regenerator, which 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-1 across to

the Regenerator standpipe. The partially regenerated catalyst flows up the lift line

and enters the second stage regenerator below the air ring. The hot regenerated

catalyst flows from the second stage regenerator through a lateral to the

withdrawal well. In the withdrawal well, catalysts 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 upto 293/371 deg C in a feed preheater

along with recycle streams enters the base of the riser. In the riser the

combined feed is vaporised and raised to the reactor temperature by the hot catalyst

flowing into the riser from the regenerator. The oil vapours carry the catalyst

upward through the riser. Cracking reactions start immediately as the feed comes into

contact with the hot catalyst. These reactions continue till the oil vapours are

separated from the catalyst in the reactor. Ramshorn Separators and Two cyclones are

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. Total catalyst and hydrocarbon vapours after cracking flow upwards

and pass through Ramshorn separators & Cyclone separators attached to top of

the reactor. Ramshorn separates followed by 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 and after steam stripping to

remove oil vapours from it the catalyst flows from the reactor standpipe to the

Regenerator-1 through a slide valve. In the Regenerator-1, around 60-70% of the

coke is burned and remainder is burned in the second stage regenerator. Oxygen for

burning being supplied by an Air Blower. Air from the Blower is uniformly given to

the regenerators’ bottom through the respective air rings. The heat of combustion

raises the catalyst temperature to more than 700 deg 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 Regenerator-2

through withdrawal well flows into the riser through a slide valve to complete

the catalyst circulation cycle. Catalyst particles in the flue gases leaving both the

39

regenerators are separated at the top of regenerator by two sets of two stage cyclones

in each regenerator. The flue gas ex R-1 regenerator is having rich in CO

concentration and gas ex R-2 regenerator is having rich in Oxygen

concentration. The sensible and chemical heat in flue gas is utilised in Flue gas

cooler to generate high-pressure steam. The flue gas is passed through an orifice

chamber to reduce its pressure very near to atmospheric so that it can be vented

through a stack directly to atmosphere or supplied to CO incinerator at a slight

positive pressure of 2.0-2.1 PSI.

The flue gases are passed through the orifice chamber & regenerator, pressure is

controlled by double disc slide valve installed one at R-2 flue gas and two in series

at R-1 flue gas path. Orifice chamber holds back pressure downstream of double

disc slide valve. By reducing the pressure drop across slide valve, operating life of

slide valve is greatly extended by avoiding sudden acceleration of catalyst bearing

flue gas stream.

4.2 Fractionation Section

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

are fractionated into the following products:

Off Gas

LPG

Light Naphtha (LCN)

Heavy Naphtha (HCN)

Light Cycle Oil (LCO)

Heavy Cycle Oil (HCO) (Recycled to the riser)

Decanted Oil (DO)

HCN & LCO are combined to produce a Total Cycle Oil (TCO) product. 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 filter

and from the filter bottom, the thickened slurry is recycled back to the riser for

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

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

light and heavy cycle oil streams supply heat to feed as well as to Gas Concentration

Unit. Excess heat available from the fractionating column is used to raise high

pressure steam in four steam generators provided, one with Naphtha Splitter Reboiler

and three exchangers with main column bottoms.

Light cycle oil streams after steam stripping are used as gas oil blending components.

The unstabilised gasoline alongwith heavy naphtha and wet gas are sent to Gas

Concentration Unit for further processing. Both heavy naphtha and light cycle oil

being blending components for HSD can be blended in the unit and sent to

product blending station, as a single stream.

40

4.3 Gas Concentration Unit

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

centrifugal compressor and sent to a high-pressure 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 unstabilised gasoline from main column overhead receiver.

Rich gasoline from Absorber bottom is recycled back to the HP receiver.

Condensate recovered from interstage receiver of gas compressor is also routed to

HP receiver. Valuable components from the gas leaving the Primary Absorber are

routed to Sponge absorber to recover hydrocarbon heavier than C1 & C2. The lean

oil is drawn from the FCC main fractionator are recycled back to main fractionator

again after Sponge absorber. Net lean gas from the sponge Absorber is routed to

Fuel Gas System after amine treatment. Rich oil from the Sponge Absorber returns

to the main fractionating column. Rich gasoline from the bottom of HP receiver is

stripped of hydrogen sulphide and lighter ends in stripper column. The stripped

gasoline is further stabilized in the debutaniser removing C3, C4 components from

it as cracked LPG and bottom product routed to Naphtha Splitter where heavy

naphtha from the bottom and light naphtha at the top will come out. Light naphtha

will be blended in MS pool and heavy naphtha in LCO. The combined LCO &

heavy naphtha is called TCO, routed to diesel pool. Both LPG & gasoline are Merox

treated before routing to storage.

4.4 CO Incinerator

The flue gas leaving the first stage regenerator via orifice chamber contains 12%

carbon monoxide, the rest being inerts like nitrogen, steam, carbon dioxide, etc. In

the CO Incinerator, flue gas is burnt with air converting carbon monoxide to carbon

dioxide, thus releasing the heat of combustion of CO in the flue gas cooler. This heat

and heat carried by second stage flue gas as well as sensible heat in flue gas

available at a high temperature is utilised for raising High Pressure Steam.

The flue gas cannot support its own combustion as the gas mixture contains large

proportions of inerts and requires a supplemental fuel to support combustion. The

gas is completely burnt when injected into a stable supplementary oil flame with

sufficient quantity of air. Incineration of the CO in the 1st stage regenerator flue

gas is accomplished at the CO incinerator. Hot CO incinerator effluent combines

with the second stage regenerator flue gas. This combined flue gas passes through

a cooler where the flue gas thermal energy is recovered by generating high

pressure superheated steam. The flue gases are then directed to the stack.

The two Motor operated valves are mounted at the RG-1 flue gas path after orifice

chamber. The one MOV enables diversion of flue gas directly to atmosphere

through the stack, in case CO-incinerator flame failure. At that time the R-2 flue gas

41

will continue to the flue gas cooler. The other MOV is for normal route of flue gas

to the CO Incinerator.

The Co-incinerator consists of two burners with 100% spare with dual firing

provision, both fuel oil & fuel gas. Two forced draft air fans are provided for

meeting the air requirement of flue gas and supplementary oil. Air is supplied in the

CO incinerator in two ducts. One is used for primary air and other is for

secondary air requirement.

The condensate available from drive turbine of air blower and wet gas compressor

together with make up demineralised water as necessary is deaerated for removal of

oxygen in the deaerator provided in this unit. The deaerated water is supplied by

HP BFW & MP BFW pumps to the flue gas cooler as well as steam generators

located in FCC fractionation section, Visbreaker, Atmospheric & Vacuum

Distillation Unit, CCRU and Sulphur Recovery Units.

Feed water enters the economiser section of the flue gas cooler. Then it flushes to

the boiler upper drum making Low pressure Steam and circulates through the

various boiler tubes connecting upper drum & lower drum. The steam generated in

the circuit is collected in the upper drum and steam is effectively separated from the

water by the internals provided in the steam drum. The saturated HP steam

generated in the flue gas cooler alongwith imported saturated steam exchangers from

the upper drum passes into the superheater.

The superheater coils are located between the Co- incinerator and flue gas

cooler. The hot flue gas ex CO-incinerator come in contact first in superheater

zone, then flue gas cooler and lastly the economiser zone before leaving to the stack.

Saturated steam is fed to the inlet header and passes through the superheater coils,

converting saturated steam to superheated steam. The steam then passes through

desuperheater where deaerated water is used for desuperheating. From the

desuperheater steam enters the main HP steam header in the unit, which is fed from

main boiler also.

42

Once Through Hydrocracker Unit

1. Introduction

In Modern refining industry there are three basic processes for the conversion of

heavy oil into useful products namely thermal cracking, fluidized catalytic cracking &

hydrocracking. Catalytic cracking produces large quantity of good quality Naphtha,

however the middle distillates are far from specification. Both thermal & catalytic

cracking units operate at lower pressures and thus have an advantage in capital cost,

metallurgy & engineering. But a particular feature of hydrocraking as compared to its

alternatives is its flexibility with respect to product pattern & its ability to produce

high quality products.

The yield of middle distillates obtained from Hydrocracker is much more than that

obtained from other processes. Also, Hydrocracker does not yield coke or pitches as

by product. The increased demand for environmentally acceptable products forced the

refiners to accept stringent specifications for gasoline & diesel necessitating the use

of hydrocracking technology to limit sulphur & aromatic in petroleum products. No

post treatment is required for the Hydrocracker products.

Process Licensor: UNOCAL/UOP has jointly licensed the hydrocracking technology

having trade name UNICRACKING.

