1

ACKNOWLEDGEMENT

Industrial Training is an integral part of engineering curriculum providing

engineers with first hand and practical aspects of their studies. It gives them the

knowledge about the work and circumstances existing in the company. The

preparation of this report would not have been possible without the valuable

contribution of the ONGC family comprising of several experienced engineers

in their respective field of work. It gives me great pleasure in completing my

training at Gas Processing Plant of ONGC at Hazira and submitting the training

report for the same.

I express my deepest gratitude to Mr. A.K. MANDAL, DGM (Production) for

giving us the permission for orientation in operational area of plant. I am also

thankful to Mr. UMESH SHUKLA, CE(P) - RE CELL who supported us

constantly and channelize our work toward more positive manner.

Our sincere thanks to Mr. D.A. SUBBARAJU, Chief Engineer (Production)

for continuously guiding throughout various aspect, functioning, and processes

of the plant and their effective coordination and allotting us the appropriate

schedule to undertake the training.

A major contribution of this work would definitely be my parents who have

constantly supported me for my training in here and my friends who have

always been there as a pillar of strength.

And at last but not least we are also thankful to all the staff members of plant

for their kind cooperation and valuable guidance throughout the process of

work.

2

PREFACE

In any organization success or failure of the company depend upon 4 M’s i.e.

Materials, Men, Machine and Method. Today is the age of competition and an

organization cannot survive without satisfaction of its customers. Quality of

material is to be maintained in order to stand in the competitive market.

To be a perfect engineer one must be familiar with individual experience in

industrial environment. He must be aware of basic industrial problems and their

remedies.

While undergoing this type of industrial training at ONGC, Hazira, Surat

(Gujarat). I learned a lot of practical aspect. My theoretical knowledge was

exposed here practically. In this report I have tried to summarize what I have

learned in the ONGC plant. For preparing this report I visited the plant, referred

to the process and cleared related doubts to the responsible personal & inferred

to manuals and process reports.

This study has been primarily undertaken by me with a view to evaluate proper

working process in the organization. Born as the modest corporate house in

1956 as a commission ONGC has grown today into a full fledges integrated

upstream petroleum company with in house service capabilities and

infrastructure in the entire range of oil and gas exploration and production

activities achieving excellence over the years on the path of further growth.

3

TABLE OF CONTENTS

TOPIC PAGE NO.

HGPC: An Introduction 5

Gas Terminal Unit 10

Gas Sweetening Unit 17

Gas Dehydration Unit 27

Dew Point Depression Unit 32

Sulfur Recovery Unit 36

Condensate Fractionating Unit 44

LPG Unit 47

Kerosene Recovery Unit 55

ATF Production 57

Storage 58

Co Generation Unit 59

Offsites and Utilities 61

Water Treatment 64

Conclusion 65

4

HGPC : AN INTRODUCTION

Oil and Natural Gas Corporation (ONGC) is India’s biggest public sector

company. The mission of this company is to stimulate, continue and accelerate

exploratory efforts to develop and maximize the contribution of hydrocarbons to

the economy of the country. The discovery of Bombay High was an important

event in ONGC’s success as a result many oil fields were discovered in the

western offshore. Out of them South Basein proved to be phenomenal having

reserves of approximately 200 billion cubic meters of sour gas. To sweeten this

sour gas (make it sulphur free) and make it suitable for industrial use Hazira

Project materialized.

Hence a gas terminal was constructed in 1985 to receive the sweet gas. Initially

the gas received at this terminal was fed to KRIBHCO. Thus, entire Hazira

area saw the beginning of gas based industrial era. With increased demand in

gas and its availability in the south Basein ONGC, Hazira improved its

production capacity and infrastructure.

Hazira Gas Processing Complex (HGPC)

5

6

Process Flow Diagram

The gas processing plant of ONGC at Hazira processes gas coming from the

Vasai, south Basein, Heera, Panna, Mukta and other fields of the Bombay

offshore region, established in 1985, it is the largest gas processing plant of its

type in India with a production capacity of about 45 Mm3 of gas/day and

8000m3 of condensate/day. Spread over 705 hectares, with a boundary covering

11km, it has about 770 employees working for it presently and had an initial

capital expenditure to the tune of Rs.1300 crores.

Initially it was set up in 1985 to receive sweet gas from Bombay high but with

time it was seen that there were concentrations of sour gas that with the

incoming flow and it was then completely turned up into a sour gas plant. The

gas terminal was constructed in 1985 to receive sweet gas from Bombay High

through 217 km 36” & 42” submarine pipes from south basin to Umbrhat and

then 14 km pipeline on land till the gas terminal. The output of the plant

sustains the HVJ pipeline, which is a gas pipeline of more than 3000 km in

length and covers many states like Gujarat, M.P, Rajasthan, Haryana, U.P, and

Delhi. The plant also supports various fertilizer plants and power plants which

depend on the gas coming out of the Hazira plant.

The important process units within the plant (and visited) are:

Table 1.1 Main plants

7

UNITS Numbers Total Capacity

Gas terminal 2 lines 50 MMSCMD

Gas sweetening Unit (GSU) 8 trains 41 MMSCMD

Gas dehydration Unit (GDU) 7 trains 35.4

MMSCMD

Dew point depression Unit (DPD) 8 trains 39.9

MMSCMD

Liquefied Petroleum Gas (LPG) Plant 1 train 5.3 MMSCMD

Condensate Fractionating Unit (CFU) 7 trains 12600 m3 /day

Kerosene recovery Unit (KRU) 1 train 1.45 MMTPA

Sulphur recovery Unit (SRU) 6 Trains .

0.84 MMSCMD

Table 1.2 Main Utilities and Offsites

Products:

Main products of HGPC are as following:

Sweet natural gas

Liquefied petroleum gas

Naphtha

Superior Kerosene Oil

Aviation Turbine Fuel

High Speed Diesel

Sulphur

The input lines are feed to the GTU, which separates the gas from any

condensates. The gas then goes to GSU, where it is sweetened i.e. freed from

H2S .The condensate goes to CFU. From GSU, the gas goes to GDU, where the

moisture content from the gas is removed. The H2S gas which is ripped in GSU

is sent to SRU, where sulphur is recovered in elemental form. After GDU, the

gas goes to DPD unit and then to consumers. The condensate from CFU goes to

KRU plant and any LPG produced is sent to CWU for recovery by removing

H2S. The process is represented in the flow chart as shown above.

8

UNITS Numbers Capacity

Co-generation plant 3 gas turbines 57.6 MW

Raw water reservoir 4 reservoirs 8 lakh m3

Raw water treatment Plant

1 48000 m3/day

LPG Storage sphere 9 22500 m3

Naphtha storage tanks 7 112000 m3

NGL storage tank 1 16000 m3

Kerosene Storage tank 5 20000m3

HSD/ATF storage tank 2 2000 m3

Heavy cut /HSD tank 2 1000 m3

FW storage tanks 6 21000 m3

Consumers : IOCL, BPCL, HPCL, RIL, KRIBHCO, NTPC etc. ARN is exported out of the country.

9

GAS TERMINAL UNIT

The Hazira Onshore terminal begins at the point where South Basein-Hazira

Pipeline ends at the distribution outlet points for the gas and the condensate

streams. The terminal has facilities for

Receiving the two-phase flow Separating into Condensate and gas streams Condensate stabilization and gas distribution.

The two-phase flow is received in the slug catcher, where the gas and

condensate streams are separated. The gas is filtered, metered and sent to the

GSU plants for further processing. The separated condensate from the slug

catcher is metered and sent to the CFU plants for further treatment.

The gas is supplied in the existing 36” pipeline and 42” pipeline. The following main equipments are provided at this terminal:

1.Pig receiver

2.Pressure reducing valves

3.Slug catcher

4.Filtering unit

5.Metering unit

6.Blow Down

Table 2.1 Characteristics of pipelines

Characteristics 36” 42”

Offshore length 217 km 222 km

Onshore length 14 km 22 km

Design pressure 98 kg/cm2 120 kg/cm

2

Capacity 25 MMSCMD 25 MMSCMD

Valve Station Umbrhat, Danti, Bhimpore, Umbrhat, Bhata,

Magdalla, Hazira Abha

10

LOCATION OF HAZIRA

Tapti

HAZIRA

36”

231 km 42”

Mumbai

244 km

MP

Bombay

High Uran

South Basein

Gas Field

PIG RECEIVER

The pig receiving trap is a facility to recover the pig when scraping the line and to remove the foreign matter and residual solids entrained by the pig itself.

During the normal operation, the terminal inlet valve and pig receiving trap by

pass valve are kept open and the trap inlet, outlet valves the drain valves and the

vent valves kept closed. The trap is kept in depressurized condition.

When the pig is to be received:

The receiving trap is pressurized by opening the bypass valves of the inlet

valve. When the trap is pressurized to the operating pressure as indicated

by the pressure indicator and the outlet valves are opened and flow

established through the trap.

When the pig signal is actuated the operator is alerted about the approach

of the pig. The operator should now reduce the gas flow through the main

line and increase the flow through the receiver trap by throttling the trap

bypass valve to 75% of the initial opening.

Immediately after the actuation of the pig signal the trap inlet and outlet valves are closed and normal flow established through the bypass valve.

After isolating the pig barrel the drain valve is opened gradually to drain

the condensate into the condensate blow down drum. The pig trap

pressure will start falling. It is an indication that he trap is drained of

liquid. The drain is then closed and the vent valve is opened to elevated

flare to pressurize the trap.

The manhole cover should be opened carefully only after ascertaining that the trap is completely depressurized. The trap contents are emptied

out and the pig is then retrieved.

It is necessary to clean the pig trap and inspect he gas kits before bottling

up the trap. The pig receiving trap should be restored to the same

condition as before the launching of the pig operation. Pig indicator

switch to be reset in the field.

The residual solids and foreign matter collected as are result of the pig operation

have a tendency to catch fire when exposed to the atmosphere for a long time.

This is perhaps because of the heat generated due to the oxidation of nascent

iron in the waste.

There are a number of precautions that need to be taken at the terminal, during the pig operation.

12

Checking and pressure testing of pig receiving trap

Testing and recalibration of the pig signal sensors and the safety valve mounted on the receiving trap.

Keeping the Slug Catcher condensate level low to receive the pipeline

hold up liquid.

Maintaining the gas distribution to consumers at a reduced level because as the line is filled with the condensates pushed by the pig, the plants

downstream would remain without gas until the pig arrives.

Taking care during condensate drain from trap to blow down drum at the time of depressurization. To avoid freeze up in the blow down system the

electric heating elements on the pipe should be energized.

Complete depressurization of receiving trap before the manhole is opened.

Proper disposal of foreign and residual matter collected in the trap during

the pig operation.

The frequency of pig operation depends upon a number of factors:

Gas/condensate flow rate

wax content in the condensate

Hydrogen Sulphide content in the gas

SLUG CATCHER

Downstream of the control valves is the slug catcher, which has existing 48

fingers and 6 new fingers. During normal operation phase-1 slug catcher (24-

fingers) separates condensate of 25 MMSCMD sour gas (approximately) from

42”line. Phase-2 slug catcher (24 fingers) separates gas and condensates from

13

36” line. There are three phases, two works at a time and one remains standby.

However, during pigging of the 42” line, all the 48 fingers will be lined up to

receive the liquid hold up in the 231 km line. During this time the 36” lines

shall be lined up to the 6 new fingers to separate gas and condensate.

Each finger has:

Length 498 m

Diameter 48”

Angle of separation 5% slope

Angle of separation 0.5% slope

Area of storage 11000 m3

Total capacity 22000 m3

Slug catcher consists of:

Condensate storage section – for storage of incoming gas

Separating section – for separating the gas and liquid condensate

Primary riser – close to the inlet side of the slug catcher, allows separated gas to come out during normal flow

Secondary riser– positioned approximately in the catcher, diverts small

amount of gas coming with liquid, also it acts as escape route for gas lift

in this area during arrival of condensate slug during pigging

Equalizing riser – positioned at the end of storage area, to prevent liquid

agitation and entrainment of product by current flow of gas and liquid

towards primary header.

Gas and condensate from pig receiver is fed to slug catcher separation section

where due to slant line liquid accumulate at lower section and the gas is

separated. Initially line is steeper and has a slant ratio of 1: 5, then it becomes

gradual and slant ration become 1:500. The separated gas goes to gas filtering

unit through primary risers. Condensate, which is removed from gas, is stored in

slug catcher and for further separations of any entrained gas. The separated gas

from primary riser, secondary riser and equalizing riser combines together and

goes to filtering unit. Slug catcher-3 has 6 fingers. Condensates, which are

collected, in each finger goes to condensate header and further goes to

condensate metering unit.

14

GAS FILTERING

The gas from slug catcher is sent for filtration in which any condensate

entrained along with the gas is separated. Sour gas from Phase-1 slug catcher is

sent to existing filtration unit and sweet gas from Phase-2/Phase-3 slug catcher

is sent to new filtration unit. For normal operation, two filters will be operated

to cover the 256 MMSCMD of sour gas and one is standby. New filtration unit

has three filters. Each filter can treat a maximum of 580,000 SCMH (13.92

MMSCMD) sweet gas to remove 99% of 10µ solid particles. For normal

operation, two filters are operated to cover sour gas. Sweet gas which is

removed of solid particles goes to metering unit and then goes to DPD.

Each filter is equipped with liquid automatic discharge, which is controlled by

the liquid level inside filter itself. The condensate from sweet and sour gas is

metered separately. Gas filter separates gas from condensate particles with

principle of centrifuge.

Gas filter has 200” diameter cyclones. Feed is injected tangentially into the

upper part of the cylindrical section and develops a strong swirling motion with

the cyclone. Liquid containing the fine particle fraction is discharged out

through the under flow.

Gas filters equipped with differential pressure gauge to monitor any leakage.

The liquid coming out of the filters will be sent to a single collecting line,

connected with both the line conveying the condensate to blown down and with

the feeding line of the stabilization plant. The condensate from sour gas is

metered separately.

METERING UNIT

There are four sour gas metering units and one condensate metering unit. Sweet

gas from gas filtering unit goes to sweet gas metering unit to measure the flow

rate with compensation of pressure and temperature. Each metering unit

consists of flow meter, pressure gauge and temperature gauge. Condensate from

Phase -2 /Phase-3 slug catcher feed to condensate metering unit and measure the

condensate flow rate. After then, it goes to condensate fractionating unit.

15

BLOW DOWN

Blow down is a process through which water sludge, foreign particle and

unwanted material is removed from pipeline. The gas travels a long distance

from offshore to Hazira plant through pipelines. During this line take turn and

become slant due to gravity. Heavier molecules and foreign solid particle get

accumulate there. To remove them from the pipeline a pig is send from offshore

terminal. It travel through pipeline and scraps all the accumulated sludge are

received at the pig receiver. The Pig is taken out and the pig receiver cleaned.

This process is done once in a year.

16

GAS SWEETENING UNIT (GSU)

The main purpose of this gas treatment step is to remove the H₂S from the sour

gas with a high severity, and at the same time, to limit CO₂ co-absorption to the

minimum required and in any case, to not more than 32 %.Two Gas Sweetening

Trains of Phase-3 A can handle a total of 12.6 MMSCMD of sour gas. The

remaining trains of GSU can handle 28 MMSCMD with 5 trains operating and

one train standby. This makes a total capacity 40.6 MMSCMD with one train of

capacity 5.6 MMSCMD as standby. The plant has been designed such that the

maximum capacity for each gas sweetening train is 40% of the design capacity.

17

In the sweetening process, gas is washed with aqueous solutions of MDEA. The

MDEA and TEG trains are connected with one another by a pipe rack supplying

products (raw gas, desulfurized and dried gas) and required utilities.