Feed: Three types of VGO’s can be processed in the OHCU with 8000 on stream

hours and 50 % turndown ratio.

Feedstock ‘A’ : Arab mix VGO

Feedstock ‘B’ : Normal VGO (47% Arab mix VGO + 53%Bombay

high VGO)

Feedstock ‘C’ : Bombay high VGO

Product Yields (Wt %)

SR. PRODUCT

No.

1) LPG 1.56

2) Lt. Naphtha 3.75

3) Hy. Naphtha 5.48

4) Kero / ATF 24.92

5) Diesel 24.92

6) Unconverted Oil 40.0

43

2. Hydrocracking Technology

Hydrocracking process is a versatile process for catalytically hydrocracking heavy

petroleum fractions into lighter, more valuable products. Typical feeds to

Hydrocracker are heavy atmospheric & vacuum gas oils and catalytically or thermally

cracked gas oils. These feedstocks are converted to lower molecular weight products,

usually maximising naphtha or middle distillates.

With hydrocracking process sulphur, nitrogen & oxygen are almost completely

removed & olefins are saturated, there by giving products which are a mixture of

essentially pure paraffins, naphthenes & aromatics.

2.1 Process Configuration

Depending upon the feed quality, product mix desired and the capacity of unit,

following processing schemes can be adopted for Hydrocracker.

a) Single stage

b) Two stage

c) Once through (OHCU) hydrocraking unit.

In Panipat Refinery Once through process is used. In once through operation there is

no recycle and fractionation bottom is taken as product or feed for another secondary

unit.

2.2 Hydrocracking Chemistry

A typical hydrocracking reaction is as follows.

C22 H46 + H2 C16H34 + C6H14

Hydrocracking is essentially the acid catalysed carbonium ion reactions of catalytic

cracking coupled with hydrogenation reactions. Hydrocracking catalyst is

bifunctional having acidic sites & metallic sites. The acidic sites are responsible for

cracking reaction whereas hydrogenation/dehydrogenation reaction takes place on

metallic sites. Rate of hydrocracking increases with the mol. wt. of paraffin.

Hydrocracking feedstocks typically contain Sulfur, Nitrogen, metals etc. which are

removed in the hydrotreating reactor. Some of the first reactions to occur in the

Unicracking unit are the hydrotreating reactions. These hydrotreating reactions are

catalyzed by the metal sites on the catalyst and, in general, are more rapid than the

cracking reactions.

The primary hydrotreating reactions are sulfur and nitrogen removal as well as olefin

saturation. The products of these reactions are the corresponding contaminant-free

hydrocarbon, along with H2S and NH3.

44

1) Sulfur Removal: The lighter compounds such as mercaptans and disulfides are

easily converted to H2S.

a. (Mercaptan)

C-C-C-C-SH + H2 C-C-C-C+ H2S

b. (Sulfide)

C-C-S-C-C+2 H2 2 C-C+ H2S

c. (Disulfide)

C-C-S-S-C-C-+3 H2 2 C-C+ 2 H2S

2) Nitrogen removal:

C C-C-C-C-C + NH3

C C

+5 H2 C

C C

N C-C-C-C + NH3

(Pyridine)

3) Oxygen Removal: Organically combined oxygen is removed by hydrogenation of

the carbon hydroxyl bond forming water and the corresponding hydrocarbon.

C C

C C-OH C C

+ H2 + H20

C C C C

C C

(Phenols)

3) Olefin Saturation: Olefin saturation reactions proceed very rapidly and have a

high heat of reaction.

a. (Linear Olefin)

C-C=C-C-C-C + H2 C-C-C-C-C-C (and isomers)

b. (Cyclic Olefins)

C C

C C C C

+ H2

C C C C

C C

45

4) Metals Removal: Removal of metals from the feed normally occurs in plug flow

fashion with respect to the catalyst bed. Typical organic metals native to most

crude oils are nickel and vanadium. Iron can be found concentrated at the top of

catalyst beds as iron sulfides, which are corrosion products. Sodium, calcium and

magnesium are due to contact of the feed with salt water or additives.

5) Aromatic Saturation: Aromatic saturation reactions are the most difficult. The

reactions are influenced by process conditions and are often equilibrium limited.

Unit design parameters would consider the desired degree of saturation for each

specific unit. The saturation reaction is very exothermic.

6) Halides Removal: Organic halides, such as chlorides and bromides, are

decomposed in the reactor. The inorganic ammonium halide salts which are

produced when the reactants are cooled are then dissolved by injecting water into

the reactor effluent, as shown below.

C C

C C-C-C-Cl C C-C-C

+ H2

+HCI

C C C C

C C

HCL + NH3 NH4Cl

Composition of Catalyst:

HC-K

MoO3 = 25 wt%

HC-22

Tungsten Oxide < 30 wt%

Nickel Oxide < 10 wt%

Aluminum Oxide < 10 wt%

silicon Oxide < 30 wt%

Hydrotreating Catalyst (HC-K): This catalyst is used for hydrotreating reactions i.e. to remove

the contaminants form the hydrocracker feed. Thus, these catalysts protect the hydrocracking

catalyst from feed contaminants. The hydrotreating catalyst is nickel molybdenum catalyst with

excellent desulfurization, denitrogenation, and hydrogenation activities.

Hydrocracking Catalyst (HC-22): This catalyst is used for hydrocracking reactions. This is a

Zeolitie catalyst having high cracking activity. Since hydrocracking involves cracking and

hydrogenation (addition of hydrogen) reactions, the catalyst is also bifunctional. The cracking

function is provided by acidic support (silica alumina, zeolite) of the catalyst and the

46

hydrogenation function is provided by the metals of the catalyst. Metals used in HC-22 are Ni &

Tungsten. These selected metals are dispersed on the acidic support of the catalyst.

3. Process Description

OHCU is divided into two major sections.

(i) Reactor Section.

(ii) Fractionator Section.

(iii)

PRT

Make up

Hydrogen

Charge

Pump

Unconverted

Bottoms

Gas Oil

Diesel

Kerosine

Light

Naphtha

LPG

Off Gas

Off GasOff Gas

Off Gas

Heavy

Naphtha

Gas Oil

Recycle

Compressor

Reac

tor

-I

Reac

tor

-III

Reac

tor

-II

Seperator

Flash Drum

Str

ippe

r

Spo

nge

Abs

orbe

r

Pro

duct

Fra

ctio

nato

r

Ker

o

Str

ippe

r

Die

sel

Str

ippe

r

Vac

uum

Colu

mn

DeB

utan

izer

DeE

than

iser

3.1 Reactor Section

Fresh feed is received in the unit as cold VGO from N2 blanketed storage tankages (

80 oC). Feed is filtered through an Automatic Backwash type filter in which particles

up to the size of 25 microns are removed. Filtered feed then goes to Feed Surge Drum

from where it is pumped by High-pressure Centrifugal pump to the Reactor Effluent

exchangers for preheating.

Recycle Gas Heating & Feed Heating System:

Recycle gas is pre-heated first by exchanging heat with Reactor Effluent & then

heated in a fuel gas fired Furnace (natural draft) from a temperature of 306-330 oC to

a temperature of 400-455 oC.

Fig. Flow Diagram of Hydrocracker

Unit

47

Fresh feed exchanges heat with Reactor Effluent only and is preheated upto 315-336 oC. The recycle gas & the fresh feed joins at the outlet of Recycle Gas Heater & the

combined stream then go to the Reactors at a temperature of 358 oC.

Reactor System:

The first Reactor has three beds of hydrotreating catalyst in which Hydrotreating

Reactions i.e.Denitrification, Desulfurization & Olefin Saturation takes place.

Particulate matter & Metals are also removed in the first Reactor top where a small

layer of Demetallisation catalyst is provided. In the 2nd & 3rd Reactor,

Hydrocracking Reactions takes place. All the three reactors are divided into different

beds with intermediate quench facility to control the reactor temperature rise due to

highly exothermic reactions.

Reactor Effluent Cooling:

Reactor effluent consists of excess H2, products & gases formed during reactions.

The reactor effluent is cooled by exchanging heat with fresh feed, recycle H2 & flash

drum liquid to a temperature of 125 – 132 0C.

At this temperature wash water is injected using high pressure reciprocating wash

water injection pump at the U/S of air coolers in the cooled effluent to dissolve

NH4Cl which otherwise, can precipitate out at this temperature & foul the air cooler

tubes. The effluent is then sent to Air Cooler, where it is cooled to 55 0C.

Reactor Effluent Separation System: The cooled Reactor Effluent goes to a High Pressure Separator. Hydrogen rich gas

leaving from the top of the separator is recycled back to Reactor by Recycle

Gas Compressor.