GAS FEEDSTOCK SPECIFICATIONS:

The following mixed gas composition (mix of slug catcher gas and CFU off-

gas) has been considered for the design of GSU and GDU. (Based on design of

phase-3A)

Pressure at Battery Limits : 96-54 kg/cm² abs

Temperature at Battery Limits : 20-33 °C

Gas sweetening train will have a maximum operating pressure of 77 kg/cm². A

pressure control valve and heating device upstream of the pressure valve will

prevent hydrate formation. H₂S and CO₂ content will vary depending on

conditions.

PRODUCT SPECIFICATION:

The product from each Gas Sweetening train will meet the following specifications

Sweet and Dry Gas:

H₂S content : 4 ppm volume maximum.

Pressure at Battery Limits : 74.9 – 51.9 kg/cm² abs.

Temperature at Battery Limits : 40°C.

Rich MDA Flash Gas:

H₂S content : 4 ppm volume maximum.

Pressure at Battery Limits : 4.5 kg/cm² abs.

Temperature at Battery Limits : 48-55°C.

18

Acid Gas:

Hydrocarbon content will be minimized.

Pressure at Battery Limits : 1.9 kg/cm²

Temperature at Battery Limits : 50°C

PROCESS DESCRIPTION:

In the sweetening process, gas is washed with aqueous solutions of MDEA and

TEG trains are connected with one another with a pipe rack supplying products

(raw gas, desulphurized and dried gas) and required utilities.

19

MDEA PROCESS PRINCIPLES:

The selective removal of H₂S is made by washing the sour gas with an aqueous

solution of Methyl-Di- Ethanol-Amine (MDEA).The process principles are

similar to the well known SNPA-DEA process. The only difference is the

behavior of the ethanol amine used. Methyl-Di-Ethanol-Amine (MDEA) is

tertiary amine, which does not react easily with CO₂. The selectivity is so

prompted by using the differences in the reaction rates between both H₂S and

CO₂ and tertiary amine. First the case a primary or secondary amine (mono-

ethanolamine or di-ethanolamine) whose reactions with the acid components

H₂S and CO₂ are similar is investigated.

H₂S reacts to give amine hydrosulfide:

H₂S + R₂NH HS¯, R₂NH⁺ _________________ (1)

CO₂ can react directly with amine to form an amine carbonate:

CO₂ + 2R₂NH R₂NCOO¯, R₂NH₂⁺ _______________ (2)

But CO₂ can also react with water or hydroxyl ions to form carbonic acid or

bicarbonate ions:

CO₂ + H₂O H₂CO₃ ______________ (3)

CO₂ + H₂O HCO₃¯ ______________ (4)

These acids then react with the amine to form amine bicarbonate (HCO₃¯,

RNH₂⁺) and amine carbonate (CO₂, (R₂NH₂⁺)₂).As regards kinetics, three types

of reactions can be distinguished Reaction(1) whose rate is infinite,

Reaction(2) whose rate is moderate, depending on amine

Reaction(3) and (4), known to be slow

It is known that using MEA or DEA the absorption rate CO₂ in the absorber

may be lower than the absorption rate of H₂S; however CO₂ removal is

regarded as complete. The case of tertiary amine is different. As a matter of

20

Fig: High pressure absorption

fact, the molecular structure of the tertiary amine prevents the direct reaction of

CO₂ with carbonate formation (reaction (2)).

Contact time depends on: The gas flow rate

The liquid height above the active plant area

The number of plates in the absorber

The first two parameters cannot be acted upon. The third parameter (plate

quantity) allows adjusting contact time according to the feeding conditions and

required performance.

ABSORPTION SECTION:

Slug-catcher derived raw gas is first heated in steam heater. Then it is passed

through the pressure regulating control valve. Its temperature is maintained

above 25 °C by controlling the heater steam flow. This raw gas is then mixed

with the condensate treating unit derived raw gas, which is made up of light

hydrocarbon fraction in the raw condensate. This raw gas mixture passes

21

through a knock out drum where liquid carryover (water, hydrocarbon) are

retained to be pumped to the condensate treating unit. Upon leaving separator

raw gas enters an amine absorption column where it comes into contact counter

currently with the aqueous solution of MDEA. The absorber column includes

14 valve trays. The lean MDEA solution at 45 °C at the column upper part.

Different liquid feed possibility to the column allows selecting adequate

number of the trays to obtain the required results taking into account about feed

gas quality and operating conditions. The selected feed position could be to the

trays 1, 3, 5, 7, or 9 and the switching over from one to another is done

manually.

The MDEA feed nozzles are arranged such that the liquid feed is fed to the

down comers of trays (1, 3, 5, 7 and 9) and not the trays themselves. The upper

tray is dry and retains the major part of carryovers. The total lean MDEA

solution flows to the column under flow control valve. At the top of absorber,

treated gas contains less than 4 ppm volume of H₂S. Temperature ranges from

40°C to 44°C. The gas is cooled to 38°C by passing through a water cooler.

Liquid phase resulting from cooling (condensed water+ vesicular amine

carryover) is separated in the treated gas knock out drum and returned to rich

amine circuit at a lower pressure. Treated gas is piped to TEG drying unit.

AMINE REGENERATION SECTION:

The stream of the rich amine solution is recovered under level control valve

from the bottom of the absorber and piped to the rich amine flash drum . The

sour flashed gas from this drum contains about 200 ppm (vol.) H2S. In order to

meet the fuel gas specifications (less than 4 ppm vol. of H2S) this sour fuel-gas

is brought into contact with a small lean MDEA flow in a 6 valve tray

absorption tower placed on the top of the rich amine flash drum .The rich amine

solution flows from the flash drum to the rich/lean amine exchanger. The rich

amine flash drum level control valve is located downstream of the exchanger in

order to minimize the solution degassing by the exchanger plates.

22

MDEA solution stripping is accomplished in the regenerator by the vapor

generated from the reboiler .The lean amine collected at the bottom of the

regenerator is routed through amine/amine exchanger and cooled to 45 C in a

lean amine cooler and sent to a large lean amine storage tank. The hot acid-

gas/steam mixture from the overhead of the regenerator is cooled to 50 C in

condenser where water vapor condenses. This condensed vapor is separated in

the reflux drum and pumped back to the top section of the regenerator. The trays

are provided for washing the acid gas with reflux water in order to minimize

amine carryover. Acid gas is sent to an acid gas header through a pressure

control valve, which maintains a 2.0 kg/cm2 minimum pressure on top of the

reflux drum .From the storage tank , lean amine is pumped back to the absorbers

by the main amine charge pump .The discharged amine stream is split into two

parts through flow rate control valves: a main stream flows to the high pressure

Absorber and a smaller one to the fuel-gas absorber.

23

MISCELLANEOUS:

Storage section:

The total amine circulating stream is drawn-off toward a large storage tank.

This tank has several functions:

- Its capacity allows the recovery of the total amount of amine in

circulation when the train is drained for maintenance operations.

- In normal operations, it has a regulating effect on the disturbances caused

by the level control valve actions on the rich amine and the lean amine

circuits It simplifies the pure solvent make-up and control of the MDEA

concentration in the lean solution

- It effects an efficient decantation of the amine solution before filtration.

MDEA is very sensitive to oxygen whose contact produces acidic elements. In

order to avoid direct contact with air, the storage tank is equipped with a gas

blanket. Inert gas is normally used as blanketing gas. However the inert gas at

Hazira plant contains residual amounts of oxygen (0.5%) making it unsuitable

for this purpose. Even though the quality of the fuel gas available from the fuel

gas header is rather unattractive due to the presence of large amounts of CO2,

which may cause undesirable effects on the lean amine quality, this fuel gas was

finally preferred. SNEA(P) confirmed that the expected lean amine degradation

due to the CO2 reaction with MDEA was very small considering the mass-

transfer conditions at the gas liquid interface in the storage tank.