Hydrocarbon Oil is drawn from the separator & this drives Power Recovery Turbine

which is connected to Feed Pump. This oil goes to a low-pressure separator called

Flash Drum/LP separator.

Off gases of LP separator, are sent to Amine Treating Unit. Sour water is sent to

SWS and Hydrocarbon oil from flash drum is heated by exchanging heat with

Reactor Effluents upto a temperature of 210 0C & then it goes to Fractionation

Section.

Recycle Gas Compressor:

RG compressor is a centrifugal - HP Steam driven compressor. The gas from the

HP separator is compressed in it & the discharge gas is split into Quench & Recycle

streams. The Recycle Stream is heated in the Reactor Effluent Exchangers and then

Recycle Gas Heater after which it joins pre-heated Fresh feed & combined stream

goes to the 1st Reactor. The Quench stream is added between the Reactor beds for

their temperature control of catalyst beds in all the three reactors.

Make Up H2 Gas Compressor System: Pure H2, from H2 generation unit is compressed from 20 Kg. to 180 kg/cm2 (g) by

Make Up Gas Compressor. Make up Hydrogen is used to maintain the Reactor

System Pressure as hydrogen is consumed in the Reactors.

48

The system consists of three Reciprocating Compressors, each with three stages of

compression and having suction Knock Out Drums & Inter-stage coolers. Each

Compressor is capable of taking 60% of total load.

3.2 Fractionator Section:

Feed to the Fractionation Section comes from the Reactor Section Flash drum/LP

separator. This hydrocarbon liquid is pre-heated in the Reactor section by

exchanging heat with Reactor Effluent in exchangers to a temperature of 204-221 0C. This material then combines with Rich Oil from Sponge Absorber and the

combined feed is preheated in a process heat exchangers to a temperature of 265 0C

& sent to Stripper Column.

Stripper Column:

The primary goal of the Stripper Column is to strip out all the H2S in the feed & to

maximize recovery of LPG. The overhead liquid of Stripper is unstabilised LPG &

Light Naphtha, which is sent to Debutanizer. The vapour from the Stripper Overhead

Vessel is sent to Sponge Absorber. The bottoms from the Stripper are Heavy

Naphtha & heavier products. The column has a Reboiler, which is Fuel gas and fuel

oil fired. The bottoms leaving the Stripper is sent to Product Fractionator after

getting heated in the Feed Fractionator charge heater upto a temperature of 385 0C.

Sponge Absorber:

The overhead vapour from Stripper Overhead Receiver is fed to the bottom of the

Sponge Absorber. The lean oil to Sponge Absorber is diesel, which is taken from the

Fractionator diesel R/D line. The off gases from the Sponge Absorber contains

mainly H2S, H2 & some light ends and these are sent to common gas treating facility /

Sour Gas header.

The rich oil from the Absorber is then preheated with process exchange & meets the

feed coming from Reaction Section. This combined feed then finally goes to

Stripper.

Product Fractionator:

Stripper bottoms goes to the Product Fractionator after getting heated up in the

Fractionator charge heater to a temperature of 385 0C. The Fractionator separates the

different products from this feed. The Column has two side draws & associated

strippers. The overhead product from the Fractionator is Heavy Naphtha. First side

draw is of Kero/ATF & the 2nd side draw is of Diesel. Both the side draws are from

chimney trays & R/D, P/A & CR are drawn from this tray only. The unconverted

bottoms from the Product Fractionator is the unconverted oil along with unrecovered

heavy diesel which is sent directly to Vacuum column for Diesel recovery.

49

Diesel side stripper:

The Diesel side stripper is a steam stripper. This stripper has six trays & the vapors

from the stripper are routed back to Fractionator above the draw tray. The bottom

level of the side stripper controls the inflow to the Stripper.

Kero/ATF side stripper:

Vacuum Column Bottoms provide the heating for reboiling the Kero/ATF side

stripper has exchanger as reboiler. The stripper has ten trays & the vapour returns to

the tray above the draw dray of Fractionator column.

Product Fractionator Overhead:

The overhead vapours from the Fractionator are cooled via air-cooling & sent to

overhead receiver. The overhead hydrocarbon liquid is the Heavy Naphtha product,

which can be sent to separate storage or can be mixed in HSD pool in the unit itself.

The boot water is routed to sour water stripping unit

Vacuum Column:

The purpose of Vacuum Column is to increase the recovery of HSD portion from the

unconverted oil. The vacuum column consists of two-packed beds directly above the

Flash Zone. In this column, the only side draw, which is diesel, is from the chimney

tray, which is at the bottom of top packed bed. In this draw also CR, P/B & R/D are

withdrawn from the same chimney tray.

The bottoms from the Vacuum Column i.e. the unconverted oil is sent to FCC feed

tanks. The overhead vapors of this column are sent to three stage Ejector System.

The non-condensable vent from the ejector system is sent to furnace. This column is

having a dual (FG &FO) Fired Reboiler at the bottom.

Light Ends Recovery Section:

Debutanizer:

The net overhead liquid from the stripper is the feed to the Debutanizer. This

column separates the LPG & light Naphtha. This column is having Reboiler & the

heat for reboiling is provided by Diesel Pumparoud Stream from the Product

Fractionator. This column has 50 trays. The bottom product from this column is Light

Naphtha. The overhead vapour is first air-cooled & then water-cooled before it goes

to overhead receiver.

The liquid from the overhead receiver is sour LPG, which is partially used as reflux

and partially, routed to Deethanizer via amine column for H2S removal. The

overhead gas is sent to amine absorber.

50

Amine Column:

The unstabilised sour LPG from the debutanizer is the feed to amine column. In this

column, H2S is absorbed from LPG by contacting with 20% DEA. The rich amine

is routed to amine regeneration unit.

The LPG from this column goes to Amine Settler to remove any amine coming along

with LPG & after this, LPG goes to caustic washing & then to sand filter before

going to DeEthanizer column.

DeEthanizer Column:

The function of this column is to stabilise the LPG. The overhead vapours from the

column are cooled by cooling water & then routed to deethanizer receiver. This

column operates on total reflux. The overhead vapour from the receiver consist of

light ends and is sent to fuel gas system.

The bottom product from this column is a stabilized LPG. DeEthanizer is also

having reboiler & heat duty for reboiling is provided by Kerosene Pump around

stream.

51

Diesel Hydrodesulphurisation Unit

1. Introduction

1.1 Purpose of the Dhds Process

The DHDS unit is set up to reduce sulfur content in the diesel and produce diesel with

0.25% Sulphur.

The unit treats the following gas-oils fractions.

1. S.R.Gas oil

2. Vacuum Diesel

3. Vis-Breaker Gas Oil

4. Total Cycle Oil

1.2 Hydrodesulfurisation Section

The purpose of the section is to reduce 90% Sulphur in feed diesel using hydrogen

from Catalytic Reformer or Hydrogen GenerationUnits. In addition to the deep

desulfurisation, the diolefin and olefins will be saturated and a denitrification will

also occur.

The choice of catalysts and operating conditions is made in order to avoid

hydrogenation of the aromatics.

Feedstocks are blended from various sources, straight run or cracked products Sulfur

and nitrogen contents are depending upon the crude. Cracked products are

characterized by the presence of unsaturated hydrocarbons (olefins, diolefins and

aromatics)

Nowadays, more and more stringent specifications are imposed upon sulfur content of

diesel delivered by refineries.Denitrification improves the product stability.

The required level of desulfurisation is achieved by hydrotreating over a specially

selected catalyst.The presence of olefins or diolefins calls for additional bed installed

in upstream of the desulfurisation bed.In the present case, no aromatic hydrogenation

is aimed at.

The unit is able to produce treated Diesel Oil with maximum sulfur content of 500

ppm by providing an additional second Reactor in series.

1.3 Amine Treatment Section

The Amine Treatment Section is designed to remove Hydrogen Sulfide (H2S) from

gaseous hydrocarbons effluents.

H2S removal from gaseous hydrocarbons effluents is achieved by means of a

continuous absorption/regeneration process using a 25% wt. Di-Ethanol Amine

(DEA) for H2S removal.

52

This section includes the following main equipments

- HP Amine Absorber

- LP Amine Absorber

2. Process Description

Hydrogen

Make up gas

Compressor

Section

Hydrogen

Reactor

Heater

System

Reactor

Section

Recycle gas

Compressor

Section

Feed

System

Stripper

Section

Naphtha

Stabilizer

Section

HP Amine

Absorber

Section

LP Amine

Absorber

Section Rich Amine

to ARU

Naphtha to

Storage

Gas Oil to

Storage

Separation

Section

Feed

Preheating

System

2.1 Feed/Reaction/Separation Section

SRGO, SRVD, VBGO, CGO and TCO are received into under flow control, with the

feed from storage under feed surge drum level control. The blend is filtered

through semi-automatic back-wash type filter and routed to surge drum.