FILTRATION PACKAGE:

This filtration package is designed to treat approximately 10% of the total lean

amine flow. It consists of three filters:

A pre-coat filter

An activated charcoal bed A cartridge filter

24

A side stream, approximately equal to 10% of the total lean amine flow is

drawn off the storage tank by the Lean Amine Filter Pump. It passes under flow

control through the Pre-Coat Filter . The pre-coat filter is designed to remove

solid particles such as iron sulphides, and iron carbonates from the lean amine.

Downstream of the pre-coat filter the stream splits. The main stream returns to

the amine storage tank. A side stream, approximately equal to 1 % of the total

lean amine flow, is taken off and passes under flow control to the Activated

Charcoal Filter . In the activated charcoal filter any further degradation products

and hydrocarbons are removed. This stream then passes through a Cartridge

Filter where any entrained activated charcoal is removed. It joins the outlet of

the pre-coat filter and returns to the amine storage tank. All amine solution

collected in the Sump Drum (see the following section) is pumped to the suction

of the lean amine filter pumps .

SUMP DRUM:

The MDEA section is provided with a sump drum to collect the drips and drains

from the unit. All low point drains from columns, vessels, pumps etc. are piped

into where the MDEA is collected. If part or all of the MDEA unit are

shutdown, then the amine solution is first drained to the sump drum, pumped to

the amine filter pumps and passes through the filtration package before going to

the storage tank . The sump drum is fitted with a pump that starts automatically

when a high level is reached and stops automatically on low level. The sump

tank is also blanketed with fuel gas to prevent solution by degradation of the

MDEA due to ingress of oxygen.

ANTIFOAM PACKAGE:

An antifoam package is provided for the injection of antifoam chemicals into

the MDEA circulation system, at the suction of the amine charge pump . This

antifoam package is common to all sweetening trains. Based on the LACQ Plant

experience, the antifoam chemical is mixed with stabilized hydrocarbon

condensate in a storage drum. Sufficient amounts of aromatic hydrocarbons are

necessary in this condensates for a good dispersion of the antifoam product.

25

Circulation pump ensures a sufficient liquid velocity in the distribution line to

prevent solid deposits. A normal injection flow rate, adjusted by manual valve

and controlled by a Rota meter and a rapid injection flow rate through a control

valve operated from the control room panel are provided in each sweetening

train.

FLARE SYSTEM:

A common flare header, Flare KO Drum and flare blow down pumps are

provided within B/L for trains of both, sweetening & dehydration units. All the

hydrocarbon vapors/liquids collected from vents and pressure relief valves will

go to the flare KO Drum through the flare header. From there the gas goes to

the flare stack through an off-sites flare header. The liquid collected from Flare

KO. Drum will be pumped through to slop tank located in off-sites.

TURNDOWN RATIO:

Overall turn down ratio to 40% of the design capacity can be obtained without

any special additions to the standard features of the equipment. With this turn

down ratio of 40%, design sweetening and drying performances will be

maintained, with an increase in the specific energy consumption.

26

GAS DEHYDRATING UNIT (GDU):

The removal of water from sweet gas is made by contacting the gas with a tri-

ethylene glycol solution. Due to their hygroscopicity, glycols are widely used

for this purpose. The hygroscopicity is directly related to the solution

concentration. So water vapor will be absorbed by a glycol solution as long as

the partial pressure of the water in the vapor phase exceeds the vapor pressure

of the solution. Furthermore, the molecular compatibility of the couple solvent-

solute plays an important role. So, greater the molecular attraction between

solvent and solute, lower the vapor pressure of the water. In liquid state, water

is highly associated through hydrogen bonds. Among all the glycols, tri-

ethylene glycol represents the optimum choice between hygroscopicity, price,

losses and regeneration ability: in this case, the required specification is 85 kg

of water/million Nm³ of gas.

DESIGN CAPACITY:

The design capacity for each gas dehydration train of 46 & 47 is 6.3

MMSCMD of sweet gas. Other GDU trains from 41 to 45 are having capacity

of 5.697 MMSCMD each. The plant has been designed such that the minimum

capacity for gas dehydration train is 40 % of the design capacity.

PRODUCT SPECIFICATION:

The product from the gas dehydration unit will meet the following specifications:

High Pressure Case:

H₂S content : 4 ppm vol. maximum

H₂O content : 85 kg/mm Nm³ maximum, (-7°C dew pt.)

Pressure at battery limits : 74 kg/cm²

Temperature at battery limits : 40°C

Low Pressure Case:

H₂S content : 4 ppm vol. maximum

27

H₂O content : 50 kg/mm Nm³ max. (-11°C dew point)

Pressure at battery limits : 51kg/cm²

Temperature at battery limits : 40°C

PROCESS DESCRIPTION

Sweetened gas is dried by washing with TEG. The MDEA Gas Sweetening

Trains and the TEG Gas Dehydration Trains are connected with one another by

a pipe rack- supplying products (raw gas, de-sulfurized and dried gas) and

required utilities.

Treated gas leaving the gas-sweetening units enters the dehydration unit. It

pressure ranges from 74.9 kg/cm2 a to 51.9 kg/cm2 a, and its temperature is

380C. The dehydration is supposed to be run with same liquid flow while the

pressure is varying. So the gas is dried to 85 kg/million Nm3 (-7

0C dew point)

in the higher-pressure case and to 50 kg/million Nm3 (-11

0C dew point) in the

lower pressure case.

ABSORPTION SECTION:

Sweet gas at the TEG unit battery limit enters to the Feed Gas KO. Drum where

entrained or condensed liquids are removed. To avoid or minimize condensation

of liquids due to ambient cooling, lines going from the gas sweetening trains to

the gas dehydration trains are insulated. Liquid collecting in the base of surge

drum are sent to the rich amine flash drum under level control by LCV.

The gas leaving the top of surge drum then flows to the absorption column

where it is contacted with the lean tri-ethylene glycol solution (TEG) (99.7%

wt). The column is fitted with 9 bubble cap trays, 8 of which are absorption

trays and a top dry tray (Tray No. I).The purpose of this dry tray is to retain the

major part of carry-over to reduce the glycol losses. The feed gas enters the

lower part of the column below the bottom tray (Tray No. 9) and is scrubbed

by the lean glycol as it passed up the column counter-current to the glycol,

which enters above Tray No. 2.

The scrubbed gas leaving from top of passed to the dried gas scrubber where

entrained glycol carry-over is removed. The gas leaving from top is passed

through the glycol unit. and hence to the hydrocarbon dew point depression

units. Rich glycol collected in the bottom of the Absorber is sent under level

control to the Rich Glycol Degassing Drum. Before entering degassing drum

this stream is combined with the glycol from the scrubber .

29

Due to the lower operating pressure (10kg/cm2) of the Degassing Drum

absorbed hydrocarbons are released from the glycol. The released light

hydrocarbons are sent to the fuel gas header. If insufficient gas is available from

for use as stripping gas then this will be made up directly from the sweet, dry

gas stream from the gas scrubber.

The Degassing Drum is fitted with 2 skimming lines for the removal of any

condensed hydrocarbons, which accumulate on the surface of the glycol. These

condensed hydrocarbons must be drained manually to the flare header.

TEG FILTRATION PACKAGE:

Tri-ethylene glycol will not exhibit a high degree of foaming if it is kept free of

surfactant-type materials. These materials may be introduced through

compressor oil, plug-cock lubricant, and corrosion inhibitors used in either the

formation or in the gas gathering system. So such products must be chosen

carefully.

Special attention has been given in the design to foaming and fouling by use of:

TEG degassing and hydrocarbon condensate removal.

Cartridge filter on the full rich glycol stream with a standby unit. Charcoal filter on 30% of the rich glycol stream.

Each of the cartridge filters is designed to take 100% of the glycol flow, with

one filter in service and the second on standby. The cartridge filter removes any

solid particles from the glycol stream. An activated carbon filter is located

downstream of the cartridge filter and is designed to take up to 33 percent of the

glycol flow with the major stream bypassing the charcoal filter under control of

Flow valve.