As the solids get collected in the filter, the pressure differential across it increases.

Once, pressure differential reaches the set point, the filter is automatically

backwashed. The backwash liquid gets collected in the backwash tank and is

pumped by backwash transfer pump to slop tank in offsites.

Fig. Block Flow Diagram of DHDS Unit

53

The pressure in the feed surge drum maintained by split range fuel gas to flare

pressure control.

Recycle hydrogen from recycle compressor discharge joins the feed at feed-effluent

heat exchanger inlet.The recycle gas ensures an adequate hydrogen partial pressure at

the entry of the reactor . The mixed stream is heated first of all in exchangers and

finally in the reactor feed heater to the required reactor inlet temperature.

The reactor outlet stream is split in two. One part exchanges heat with the stripper

feed , while the remaining part exchanges heat with the reactor feed. The two streams

are mixed together before entering feed-effluent heat exchanger.

The reactor effluents are cooled , first, in the effluent air-cooler , then in the effluent

trim-cooler .

To prevent ammonium salt deposits and the risk of corrosion, wash water is injected

at the inlet of the air cooler by washing water pump .

The H2 make up gas coming from the HGU/CRU is sent to the H2 make up KO

drum. H2 from CRU is passed through chlorine guard pot for removal of chlorine if

any from CRU. It is then compressed by the H2 make up compressor. The make

up gas joins the recycle gas stream from H.P. amine absorber upstream of the recycle

KO drum.

From Effluent Water train Cooler effluent is collected in the cold separator where

three phases are separated. The sour water containing ammonium salts is partially

recycled to the wash water drum under level control of this drum while the residue is

sent to the sour water stripper .

The gas phase from the cold separator is routed to the HP amine absorber KO drum

and then is partly sent to the HP amine absorber where H2S is removed. The other

part bypasses the absorber and is directly routed to the recycle KO drum . This by-

pass is for control of H2S concentration in the recycle gas, which should be

maintained within the range of 0.1 to 1.0 mol percent (typically 0.5% mol).

In the H.P. amine absorber, the gas is washed by DEA solution (Lean Amine). Lean

amine is received from the ARU and heated in LP Amine Heater, by steam. A

stream from this heater goes to HP amine surge drum. The H.P. Lean amine

circulation pump, pumps lean amine from surge drum to H.P. amine absorption

column top under flow control. The other stream from Lean Amine Heater is sent to

L.P. amine absorber . The lean amine is fed at the top under flow control. The rich

amine solution is withdrawn under level control at the bottom and sent to L.P. amine

absorber.

54

2.2 STRIPPER SECTION

The liquid hydrocarbon phase of cold separator constitutes the stripper feed.

The stripper feed is first preheated by exchange with stripper bottom product in the

stripper feed/bottom exchangers and then by exchange with the reactor effluent in the

stripper feed preheater exchanger in order to reach the required stripper inlet

temperature.

Medium pressure steam is injected under flow control at the bottom of the stripper in

order to maintain a diesel with the desired flash point and to strip off H2S. Light ends

and H2S from the top of the stripper and are partially condensed first in the

stripper/stabilizer air condenser and then in the stripper/stabilizer trim condenser.

Corrosion inhibitor is injected into the stripper overhead line upstream of the

condenser to minimize the corrosion.

Three streams are separated in the reflux drum: liquid HC (wild naphtha); free liquid

water, and a vapor stream. The vapor stream is sent to the L.P. amine absorber where

it is washed by a DEA solution to remove the H2S. The rich DEA solution is

withdrawn under level control at the bottom and sent to the ARU section for

regeneration.

The amine drain from H.P. & L.P. Amine System is collected in HDS Amine Surge

Drum. The amine layer which gets collected in the first bootleg is pumped by HDS

Amine Sump Drum pump under level control to ARU. The hydrocarbon layer from

second bootleg is pumped by HDS Amine Sump Drum HC pump under level control

to the slop tank.

The decanted water from reflux drum is sent under boot level control to the washing

water surge drum . The liquid hydrocarbons are split into reflux, which is returned to

the stripper under flow control, and into liquid distillate (wild naphtha), which is

Naphtha Stabilizer under level/flow control.

The stripper bottom product is cooled against the stripper feed. Final cooling is then

achieved in the hydrotreated diesel air cooler and in the hydrotreated diesel trim

cooler. The free water contained in the product is removed in the coalescer

(including a prefilter ) and routed to the washing water surge drum . The dry product

is finally sent under stripper bottom level control to battery limit.

2.3 Stabilizer Section

The feed to the stabilizer is heated up in the stabilizer feed/bottom exchanger before

entering the column at the top tray. The remaining H2 and H2S are stripped at the top

with the light ends to constitute the overhead gas which is mixed to the overhead of

the stripper. The stabilizer is heated by a steam reboiler operating under temperature

control. The bottom product is cooled in the feed/bottom exchanger then in the

stabilized naphtha cooler before being routed to storage under cascade level/flow

control.

55

2.4 Catalyst Regeneration

During catalyst regeneration a mixture of nitrogen and oxygen (upto 1% vol.) is

circulated by the recycle compressor through the reaction section. The feed/effluent

exchanger is bypassed. The gaseous stream is preheated against the reactor effluent.

A bypass of this exchanger (under TC control) is used to control the furnace inlet

temperature and the effluent temperature. The required reactor inlet temperature is

reached in the reactor feed heater.

The reactor effluent is neutralized by injection of ammonia, before being cooled . A

caustic soda solution is injected and mixed with the effluent to control the salt

deposit. The mixture decants in the HP cold separator. The sour water is routed to

the caustic treatment under water level control, while the vapor phase goes back to

the recycle KO drum .The oxygen make-up is made through the make-up compressor

by injecting air.

56

Amine Regeneration Unit

1. Introduction

The amine regeneration unit is designed to regenerate rich Diethanol amine

containing H2S/CO2 from fuel gas amine absorber. LPG amine absorber (located in

CDU) and rich amine solution from hydrocracker and Merox units to obtain lean

DEA for reuse in amine absorption units.

2. Process Description

2.1 Amine Flash Column and Heat Exchanger

The rich amine containing absorbed H2S and CO2 from various amine absorber units

enter the flash column at a pressure of 5.0 Kg/cm2g and temperature of 54 C. A

backpressure controller is provided near flash column in order to avoid any flashing

in the line. The flash column is a tall vertical vessel having diameter of 600mm at top

section and 3600mm at the bottom section. The flash column operates at a pressure of

1.0 Kg/cm2g. The feed enters below the packing and above the fourth tray. Because

of the flashing, any hydrocarbons dissolved in the amine get liberated, thereby

reducing the quantity of hydrocarbons going with the sour gas to sulphur unit, which

spoils the catalyst. Some H2S also gets liberated. A slipstream of lean amine solution

making counter current contact with liberated gases over a packed bad again absorbs

the liberated H2S.

The liberated hydrocarbons from top of the column enter the flare header through a

pressure control valve. Flash column is also provided with a oil skimmer at the

bottom to skim off any hydrocarbon liquid carry over along with rich amine.

From the flash column, the rich amine at 1.3 Kg/cm2g pressure and 54 C temperature

is pumped to amine regenerator after preheating to 96 C in lean amine / rich amine

exchanger coming from the bottom of amine regenerator at 121.2 C which in turn

cools down to 79.8 C. The lean amine from rich amine exchanger is further cooled to

47 C in lean amine cooler and routed to Amine storage tank.

2.2 Regeneration

The hot rich DEA enters the amine regenerator. In the amine regenerator, the rich

DEA is stripped off of its absorbed sour gases H2S and CO2 using steam as the

bottom heating media in both the re-boilers provided at the bottom.

The amine regenerator is a tall vertical column 24200-mm high and has a diameter of

3600 mm. It contains 24 trays. The feed to amine regenerator enters the column on

21st tray. Provision is there to introduce the feed on 17th and 19th tray also. The amine

regenerator operates at a top pressure of 0.90 Kg/cm2g. Reflux water enters the

columns on 24th tray and descends down. This prevents DEA losses into the overhead

and ensures complete removal of H2S. The re-boiler vapours from the bottom of the

tower counter currently contact the rich amine and strip it off H2S / CO2 present it the

DEA solution.

57

The chemical reactions involved are:

R2NH3S ----------------------------- R2 NH + H2S

(R2NH3 ) CO3------------------------- R2 NH + CO2 + H2O

Where, R is a CH3,CH2,OH group.

The liberated sour gases and steam at 110 C and 0.90 Kg/cm2g pressure leave the

regenerator from the top and enters the regenerator over head condenser where the

gases are cooled and steam is condensed to 40 C by cooling water on the tube side.

The condensate and the gas flow freely from the condenser to the reflux drum. The

sour gases from the reflux drum top go to the sulphur recovery plant for production of

sulphur.

From the bottom of the reflux drum, Reflux pumps take suction and deliver the liquid

to the regenerator top above the 24th trays as reflux. From the draw off pan below 1st

tray of regenerator lean amine flows into the amine re-boilers where it is heated by

LP steam on the tube side. From the re-boiler, liberated steam and gas enter the

column below the first trays.

From the regenerator bottom lean amine at a temperature of 121.2 C and pressure of

0.9 Kg/cm2g pressure enters the DEA feed bottom exchanger , where it gets cooled

to 79 C by exchanging its heat with the incoming rich DEA which gets heated from

53 C to 96 C. After it lean amine passes through exchanger to cool the lean amine

to 47 C.

A small stream of lean amine is sent to the top of the amine flash column to re-absorb

any H2S liberated during flashing.

58

Sour Water Stripping Unit

1. Introduction

Refinery Sour Water Stripping Unit and a two stage Hydrocracker Sour Water

Stripping Unit are the two sour water stripping units of Panipat Refinery to treat Sour

Water.

Refinery sour water stripper is designed to treat sour water from CDU, VDU, VBU,

CRU, FCCU, DHDS and intermittent sour condensate from SRU, HCU, sour water

stripper unit is designed to treat sour water from reaction section and fractionation

section of hydrocracker.

1.1 Unit Capacity

A)

i) Refinery sour water stripper capacity is 71805 Kg./hr. of sour water.

ii) HCU Sour Water stripper capacity is 16388 Kg./hr. of sour water.

B)

Turn down ratio for refinery sour water stripper is 40% of max. capacity.

Turn down ratio of HCU sour water stripper is 50% of max. capacity.

1.2 Feed Characterstics:

1) Refinery sour water:

H2S, ppmw : 2500

NH3, ppmw : 1100

2) HCU Sour Water:

H2S, ppmw : 42580

NH3, ppmw : 17740

1.3 Product Characterstics: H2S, ppmw : 50

NH3, ppmw : 50

2. Process Description

2.1 Single stage Refinery Sour Water Stripper Unit

Sour water from CDU, VDU, VBU, CRU, FCCU, DHDS and intermittent sour

condensate from SRU is received from a common line in a sour water surge drum.

This is a horizontal vessel and is provided with two baffle plates, which divide the

drum into three compartments. Sour water enters the middle compartment. Water

settles down at the bottom and flows into the 3rd compartment. Any oil contaminated

59

with water over flows from the top to the first compartment from where it is drained

to OWS at regular intervals.

The sour water from surge is pumped to single stage stripper column under flow

control through feed/bottom exchanger. In this exchanger sour water is heated from

440C to 96.5 0C in tube side and stripped water gets cooled from 123 0C to 70 0C on

the shell side. The feed enters at the 24th tray in normal operation.

Sour water stripper is a tall vertical column having a height of 33.5m and dia of

1.55m It contains 39 numbers of valve trays made of 316 SS. The stripper operates at

a top pressure of 0.8 Kg/cm2g (floating with SRU header backpressure). Column top

temp is to be maintained 90OC and corresponding bottom temp. is 123 0C. The 33rd

tray is a chimney tray and provides partial draw off sump for pump around circuit.

Manual oil skimming facility is provided on this tray. For introducing the heat into

the system column is equipped with an LP steam heated kettle reboiler and a

condensate Pot.

For controlling the column top temperature pump around system is provided.

Circulating reflux pumps will take sucion from the partial draw off tray No.33 and

will discharge the circulating reflux to air cooler where it is cooled and put back in

the column above 39th tray. Hydrogen sulphide and Ammonia gas recovered from

column overhead at 900C and 0.8 Kg/cm2g. is sent to sulphur recovery unit through a

steam-jacketed line.

From bottom of the stripper, stripped water containing ammonia and H2S less than

50 PPMW at 1.2 Kg/cm2g pressure and 123 0C temp is pumped out by stripped water

pumps to the desalter section of the crude unit. The stripped water is cooled by

preheating the feed as the 1st step, to bring down its temp. to 70 0C and further cooled

to required battery limit temperature of 40 0C in a water cooled exchanger.

2.2 Two-stage HCU sour water stripper unit

Hot sour water from the Hydro cracker Unit is mixed with the ammonia rich recycle

stream from second stripper overhead (to keep H2S in solution and for constructive

recovery). This mixed stream will be cooled in a water cooler to 37 0C and received

in a surge drum. Surge drum acts as a three phase separator like refinery sour water

surge drum to remove any flashed vapour and hydrocarbon liquid in the sour water.

While the flashed vapour is joined to the ammonia stripper overhead line to be routed

to thermal incinerator in SRU or acid flare. The entrained liquid oil, if any, is

skimmed off from the surge drum and drained to OWS via seal pot.

The sour water is sent to sour water storage tanks. Any hydrocarbon liquid not

separated in surge drum separates in tank. The sour water tanks are blanketed with

nitrogen to keep off air/oxygen.

Sour water from tank is pumped by the HCU SWS feed pumps to the first stage H2S

stripper column. Feed to is through feed/bottom exchanger where the incoming sour

water feed is preheated against 2nd stage bottoms, i.e. stripped water.

60

First stage stripper is 25.85 meter high and dia is 1.0 meter. It contains 32 Nos. of

valve trays. This column operates at top pressure of 7 Kg/cm2g and temperature of

840C.

The feed enters the column at 24th tray. The stripping section removes most of the

steam and almost pure H2S is produced at the top of the column. A slip stream

quantity is taken from the 2nd stage bottom (stripped water) from the outlet of

exchanger and sent as hot wash water to the stripper column. Since maintaining the

temperature of 730C of this stream is very important for column steady performance,

an additional wash water cooler is provided. The use of wash water helps in retaining

the NH3 in the stripped water stream.

H2S stripper is also equipped with MP steam heated kettle reboiler and 1st stage

condensate pot to provide the reboiling duty to maintain column bottom temperature

of 166 0C. The MP steam flow to reboiler will be controlled by a flow ratio controller

which resets steam flow in accordance with sour water feed to 1st stage stripper, to

maintain a constant ratio of steam to sour water.

The sour water from the H2S stripper bottom, containing almost all ammonia and

small quantity of unrecovered H2S is fed to the 2nd stage HCU sour water stripper on

24th tray. This water containing NH3 is stripped out to leave less than 50ppm by wt. of

NH3 in the stripped water.

2nd stage sour water stripper is a tall column of 32.25 meter high and dia of the

column up to 33 tray is 1.25 M and above 33 tray it is 1.8 meter. Total 39 trays are

there in this column. Tray 33 is chimney tray is providing necessary hold up for pump

around system to condensate Ammonia rich gases from 2nd stage stripper top is routed

to SRU thermal incinerator.

The required re-boiler duty for this column is supplied by the LP steam heated kettle

reboiler and condensate will be collected in 2nd stage condensate pot. 2nd stage

stripper column bottom temp is required to be maintained 121 0C. Flow ratio control

cascading is with sour water feed to H2S stripper to maintain a constant rate of steam

to sour water feed. This ratio should be sufficient to bring down ammonia content

below 50ppm wt. in stripped water from the column bottom.

The over head pump around circuit consists of circulating reflux pumps and 2nd stage

circulating reflux air cooler. Pumps take suction from partly draw off chimney tray

No.33 and circulates the same at a constant rate at the column top. This circulating

cold reflux causes condensation the steam present in the vapour from tray 32. The

ammonia (with small H2S quantity) coming out from column top is routed to SRU

ammonia incinerator or acid flare header. The stripped water from 2nd stage column is

pumped using stripped water pumps to HCU sour water surge drum.

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Bitumen Blowing Unit

1. Introduction

The unit is designed for producing 508800-tonnes/year bitumen from vacuum residue

of Arab mix crude by air blowing. Air blowing of vacuum residue at high temperature

considerably increases the contents of gums and asphaltenes at the expenses of

conversion of a portion of hydrocarbons into condensed oil. Bitumen is a colloidal

solution of asphaltenes and associated high molecular gums in the medium formed by

oil 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.