REGENERATION SECTION:

Before entering the regenerator column to be regenerated the glycol is

preheated in a heating coil at the top of the regenerator. The flow of glycol to

30

the heating coil is controlled by a 3-way valve TV-1215 which controls the top

temperature of column from 97.8oC to 98.4

oC. Temperature controller TV-

1215 opens to allow cold rich glycol to flow to the heating coil. As the glycol

flows through the coil it cools and partially condenses the hot vapors rising up

the column there by reducing the overheads temperature and providing and

internal reflux for the column. The glycol, which is not required to maintain

column top temperature, flows through the by-pass port of TV-1215 and

rejoins the preheated glycol stream from the heating coil.

The rich glycol stream then flows to the rich/lean glycol plate type exchanger

where it is heated from 52oC to 175

oC by exchange with the regenerated lean

glycol" before entering the glycol regenerator column.

The regenerator column is an atmospheric column, which contains 4 bubble cap

type trays and the previously mentioned heating coil. The temperature in the

regenerator reboiler is controlled at 204oC by TV-1212, which controls the flow

of H.P. steam. Glycol from the reboiler overflows to the stripper, which is end-

mounted on to the reboiler. Then it is stripped by hot dry fuel gas to achieve a

concentration of 99.7% wt. The fuel gas is preheated in a second coil of the

reboiler before it enters the stripper.

The hot, stripped glycol from the base of stripper flows by gravity through the

rich/lean glycol plate type exchanger, where it is cooled from 204oC to 80

oC by

heat exchange with the cold rich glycol feed to regenerator, before going to the

surge drum. The gases from the top of the stripper are piped to the reboiler

and the surge drum to maintain a slight positive pressure in these vessels.

The lean glycol collected in the surge drum at 800C is pumped by the lean

glycol injection pumps to the trim cooler, where it is cooled to 45 0C by

exchange with cooling water, it then returns to the absorber.

31

DEW POINT DEPRESSION UNIT (DPD)

The dew point depression unit is designed, as the name suggests lowering or

depressing the dew point of the gas. This objective is achieved by lowering the

gas temperature well below the minimum temperature which the gas may attain

in the HVJ pipeline.

PROCESS DESCRIPTION:

Sweet and dehydrated gas is treated in this DPD unit to lower hydrocarbon dew

point of gas well below the minimum temperature which the gas may attain in

the HVJ pipeline. Expected minimum temperature that the gas may attain in

HVJ pipeline is 11°C. Dew point depression unit is designed to chill the gas up

to 5°C and recover condensate formed due to gas chilling. The process

description for dew point depression unit is described in two sections:

1.Chill down section

2.Propane refrigeration section

CHILL DOWN SECTION:

The feed gas is first cooled by outgoing (dew point depressed) product in the

gas-gas exchangers and it is then finally cooled to 5°C in a gas chiller by the

evaporating refrigerant propane. The gas temperature at the outlet of chiller is

controlled by the bypass control valve.

Provision is kept to inject tri-ethylene glycol upstream of the gas-gas

exchangers and when required to avoid freezing problems in chill down section

which may crop up during malfunctioning of dehydration unit. Normally TEG

injection shall not be done.

The chilled gas is sent to the filter-separator to knock out hydrocarbon

condensate, traces of water and glycol (if any) formed. The separated gas from

the filter-separator exchanges its cold partially with the incoming feed gas in the

32

gas-gas exchangers. The gas is then sent for transportation in HBJ pipeline.

Hydrocarbon condensate from filter-separator is pumped by the condensate

transfer pumps to LPG unit / Condensate fractionating unit or Slug catcher

condensate header on level control valve.

PROPANE REFRIGERATION SYSTEM:

Propane refrigeration system has been provided in the DPD unit to supply

refrigeration required in the gas chiller. Once the system is filled with liquid

propane it operates in a closed cycle and very little makeup of propane from

external source is required. Single stage refrigeration is provided.

33

Propane from accumulator at 45°C flows over to propane sub-

cooler where it is sub cooled by cooling water to 40°C. Then it flows over to gas chiller through level.

Refrigerant propane after evaporation in the chiller flows over to

propane compressor via suction knock out drum .

Propane vapor is then compressed by reciprocating propane compressor driven by electric motor.

The compressed propane vapor is condensed in the propane

condenser and taken to the accumulator for reuse in the propane recirculation cycle.

The temperature of the bypassed propane vapor is maintained at 0°C by

spraying liquid propane in a quench nozzle via a temperature control valve. In

each train, two refrigerant propane compressors are provided. One compressor

will be in operation and other will be stand- by.

CHEMICAL SYSTEM: Glycol (Methanol) system:

A common glycol (Methanol) tank with glycol injection pumps is provided

within B/L in phase-1. Glycol injection being an intermittent requirement, the

same header is extended for the two trains. Pure glycol (Methanol) will be

received in tank from off-sites. This glycol is used to prevent/melt hydrates

which may form in the process unit during process upset conditions.

EFFLUENT SUMMARY:

It comprises mainly of vessels / filter–separator drains, floor washings and

storm water effluents. As such, during normal operation there will be no release

of continuous effluents. While during shut down or mal-operation, intermittent

release of oily water from filter-separator can take place. Another source of

34

leakage is occasional dripping of lubricating oils around the rotating equipment

such as propane compressor and condensate transfer pumps.

During floor washing, waste-water is generated and it is likely to be

contaminated with oil. During rainy season, there could be chances of rain /

storm water also getting contaminated with oil.

Gaseous effluents: Gaseous effluents come mainly from vessels and safety valve discharges.

During normal operation there will not be any gaseous effluents,

excepting small quantities from occasional gas venting from some

equipment.

35

SULPHUR RECOVERY UNIT (SRU)

BLOCK DIAGRAM - GSU / SRU

Sweet Gas Vent Gases

Acid Gas

Air

SRU

MDEA GSU (LO-CAT Solution) Chemicals

MDEA Regeneration

Sulphur

Fig. 1.1

The SRU is designed to treat 35,000 Nm³/hr of acid gas from the gas

sweetening unit. Each train is capable of treating up to 7000 Nm³/hr of acid gas

with a hydrogen sulfide concentration ranging between 0.3 and 5.2 mole percent

i.e. 3000 to 52000 ppm of H₂S. The sulphur production will range between 0.7

to 12.2 metric tons per day per train. Under normal circumstances four trains

will operate at full capacity while two remains on standby/under maintenance.

The SRU of Hazira Plant consists of 6 Trains which came up in phases – Tr. 61,

62, 63 (Phase I); Tr. 64, 65 (Phase II) and Tr. 66 (Phase III). In addition to

these, there is one Incinerator (Tr. 60), which came up with Phase I.

36

FEED SPECIFICATIONS:

The acid gas composition will vary with variation in sour gas throughout ,

arrival pressure and temperature at Hazira. The acid gas has the following

properties:

COMPOSITION VOLUME %

H₂S 0.3-5.2

CO₂ 92.3-85

H₂O 6.9-8.5

Hydrocarbons 0.5-1.0

Pressure (kg/cm²) 0.8-1.0

Temperature (°C) 45-50

Flow (Nm³/hr) 7000 per train

PRODUCT SPECIFICATIONS

Sulphur produced by the SRU is a consequence of melting an environmentally

accepted gaseous effluent.

The sulphur is expected to have the following characteristics :

Sulphur Purity 99.9 %

Moisture 0.1 %

Ash Less than 400 ppm

Organics Less than 500 ppm

As, Se, Te Commercial nil

Fe 250 ppm maximum

Form Solid, in flakes form

Packaging 25-30 kg bags

37

PROCESS DESIGN:

The LOCAT unit will reduce the H₂S with a liquid phase catalytic reagent,

which absorbs the H₂S and converts it to elemental sulphur and H₂O. Details of

the theory and operation of the LOCAT unit designed for this application are

contained in the following sections.