1.1 Product

S-35 50000 TPA (Penetration 30-40)

S-65 125000 TPA(Penetration 60-70)

S-90 325000 TPA(Penetration 80-100)

2. Process Description

2.1 Chemistry of Air Blowing

Air blowing of asphalt is a chemical conversion process involving dehydrogenation,

oxidation and polymerization. Air is injected uniformly over the bottom of the

blowing vessel & creates turbulent mixing as it rises through the asphalt. The reaction

between asphalt and oxygen from the air is exothermic. The heat of reaction is

controlled by water quenching if it is in excess of the heat requirements for the

process.

The conditions of air blowing are regulated so that blown asphalt of the desired

properties is produced. The asphalt is hardened, as a result of air blowing and the

properties of hard air blown asphalt are less susceptible to change with varying

temperature.

Most of the oxygen that reacts with the asphalt in blowing process forms water vapor.

Very small amounts are bound in oxides of carbon and sulfur and in the oils taken

overhead. Only 5-25% of the reacted oxygen remains bound in the blown asphalt.

2.2 Production Of Design Grade Bitumen

The feed to BBU is received from off sites storage tanks at a temperature of 160 C.

It is heated up to the reaction temperature of 230 C in charge heater. The hot feed

goes under flow control to the bitumen blowing drums. Air from air compressor is

blown under flow control into the contents of bitumen blowing drums.

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Blown vapors are quenched in the top section of the bitumen blowing drums, using

boiler feed water and LP steam to remove the exothermic reaction heat. The quenched

vapours go to wash column where a circulating gas oil stream is employed to wash

the vapor for maximum recovery of the hydrocarbon content. The off gases after the

wash column are sent to bitumen incinerator.

Hot bitumen product from the bottom of bitumen blowing drum flows into the surge

drum. From here the hot product is pumped by the bitumen product pumps under

ultrasonic level controller to the bitumen product coolers where product bitumen is

cooled by generating LP steam. The cooled product at 170 C is routed to off site

storage.

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Sulphur Recovery Unit

1. Introduction

The function of SRU, is to recover sulphur from H2S present in acid gas from Amine

Treating/Regeneration Unit and H2S rich Sour Gas from single stage Refinery Sour

Water Stripper Unit and 1st stage of OHCU sour water stripper. This unit based on

MCRC (Maximum Claus Recovery Concept) is consisting of one Claus stage and

three MCRC converters for recovery of sulphur from above streams. The equipment

in the unit will be divided into three main sections, namely the Claus section, MCRC

section and tail gas incineration section.

Sulphur recovered in the process is stored in the sulphur pit and is pumped to a yard

where sulphur lumps are produced by quenching the molten sulphur using service

water.

It is a combination of Claus process and the extension of Claus reaction upto the

temperature at which the product Sulphur starts condensing on the catalyst itself.

Extension of Claus reaction up to sulphur dew point enhances sulphur recoveries

beyond 99%. As Sulphur condensation on the catalyst leads to its activity reduction,

hence regeneration of such portion of the catalyst bed is required.

The Sulphur Recovery Unit consists of one thermal reactor (main combustion

chamber) and four catalytic converters. The first catalytic converter is a conventional

Claus Converter while the last three are MCRC converters that alternate between a

sub-dew point mode and a regeneration mode. With such a four-converter MCRC

configuration, Sulphur Recovery higher than 99.0% is achievable. The salient feature

of the MCRC process is that regeneration takes place on line.

The acid gas from Amine Recovery Unit (ARU), H2S rich gas from the first stage

Sour Water Stripper Unit (SWS) and NH3 rich gas from the second stage Sour Water

Stripper Unit are fed to Sulphur Recovery Unit. Hydrogen sulphide content of feed

gas is converted into elemental Sulphur in the Sulphur Recovery Unit (SRU).

The SRU (115 TPD Capacity) is a standby train for existing SRU at Panipat Refinery

(Unit-22). This new train is utilising following facilities available in existing SRU as

common facilities for 2 trains:

- Feed gas KODs

- Fuel gas KODs

- BFW Pre-heater

- Combustion air blower

- Chemical Injection system

- Incineration Section including Vent stack

- Sulphur yard

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2. Brief Process Description

2.1. Claus Section

The acid gas feed from Amine Regeneration Unit is introduced via the knockout

drum and H2S rich acid gas from first and second stage sour water stripper & first

stage of OHCU SWS unit and NH3 rich sour gas from second stage of OHCU SWS

unit are introduced via respective knockout drums . Acid gas from ARU preheated to

110 0C in Acid Gas Pre-heater so that temperature of mix gas stream is maintained at

90 0C (minimum). Sour water separated in the knockout drum is collected in the

SWS/NH3 gas condensate collection pit and the condensate is sent to SWS unit

sump. Condensate from Acid gas KOD is collection in Acid Gas Condensate

collected pot and condensate is sent to ARU sump.

To obtain high percentage of Sulphur Recovery by the MCRC process, the ratio of

H2S to CO2 must be kept at a value of 2 to 1 in process gas from claus section. This is

done by cascading a process analyser (air demand analyser or ADA) to the air & acid

gas flow ratio control loop. The ADA is complete with a sample system and source

module, a detector and control module, a closed loop controller and an interface

package. The ADA will monitor the ratio of H2S to SO2 in the exit gas of Claus

converter-I provided after heater, based on the requirement of H2S/SO2 as 2.0 at the

exit of reaction furnace. Any deviation from the required ratio, an analyser signal

changes the set point on the air/acid gas flow ratio control loop. Thus, more (or less)

H2S will be burned to maintain the correct H2S/SO2 in the exit gas of Claus converter-

I based on the requirement of H2S/SO2 as 2.0 at the exit of reaction furnace. Thus

more, (or less) H2S will be burned to maintain the correct H2S/SO2 ratio in the

process. The air flow rate is first set by the air demand ratio (air /acid gas) to get

H2S/SO2 as 2. Finally it is tuned by ADA, based on the analysis of exit gas from

converter-I.

The hot reaction gases enter into a waste heat boiler (WHB) where heat is recovered

by generating steam at the pressure of 17.0 Kg/cm2a. The WHB is a fire tube boiler,

it cools process gases to 300 0C.

The main reactions in the furnace are:

H2S + 3/2 O2 ------ SO2 + H2O + Heat

The major percentage of residual H2S combines with the produced SO2

to form Sulphur, according to the following reaction:

2H2S + SO2 ---------- 3/n Sn + 2H2O + Heat,n = 2.6 or 8

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The gas leaving the WHB is further cooled to 185 0C by producing 6.5 Kg/cm2a

steam in the Sulphur condenser-I. The Sulphur produced in the reaction furnace

condenses and separates in the outlet channel of the Sulphur condenser-1 and flows to

sulphur pit . The sulphur condenser-I vapour effluent is reheated 273 0C by mixing

with hot combustion product at a temperature of 1287 0C from an in-line burner. The

in-line burner uses a slip stream of ARU gas from KOD as fuel to produce the hot

combustion product. The temperature of the exit gas of in-line burner is controlled by

flow control of acid gas flow to burner . The combustion air is obtained as slipstream

from main blower and its flow rate is automatically controlled based on the acid gas

flow to burner. The preheated vapours from the line burner mixing chamber further

flow to Claus converter-I at 273 0C where additional conversion to sulphur takes

place. The reaction gases from the converter-I is cooled in Re-heater–II (Gas Gas

Exchanger) by heat exchange with cold process gas from sulphur condenser-II .

Further cooling of this gas takes place in sulphr condenser-II. The produced sulphur

condenses and flows to sulphur pit . In sulphur condenser-I and condenser-II, low

pressure steam of 6.5 Kg/cm2a pressure is produced and taken out by pressure control

to low pressure steam header. Pre-heated Boiler Feed Water is supplied on level

control in condensers. The sulphur condenser-II vapour effluent is reheated to 276 0C

in the Re-heater-II by heat exchange with exit gas from converter-I. Re-heater-II is a

Gas–Gas Exchanger.

2.2 MCRC Section

MCRC Section is equipped with three converters and three sulphur condensers.

Process gas from Claus section at temperature of 276 0C enters into the MCRC

converter-II and regenerates the catalyst at high temperature by vaporising sulphur

from the catalyst pores where it (sulphur) was already adsorbed when the converter

was in sub-dew point mode. Catalyst is regenerated and simultaneously Claus

reaction further proceeds to produce elemental sulphur in the regeneration mode

reactor. The process gas flows directly to sulphur condensers-III at a temperature of

296 0C. The elemental sulphur condenses and separates in the outlet channel of the

sulphur condenser and flows to sulphur pit . The balance gas exiting from Sulfur

Condenser-III at a temperature of 140 0C, goes to sub-dew point converter-III . The

Claus reaction conversion to sulphur occurs at sub-dew point condition, where

produced sulphur is adsorbed onto catalyst pore structure. The leaving process gas

from Catalytic Converter-III flows to condenser-IV where sulphur is condensed and

flows to sulphur pit . The balance process gas at a temp. of 124 0C leaving Sulf.

Condenser-IV goes to converter-IV without reheating. The Claus reaction continues

at sub-dew point mode to produce sulphur. The process gas from converter-IV flows

directly to condenser V, from where condensed sulphur is taken out to sulphur pit.

The tail gas from condenser–V is sent to incinerator. Sulphur condenser outlet

channels are provided with demisters to minimise sulphur loss due to entrainment.

Adsorption of sulphur on the sub-dew point converter catalyst depresses mist

formation.

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When the catalyst on the sub-dew point sulphur converter-IV reaches at saturation

with sulphur, these converters interchange positions with converter-II automatically

by means of switching valves. These switching valves operate on time cycle control

system. Interchange of position of converters-II & IV means, the process gas from

Claus section enters first into converter-IV which is put in regeneration mode and exit

gas from converter-IV after cooling in condenser-V enters into converter-II on sub-

dew point mode. Similarly in the next cycle converter-III will be in regeneration

mode and converter-IV will be put on sub-dew point mode by operating switching

valves. Hence at any time one converter is in regeneration mode and two converters

are in sub-dew point mode.

Due to low temperature reaction in the sub-dew point converters and in order to

condense as much sulphur vapour as possible, the last three condenser operate at low

temperature. This low temperature is obtained by generating steam at a lower

pressure (1.0 kg/cm2g) than in the proceeding condensers. The steam is condensed in

air cooled steam condenser after which the condensate is drained back into the shell

side of the sulphur condenser by pressure control.

2.3 Sulphur Storage

The discharge line of each sulphur condenser will be connected into its own buried

seal leg. As the sulphur fills the seal leg, it over flows into a header that connects to

the sulphur pit.

The sulphur drained to the pit is maintained in liquid stage at 130-140 0C using pit

heating coils. Saturated LP steam is used in jackets of liquid sulphur lines, sulphur pit

etc.During storage of sulphur, H2S dissolved in sulphur gets liberated gradually.

Hence a constant sweep air circulation is maintained over the liquid sulphur in the pit

using a pit ejector , while one of the ejectors is normally operating, the other one is

kept as standby. Air and steam from pit ejector containing H2S is routed to the

thermal incinerator .

Liquid sulphur from pit is pumped to the existing sulphur yard using sulphur pumps ,

where it is solidified by spraying cold water.

The sulphur pumps are also used to recirculate part of liquid sulphur by opening part

of recirculation valve on pump discharge to pit thus providing agitation in liquid

sulphur pool. This helps in liberation of H2S from liquid sulphur pool.

2.4 Thermal Incinerator

In thermal incinerator, the combustible components in the Tail gas from the last

condenser of MCRC section and sweep gas from sulphur pit are thermally oxidised at

750 0C temperature. Tail gas from MCRC process and vent gas from sulphur pit are

fed to thermal incinerator and oxidised with an excess of air. A dedicated air blower

is used to supply oxidation air to incinerator. The thermal Incinerator converts almost

all the H2S and NH3 in the tail gas so that the H2S concentration in the stack gas is

less than 10 ppm (volume). Fuel gas flow rate to incinerator burner is based on exit

gas temperature control, which is set at 750 0C. Flow rate of primary air from

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incinerator blowers is controlled based on the ratio with fuel gas flow rate.

Secondary air flow rate is reset by oxygen content of flue gases. Excess air operation

is essential for complete incineration of process gases. Oxygen content of stack gases

is set at 2 vol %.

In additional to incinerator burner a reduction furnace burner and Reduced Furnace

are also provided to destroy NH3 rich sour gas while minimising NOX content of flue

gas. Hot gas from Reduction furnace flows to thermal incinerator.

The remove the heat generated in the thermal incinerator, the flue gas passes through

the tube bundle located in the WHB. Also a reduction furnace is provided for

complete destruction of NH3 in NH3 rich gas from SWS 2nd stage. The flue gases are

cooled to 285 0C thereby generating MP steam (16.5 Kg/cm2g).

Finally, the flue gases are vented to atmosphere through vent stack at a temperature

of 288/600 0C (normal/bypass mode). Shut down of thermal incinerator due to any

reason would lead the shut down of SRU.

2.5 Waste Heat Recovery System

MP steam is generated in Waste Heat Boiler (WHB) by cooling hot process gases

from main combustion chamber. Saturated MP steam produced in WHB is fed to MP

steam header. Sulphur condenser-I &II generate LP steam, which is fed to the LP

steam header. A part of LP steam is used for tracing purpose in the unit and as heating

medium in Acid Gas Pre-heater, BFW Pre-heater & in sulphur pit. Balance LP steam

is exported to B/L.

BFW from B/L is pre-heated to 130 0C in a LP steam exchanger to avoid cold spots in

WHB and sulphur condensers. Pre-heated BFW is fed to WHB under its level control.

This control is provided to prevent tube dry out under all situations. BFW is also fed

to sulphur condensers I&II with level control. Normally BFW supply to MCRC

condensers is not required due to closed loop operation. However BFW makeup on

level controls to make up for losses due to leakage.

Blowdown from various exchangers is routed to Blow down drum where it is

quenched with water and drained to storm sewer. Condensate from all steam

exchanger are sent to atmospheric condensate flash pot and quenched with DM water

and sent to LP condensate header.

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Apart from above processes OMS & WWTP are integral parts of the Refinery.

Oil Movement and Storage (OMS)

1. Introduction

The Oil Movement and Storage (OM&S) is an integral part of Production

Department. The activities of OM&S can be classified as follows:

1.1 OM&S Control Room

• Oil Accounting

• Co Ordination - OC-2, 3, & 4, SMPL, KBPL, KBP, TPS, WWTP

1.2 OC-2 Operation

• Crude and intermediate feed receipt, preparation, feeding

• Ifo & flo supply to units & TPS

• Slop receiving & processing

• Off spec. Tanker unloading

• Tk dipping, water draining, bleeding

1.3 OC-3 Operation

• Product receipt, preparation, blending

• Flo supply to units & dye dozing

• ATF transfer, mkt & ppl transfer, dipping

• Gt and bitumen feeding, b/l valve operation

1.4 OC-4 Operation

• Lpg, Propylene & 96 octane gasoline receipt, preparation & transfer to KBPL.

• Interlock & gas leak checking.

1.5 Crude receipt and product pattern:

Crude oil for Panipat Refinery is supplied through 24-inch chaksu-karnal branch

pipeline of the Salaya-Virangam-Mathura pipeline. The entire crude oil requirement

is met either by low sulphur (Bombay High) Crude Oil or by high sulphur

imported Crude Oil which is received at Salaya terminal. Crude oil is stored in 8

no. of floating roof tanks. From the storage tanks the crude oil is pumped to

Distillation unit through feed booster pump.

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Product Pattern:

CRUDE 100 ( % by weight)

LPG 3.3

NAPHTHA 5.3

MS 12.2

ATF 3.7

MTO 0.2

SKO 10.1

HSD 41.9

HPS 7.7

BITUMEN 6.7

SULFUR 0.3

FUEL & LOSS 8.37

2. Storage Tanks and Vessels

All petroleum stocks from crude oil to its lightest volatile fractions must be stored

during the intervals between production, transportation, refining, blending and

marketing. Hence, for this purpose, different types of tanks and vessels to suit the

characteristics of the product to be stored are provided.

2.1 Types of Tanks

There are three types of storage tanks at Panipat Refinery.

Cone roof or fixed roof tanks for storing heavy products i.e. less volatile material.

Floating roof tanks for storing crude oil and lighter products.

Cone cum floating roof tanks where contamination with water is not desirable.

2.1.1 Cone Roof Tank

This is a vertical cylindrical vessel made of welded plates. The fixed roof is

supported on internal structures. The shell at the bottom is thick while at the top it is

thin.

2.1.2 Floating Roof Tanks

These are vertical cylindrical welded steel tanks with open tops equipped with

floating roof which cover and ride up and down, on the liquid stored in the tank. The

floating roof reduces evaporation loss.

2.1.3 Horton Spheres

LPG is stored above ground under pressure in Horton Spheres designed to withstand

safely the vapour pressure at the specified maximum temperature. At present there are

7 horton spheres in service. All the LPG Storage vessels are insulated with mineral

wool.

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The horton spheres have following fittings

Automatic level indicator Servo float type plus D.P. Cell

Pressure gauge

Temperature gauge

High level alarm

Two Nos. safety relief valves, both the safety valves are connected

to flare.