THEORY OF OPERATIONS:

The LOCAT process brings about the following reactions to produce solid

elemental sulphur from hydrogen sulphide gas.

Absorption:

H₂S( g ) + H₂O( l ) H2S( l ) + H₂O( l ) ______________ (1)

First Ionization:

H₂S( l ) H⁺ + HS¯ ______________ (2)

Second Ionization:

HS¯ H⁺ + S-2

______________ (3)

Oxidation by Metal Ions (Fe⁺⁺⁺) :

S-2

+ 2Fe⁺⁺⁺ S₍s₎ + 2Fe⁺⁺ ______________ (4)

Overall Reaction:

H₂S₍g₎ + 2Fe⁺⁺⁺ 2H⁺ + S + 2Fe⁺⁺ ______________ (5)

The metal ions must then be deoxidized in the regeneration part of the process

using O₂ from either ambient air (anaerobic process) or the process gas itself

(aerobic process).

38

Absorption:

O₂₍g₎ + 2H₂O( l ) O₂₍l₎ + 2H₂O( l ) ____________ (6)

Regeneration of Metal Ions:

½O₂₍ l ₎ + H₂O + 2Fe⁺⁺ 2(OH)¯ + 2Fe⁺⁺⁺ ____________ (7)

Overall reaction:

½O₂₍g₎ + H₂O + 2Fe⁺⁺ 2(OH)¯ + 2Fe⁺⁺⁺ ____________ (8)

Now, adding equations (5) & (8) together gives

H₂S₍g₎ + ½O₂₍g₎ + H₂O S₍s₎ + 2H₂O₍l₎ ____________ (9) OR

H₂S₍g₎ + ½O₂₍g₎ S₍s₎ + H₂O₍l₎ ____________ (10)

In this overall reaction, the metal serves to transport electrons from the absorber

side of the reaction to the regeneration side, and it is necessary to supply at least

two metal ions per atom of sulphur produced. In this sense, the metal ions are a

reagent. However, they are not used up in the overall reaction and serve as a

catalyst for the reaction of H₂S and O₂. Because of this dual function, the metal

ion concentrate, ARI-310 solution is described as a catalytic reagent. The auto

circulation LO-CAT® unit addressed in this manual utilizes the differential

density between two aerated liquid phases at different aeration rates to circulate

ARI-310 solution from the oxidizer section to the absorber section of the vessel.

The solution absorbs H₂S and small amounts of CO₂ and is absorbed into the

solution. This absorbed oxygen regenerates the catalyst. Equation (10) indicates

that there is no net production of H⁺ ions of OH¯ ions and that the pH of the

solution is not changed by the basic reaction.

39

FLOW DIAGRAM OF SRU

40

41

PROCESS DESCRIPTION:

Feed gas enters Unit 61 through flow control valve and in to the feed gas knock

out drum, which removes any condensate entering the unit. This condensate is

removed on level control / manually and sent off to the MDEA Sump Storage

tank. Low level switch will automatically close flow control valve to prevent

the acid gas from entering MDEA Sump Storage tank. The scrubbed acid gas

continues to the oxidizer / absorber Absorption of H2S is accomplished by

contacting the sour gas with basic solution of ARI-310 catalytic reagent in the

center well of the liquid full Absorber / Oxidizer. The process gas is introduced

into each of the four (4) absorber sections through four (4) 8” process gas

Spurger assemblies. Process gas leaves the absorber section of the vessel

through a perforated gas-liquid distributor plate at the top of the center well is

mixed with spent air from the oxidizer section of the vessel and is finally vented

to the atmosphere through the Cooling Tower. An H2S analyzer located in the

discharge neck of will activate an alarm when the H2S concentration reaches 15

ppm. Circulating Lo-cat solution is introduced into the absorber section of the

vessel by spilling over the center well wall through the gas-liquid distributor

plate.

The sulfur created by the reaction forms in the absorber section of the vessel.

Since the density of solid sulfur is approximately twice that of water, the formed

sulfur will settle down into the settler section of the vessel. A small amount of

fine sulfur particles will continuously circulate with the liquid catalyst solution

but this will equilibrate at a low enough concentration to not interfere with H2S

removal. The reduced solution from the absorber section of the vessel

underflows the center well wall and enters the oxidizer section.

As the reduced solution proceeds through the oxidizing section, it is regenerated

by contact with air. The injection of air also serves the purpose of providing the

driving force necessary to circulate the Lo-cat solution by lowering the bulk

density of the oxidizing section.

The solution is completely regenerated by the time it reaches the top of the

oxidizer section. Regenerated solution spills over the top wall of the absorber

center wells and proceeds downward making counter current contact with

upward flowing acid gas bubbles, thus completing the oxidation / regeneration

cycle. Sulfur particles produced in the absorber section of drop out into the

42

settling section. The sulfur particles are about two times the density of water and

rely on gravity and on the centrifugal force resulting from the circulation of

LOCAT solution to settle out into the cone section . Sulfur will accumulate in

the cone section to about a concentration of approximately 10-wt%. A

continuously operating scraper prevents bridging of sulfur off the inside walls of

the cone. An air blast Spurger ring directs air jets towards the wall of the cone to

prevent sulfur bridging in the lower section of the cone (below the scraper).

Sulfur is withdrawn from the bottom cone of the settler section and pumped to

the sulfur melter section of the unit by one of the two mono type progressive

cavity positive displacement pumps .Liquid sulfur exiting the sulfur separator,

flows to the sulfur surge tank where it is stored the storage capacity of this tank

is about 7 days.

CHEMICAL REQUIREMENTS:

Chemical make-up is normally required in order to maintain the Lo-cat solution

at its most desirable chemical composition. The Lo-cat process uses the

following make-up chemicals:

ARI - 310M Surfactant

ARI - 310C Biochem

KOH

The addition of these chemicals on a regular basis has been provided for in the

process design. However, chemical addition should be governed by the

chemical composition of the circulating Lo-cat solution.

KOH solution is added to the process to maintain the required pH for H2S

absorption.

43

CONDENSATE FRACTIONATION UNIT (CFU)

Condensate fractionating unit is designed to remove H₂S and to recover LPG &

NGL from slug catcher condensate. The design capacity for the Gas Condensate

Fractionation Units is 51.5 tons/hr or 75 m3/hr of sour condensate. This feed

comes from Slug-catcher. There is also stream of sweet condensate from Dew

point depression Units (DPD) which can be processed in CFU along with the

slug-catcher condensate. The plant has been designed such that the minimum

running capacity for each condensate fractionating unit is 40 % of the designed

capacity i.e. 30m³/hr. each train is independently operated with all trains

continuously in service.

PROCESS DESCRIPTION:

The fractionation unit consists of:

Condensate receiving system H₂S stripper

Condensate off gas compression LPG column

Condensate Receiving System:

The condensate as it comes from the slug catcher is heated in a condensate

preheater and received in surge drum under level control through LCV. The

preheater uses LP steam to heat the condensate up to 33°C to 36°C to avoid any

hydrate formation. Hydrate formation is possible if there is high pressure drop

across valves. The flash vapor from the surge drum is taken to gas sweetening

unit directly (bypassing compressor) when condensate inlet pressure is at 80

kg/cm² or more. Below 80 kg/cm², the pressure is maintained 2 kg/cm², below

the inlet pressure in the surge drum to allow differential for incoming liquid and

the vapor is routed through the compressor system. Any free water droplets gets

separated in the surge drum and are collected in boot. Water level is drained

through interface level control mechanism. The condensate in the surge drum is

taken into condensate transfer pumps (one operating & one standby). This pump

is provided to generated sufficient head and flow to avoid any condensate

44

flashing in the down steam filter coalesce. Two units of cartridge type filter-

coalesce are provided (one operating & one standby). The filtering elements of

the filter are being used for filtering out any scale/dust/debris/iron sulphides /

black material which may entail during pre-commissioning/commissioning,

pigging operation of the trunk lines. The coalescer element is used for removal

of free water. The free water collected in the boot and is drained through

interface level control mechanism. The condensate flows further through flow

control valve into the stripper column top tray. This is designed to maintain a

back pressure to ensure that no flashing occurs in the filter chamber. Dew point

depression unit’s condensate can also be processed in CFU besides LPG plant

as and when required so.

At the top of stripper column lighter fractions come out. It is the offset gas

which further goes into knockout drum, where liquid is separated. From there it

goes to GSU. LPG component moves into reboiler from where it is refluxed in

stripper column for purification. Some part of this liquid after purification goes

to LPG Line. Stripper’s temperature is maintained by HP steam. LPG which

comes out from reboiler section further goes for caustic washing( since it has

H2S). From bottom of the stripper column Naphtha and NGL are produced.

This NGL either goes to KRU or NGL line depends on consumer demand.

45

46

LIQUEFIED PETROLEUM GAS ( LPG UNIT)

Oil and Natural Gas Corporation Ltd. Of India has set up a gas processing plant

at Hazira in Gujarat. The Plant is designed to process 20 MMNm3/day of gas

and associated condensate (in Phase-I & II). The gas and associated condensate

are received at the Plant from the Offshore platforms in Bombay High/ South

Bassein Oil/Gas fields through a sub-sea pipeline. After commissioning of

Phase-III & IIIA, total design capacity has increased to 38.5 MMNm3/Day of

gas (one GSU train standby concept) & associated condensate. LPG recovery

plant is designed to process 5 MMNm3/day of sweet gas. The balance gas

(33.5MMNm3/day) after routing it through gas dehydration dew point

depression units will be supplied to various fertilizer plants along the 1500 km

long pipeline route from Hazira to Jagdishpur (HBJ pipeline) in U.P. The

condensate collected in the dew point depression units is also processed in LPG

recovery plant.

Feedstock:

Gas:

5.12 MMNM3/day free gas from South Bassein field after sweetening.

OR

5.12 MMNM3/day associated gas from Bombay High Offshore field.

Liquid:

Average amount of condensate generated in 3 Dew point depression units (upto

40 M3/hr) (presently 7 to 8 trains equivalent to 2300 m

3/day) OR

Pipeline condensate corresponding to 5.12 MMNM3/day of associated gas from

Bombay High (presently sweet condensate is not being received).

PRODUCT SPECIFICATIONS: LPG: The plant is designed to extract LPG from the feed gas and condensate.

Specifications of LPG will be 50:50 by wt.(approx.) of C3:C4 and will conform

to IS-4576 for marketing system. Vapor pressure of LPG is 16.87 Kg/cm2a

(max) at 45 OC.

47

ARN: By product Aromatic Rich Naphtha is a mixture of pentane and heavier

hydrocarbons as present in feed streams. Vapor pressure=0.9 Kg/cm2 (max) at

40oC.

Lean Gas: Composition of Lean Gas from LPG recovery facility will depend

on the feed gas composition and is expected to vary with time.

PROCESS DESCRIPTION:

Feed gas from gas sweetening unit available at the LPG plant B/L at a pressure

range of 75-52 Kg/cm2 (around 60 Kg/cm

2 presently) and a temperature of

around 38oC (32-34

oC presently) flows to a K.O. Drum where any liquid

present in the gas is knocked off. Bulk of the water is removed from the gas by

cooling it up to 25 oC (presently 22-24

oC). After this, the gas flows through a

molecular sieve dryer where the moisture is reduced to up to 1ppm level. This

dried gas is cooled to -30oc in a Cold Box and the condensed liquid is separated

out in Separator-I. Vapors from separator are expanded almost isotropic ally in

an expander as a result of which the temperature further falls down to -54 OC

(presently around -50 oC).Liquid condensed on cooling is separated out in

Separator-II. The refrigeration of the vapor stream from Separator-II is

recovered to cool down the feed gas stream. Further, this lean gas is compressed

by expander compressor to about 37 Kg/CM2a (from 30 kg/cm2) and finally to

48.5 Kg/CM2a (presently 46.5 Kg/cm2a) by the lean gas compressor and

supplied to consumers as high-pressure lean gas.

Condensate from Dew Point Depression unit available at plant B/L at 73-50

Kg/CM2a (60 Kg/CM2G at present) pressure is flashed into surge drum after

heating to 25 OC (28-30

OC presently) to avoid hydrate formation. Condensate is

passed through a Coalescer where most of the free water present in the

condensate is separated out. Hydrocarbon liquid from Coalescer flows to liquid

dryers where the moisture content is brought down to 5 ppm.

Liquid from Separator-I & II along with condensate from liquid dryer outlet is

routed to Light Ends Fractionator (LEF) column. The light hydrocarbons (a part

of propane and lighters) are removed from the top of the column. These light

hydrocarbons are expanded in LEF 0/H expander and the refrigeration

recovered by cooling the feed gas stream in a cold box. LEF O/H gases from the

cold box is compressed to supply to KRIBHCO as Low-pressure lean gas and

also used for internal fuel gas consumption. Excess gas is compressed by

residue gas compressor to high-pressure lean gas header.

Liquid from the bottom of LEF column is routed to LPG recover column.

Liquefied Petroleum Gas (LPG) is withdrawn from this column as overhead

product and sent to storage. The bottom product, ARN is also sent to storage.

49

Propane is used as refrigerant for LEF overhead condenser and is generated by

fractionating a small part of LPG product in the Propane column.

Gas Dryers:

Gas from feed gas K.O. drum is sent to gas dryers, on flow control. This flow

controller controls the feed gas flow rate to the LPG plant. The gas dryers are

designed to reduce the moisture content of the incoming saturated gas to less

than 1 PPM. This is considering the requirement of C2-C3 Recovery unit, which

may come up in future. One dryer is used for drying while the other is under

regeneration. PIC-402 is provided at dryer outlet to flare the off-spec gas.

The driers are 3m O.D. and 12.45m height carbon steel vessels. They are filled

with molecular sieves of 3 mm 4 A type as desiccant. The molecular sieve is

supported by a bottom layer of ceramic balls. The top of molecular sieve bed is

also covered with a layer of ceramic balls. The drier bed is provided with two

sampling connections each connected to an online analyzer (which are isolated

because probes cannot sustain high temperatures during regeneration).

Sampling connection is also provided at the common outlet line of dryers for

moisture analysis. The bottom of the dryer is provided with a removable type

bottom collector fitted with SS wire mesh screen to retain escaping molecular

sieves from going to downstream equipment. The total charge of molecular

sieves per dryer is about 37.0 Tons (presently about 33.5 tons). The inlet and

outlet valves of the dryers are all motor operated. Dryer inlet valves and dryer

outlet valves leading to regeneration gas cooler are provided with a bypass

valve and a restriction orifice for slow pressurization and depressurization of

dryers.

Feed Gas Chillers: Dry and filtered feed gas is chilled to -30

OC in a brazed aluminum plate fin

exchanger, E housed in a cold box. Other cold streams, which pass through the cold box and provide the cooling, are:

Liquid from separators .

Expander outlet vapor.

LEF overhead vapors after expansion in LEF overhead expander.

50

FEED GAS EXPANDER-COMPRESSOR:

Gas from separator-I outlet is isotropic ally expanded in the expander section of

Expander-Compressor EK-101A/B, and the liquid condensed on cooling is

separated in Separator- II. The refrigeration thus produced is recovered in Feed

Gas Chiller, E-101 and Feed gas cooler, E-122 and the warm gases are

compressed in the compressor section of Expander Compressor. To prevent the

mixing of cold process gas into lube oil and consequent freezing of lube oil and,

also to prevent the lube oil from leaking into the expander casing, a stream of

warm and dry seal gas is provided. During start up, the seal gas would come

from dryer outlet through a seal gas heater, E-125. Under normal operation, seal

gas will be supplied from the HP lean gas header.

Gases on expansion from 57 (presently 53-54) Kg/CM2abs to a pressure of 32.6

(presently 29-30) Kg/CM2abs cool down to about –55 OC (presently –50

OC).