A manual vent joining the flare header.

31 Nos. of thermal fuses. In case of fire, they will blow and the

following operations will be initiated automatically.

Isolation of vapor return line.

Isolation of recalculation header

Isolation of LPG inlet/outlet line of the effected sphere.

Horton sphere have been provided with water sprinklers and water

deluge system.

2.2 Tank Pad The tank is erected on a specially prepared hardened pad. It is called tank pad.

2.3 Steam Coils and Insulated Tanks

If the liquid is to be stored at a higher temperature, than the ambient temperature, the

shell of the tank is covered with insulation to prevent loss of heat and/or is provided

with steam (heating) coils inside the tank, which are placed above the tank floor.

2.4 Hammering

If for any reason the condensate in the steam coil is not moving freely, the loud

banging sound will be heard. It can be heard from a distance. The phenomenon is

called "hammering". The remedy is to take immediate steps to drain out the

condensate. Till this is done, the steam inlet can be reduced or closed temporarily.

In order to protect the coils against damage due to hammering and to take care of

expansion due to variation in temperature, the supports on which coil is resting are

welded to the tank floor.

2.5 Inlet, Outlet, Mixer Nozzles

Each tank may have one or two nozzles in the shell. One nozzle is inlet outlet i.e.

for receiving oil and for taking out oil from the tank. The second nozzle will be

found in those tanks where provision is made for mixing the contents to a uniform

density.

2.6 Dip Hatch

There is a ladder to go on the roof of the tank. A platform is provided at the landing,

where the ladder ends at the top Near this platform is situated a dip hatch with a cover

which should be kept closed all the time except while sampling/dipping. Normally at

the mouth of the pipe of dip hatch a ring of non-ferrous metal is fixed. This is to

avoid the generation of static electricity that may be produced when the steel tape of

71

dip tape slides over the edge of the pipe.

2.7 Reference Point

Sometime a guide made of non-ferrous metal with sloping notch wide enough to

accommodate the tape of dip tape is fitted. This guide or a marking on the rim of

the above said ring indicates the reference point.

2.8 Datum Plate

Exactly below and corresponding to the dip hatch a steel plate is provided at a

suitable height from floor of the tank is called datum plate. When a dip is taken, it

is here on this plate the bob of the dip tape rests.

2.9 Reference Height

Reference height is the distance between the marking on the rim of the pipe (nozzle)

or dip hatch and datum plate.

2.10 P.V. Valve (Breather Valve)

Fitted on the roof is a pressure cum vacuum relief valve. It has a dual function,

when the liquid is coming into the tank, the air inside the tank are

expelled out through this and no pressure is allowed to be built inside. Similarly,

when the liquid goes out from the tank, the air is allowed to enter through this

valve into the tank thus not allowing the creation of vacuum. If for any reason a

vacuum is created inside the tank, the shell of the tank will buckle. If the PV

valve does not function, the chances are that the pressure inside may not be

regulated and the built up pressure which will be more than the atmospheric pressure

outside cause a blow up. In such a case to minimize the damage to shell the joints

where roof is welded to shell are kept comparatively weak so that it is the roof

where the blow up occurs.

2.11 Foam Chambers

This is a fire fighting equipment fitted on the tanks. These are fitted on the opening

in the tank shell nearest the roof and connected to a pipe which runs along the

shell and leads away from the tank. In the event of fire, foam is pumped into the

tank. Thus, a foam blanket is produced over the liquid surface cutting off the

oxygen and thus the fire gets extinguished.

2.12 Water Drain

The drain water from the tanks, water draws are provided. The arrangement of water

draw differs from design to design.

In Russian design the conical saucer shaped tank floor with a depression ending in a

pit in the center. Since the slope is towards center, all the water flows to wards

depression in the center and gets collected in the pit.

Generally the bottom of the tank (tank floor) is convex i.e. like an inverted saucer

shape. Here, the water in the tank gets collected towards the periphery

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2.13 Water Draw in ATF Tanks

In ATF tanks even the tracer of water is not acceptable. That is the reason why a

medium sized. ATF tank is supposed to have 4 water draws while other tanks of

comparable size have only one water draw. Stagnant water at the bottom (no matter

how small in qty.) in ATF tank gives rise to a kind of algae which multiplies

fast and forms colonies. Organic chemical produced by colonies reacts with ATF and

renders it off specification. ATF fails is the test of silver strip.

2.14 Tank Cooling Arrangement

A circular ring of pipe is provided towards the top of the shell. Spray nozzles are

fitted into this ring which is connected with pipes to supply water through fire

water system.

3. Water as a Static Generator

Petroleum products in motion, as and when being pumped through a pipeline,

become electro statically charged. If water is present in the oil, the hazard increases

greatly because even small amount of water in flowing oil can cause a dangerous

build up of static charges. Static sparks produced in this manner have caused many

accidents. Electrostatic charging of oils occurs when droplets of water settle through

oil in tankage. Keeping all petroleum products as free from water as possible avoids

this hazardous condition.

4. Tank Mixers: The three different types of mixing arrangement provided in

different tanks.

4.1 Propeller

It consists of a long shaft at end of which three curved blades are fitted. The other

end is brought out of the tank. If the rotation is in correct direction, it throws the

heavy liquid, which has a tendency to settle on tanks bottom, towards the top, thus

setting in motion a circular movement in the vertical plane. The settling and

accumulation of sludge and sediment on tank floor is considerably minimized and the

tank may not require Cleaning.

4.2 Jet Mixer

Heavier portion of oil has tendency to settle down. Thus, heavier liquid is drawn

through tank outlet by a pump of adequate capacity & head and is

returned to the tank through a comparatively smaller dia line which enters the

tank through a separate nozzle.This nozzle is usually pointing towards the center

of the tank roof. A circulation is set in motion which results in thorough mixing.

4.3 Sacony Mixer

It consists of a vertical pipe with four nuts of circular holes at regular intervals,

the top end is open. It extends upto the 80% of safe filling height of the tank. It is

connected to the eductor placed on the tank floor. The eductor is fixed in the tank on

the discharge line of the circulation pump. When the content of the tank are circulated

through eductor, it creates a suction (pull) in the vertical pipe and pulling liquid

73

from all the levels of liquid through the holes in it. Thus oil from different levels

gets mixed and passes through the bore of the eductor.

5. Auto Level Measuring Instrument: Two types of auto tank level measuring

instruments are being used at Panipat Refinery.

5.1 Servo Level Xr:

These instruments are installed primarily on white oil tanks. These instruments can

measure both oil as well as water/ sediment level in the tank.

5.2 level Xr (Radar)

This type of system is installed for level gauging on black oil tanks.

6. Method of Dipping

There are two methods for dipping a tank:

a) The innage method

b) The ullage method.

6.1 Innage Method

It is normally applied for white oils. Here, the distance between the datum plate

and the surface of the liquid is measured with the help of dip tape.

6.2 Outage Method (Ullage Method)

Lower the bob though the dip hatch slowly till it touches the top of liquid surface.

Lower it a couple of centimeters more. The difference between the readings taken at

the reference height mark and of the oil mark on the bob or tape gives the height of

the empty space in the tank. By subtracting this from the reference height, the

height of the liquid column in the tank is obtained.

7. Blending

Blending operation is a mixing of various streams under controlled condition to get

required characteristics of final stream which meets various parameter like Rvp,

octane no, sulfur content, aromatics, viscosity, flash point etc.

Advantages in blending operation:

• Uniform mixing and no layering

• Less no. Of tanks requirement

• Less time required for tank preparation

• Less number of samples for certification

• Power saving due less circulation

• Less quality give away

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7.1 Blending Station

Finished products: NAP, MS, GASOLINE, ATF, SKO, BH-HSD, HSD, ULSD,

LDO, HPS

Intermediate Streams: CRU feed, H2 Feed, IFO

Straight Run Products: LPG, MTO, Heavy Kero, Sulfur, and Bitumen

Following are some products that are received after blending

1. Motor Spirit: Lt. Naphtha (C5-90) + Lt. Naphtha ex-OHCU + FCC Gasoline +

Reformate + off spec.80 MT gasoline

2. Naphtha: C5-90 Naphtha ex-CDU + 90-140 Naphtha ex-CDU + Lt. Naphtha ex-

OHCU + Reformate

3. Superior Kerosene Oil: Kerosene ex-CDU + OHCU Kerosene

4. High Speed Diesel: Gas Oil ex-CDU + VDU Diesel + OHCU Gas Oil + VBU

Gas Oil + TCO ex-FCCU + Heavy Naphtha ex-OHCU + 120-140 Naphtha ex-

CDU + SKO ex-CDU/OHCU