Cold gases flow to Feed Gas Separator-II, V-103. Separator-II is 3.4m O.D. and

about 5.2m height vertical vessel of alloy steel construction fitted with SS-304

wire mesh demister at the top. Condensed liquid is separated from the vapor

stream and is sent to LEF column after exchanging the cold in E-101. Feed to

LEF column is under flow control (FIC-602) cascaded to Separator-II level

controller, LIC-602. Gases at -54 OC (presently -50

OC) from feed gas

Separator-II pass through feed gas Chiller where the cold is recovered by feed

gas flowing to separator-I. The gas leaving feed gas Chiller at 7 OC is passed

through the feed gas cooler, E-122 to exchange cold with incoming feed gas.

Warm gases leaving E-122 at 30.8 OC are compressed to 37.7 Kg/CM2a in the

compressor section of the Expander compressor. Low pressure at compressor

suction is indicated by PAL-605/606. The temperature of the compressed gas

rises to around 55 OC. In case of very high temperature at compressor discharge

as sensed by TSHH-603A and 604B, the respective expander compressors are

tripped. Hot gases from compressor discharge at 55 OC are cooled to 40

OC in

after cooler.

DRYERS REGENERATION:

Regeneration of liquid and gas dryers (heating as well as cooling) is done by

passing hot/cold hydrocarbon gas through the dryers. LEF overhead vapor

stream is expanded in expander compressor and the refrigeration produced is

recovered . This gas is compressed by the expander compressor and used for

51

regeneration of dryers after heating the gas in a furnace. Hot gas at 265

OC

passes through the dryer bed under regeneration. The pressure of the gas to

regeneration gas heater is maintained by PIC-803, which by passes the excess

pressure of the compressed LEF overhead gases to regeneration gas moisture

separator. The regeneration gas is cooled by regeneration gas cooler, and the

moisture condensed is separated in the regeneration gas moisture separator. This

gas is then supplied to KRIBHCO as low pressure gas after providing for

internal consumption of fuel gas. Provision exists to recompress this low

pressure gas by residue gas compressor, and put it to high pressure lean gas

header in case for some reason low pressure lean gas is not being taken by the

consumers.

LEF COLUMN:

Liquid from dryer and from feed gas separator-I and II are sent to Light Ends

Fractionator. The column removes methane, ethane, a part of propane and most

of carbon dioxide as overhead product.

LEF column is a 36.9 M tall column with 50 valve type trays. Carbon steel is

used as material of construction for the column and trays, and stainless steel for

the valves. The column is of varying diameter. It is 3.4 M O.D. at the stripping

section and 2 M O.D. at the rectification section. In the stripping section trays

with 2-pass are used whereas in the rectification section, trays with 1-pass are

used.

Column overhead vapors are condensed in LEF condenser to about -19.2 OC

(presently, -23 to –24 OC). LEF condenser is a partial condenser with the

hydrocarbon vapors on the tube side being cooled by propane refrigerant on the

shell side. The temperature of propane on the shell side is about -25 OC.

The reboiler heat is provided by a kettle type reboiler. Heating media is

modified to LP steam (from MP) at kg/cm2g from cogeneration. At present

either MP or LP steam can be used as per the availability. Hydrocarbon on the

shell side is heated by steam on the tube side.

52

LPG COLUMN:

Liquid from LEF reboiler is fed to LPG column at about 105.5 OC (113-115

OC presently) for separation of LPG and aromatic rich naphtha (ARN). LPG is

withdrawn as column top product and ARN withdrawn as column bottom

product, are sent to storage. LPG column is 2M O.D. and about 37.4m height,

two-pass column with 54 valve trays. Carbon steel is used as the material of

construction for the shell and trays and Stainless steel for the valves. The

column operates at a top pressure of 11.3 Kg/CM2abs (presently 11.7

Kg/CM2abs) and a temperature of 57.3 OC. Feed to the column can be sent to

14th, 18th or 22nd trays, depending upon the composition of the LEF bottom

liquid. Presently 14th Tray is in use. Vapors from the column top are condensed

in LPG column condenser and the condensed liquid is collected in LPG column

reflux drum.

Aromatic Rich Naphtha is withdrawn from the bottom of the column on level

control and sent to storage via Aromatic rich naphtha cooler that cools the

column bottom stream to 45 OC.

PROPANE COLUMN:

A part of LPG product from upstream of is sent to Propane Column on flow

control for fractionation to produce pure propane for use as refrigerant. LPG to

propane column is fed on the 25th tray. Propane column is 1.2 M O.D. and

about 25.5 M tall column with 35 one-pass valve trays. The material of

construction for shell and trays is carbon steel.

The column operates at a top temperature of 48.3 OC (42

OC at present). Vapors

from the column top are condensed in a water-cooled condenser (Propane

Column condenser)and the condensed liquid is collected in the reflux drum. The

column top pressure is maintained at 16.3 Kg/CM2abs (14.5 Kg/CM2abs

presently) by a split range pressure controller (PIC-1101) which either operates

control valve on cooling water line to the overhead condenser or operates PV on

line to flare from the reflux drum. PV(Pressure valve) is provided with a

minimum stop position to ensure flow of minimum amount of water to the

53

overhead condenser. The column is protected against over pressurization by a

safety valve PSV. PSV has been installed later on, for sending the lighters to

Fuel Gas Knock Out Drum, which was earlier, flared to maintain Column

pressure during the Propane Column in operation. Propane is withdrawn as a

side stream from the 6th tray and is sent on flow control (FIC)either to storage

or directly to the refrigeration system by Propane product Transfer pumps. The

minimum flow requirement of the pump is met by flow controller (FIC) which

operates FV to send the pump discharge as reflux to the column in case the

product withdrawal rate is less than the minimum flow required for the pump.

Propane product transfer pumps operate at a suction pressure of 17.4

Kg/CM2abs and a discharge pressure of 19.6 Kg/CM2abs. The pumps are

designed for a normal flow of 2.75 M3/hr and can develop a differential head of

48.4 meters.

The reboil heat is supplied by Propane column reboiler,. The reboiler is of

thermo-siphon type. Carbon steel is used as the material of construction for shell

and tubes. Heat is supplied by low pressure steam regulated by flow controller(

FIC)which is cascaded with temp. controller, TIC, which controls the column

temperature at the 33rd tray. The column at the 33rd tray is maintained at 66.8 OC. The column operates at a bottom temperature of 79.25

OC and a pressure of

16.6 Kg/CM2abs as design or 69.0 OC at 13.5 kg/CM2g presently. Temperature

indicators are provided for the 3rd, 27th and 33rd trays . The column is provided

with high and low level alarms. Condensate from the reboiler is collected in

propane Column Condensate Pot from where it is routed to condensate header

Propane Column bottom product is sent to LPG storage on level control after

cooling it to 45OC in Propane Column Bottom Cooler. In case of high

temperature at the outlet, the column bottom flow is stopped by closure of the

valves. Lighter fractions can be diverted to fuel gas KOD through the modified

line having the pressure control PV.

54

KEROSENE RECOVERY UNIT (KRU)

Three main products are produced in this unit – Naphtha , kerosene and HSD.

Based on the mode of operations chosen for the unit, it can also produce ATF.

Both kerosene and ATF cannot be produced at the same time. The two modes

differ in the maintenance of physical parameters like temperature and density at

appropriate time and unit within the operation.

PROCESS DESCRIPTION Two modes of operation are envisaged for the kerosene recovery from NGL

produced in the condensate fractionation units from CFU.

When the FBP of the NGL feed is greater than 290°C, then the two

columns are planned to be operated in series mode to produce kerosene as

per specifications.

When the FBP of the feed NGL is less than 290°C parallel mode of

operation is planned under which the second column shall be used for the

same service as the first column.

The kerosene recovery unit is designed to fractionate 189.39 MT/hr, of NGL out

of which 163.00 MT/hr is the feed NGL from 6 CFU trains and 11.67 MT/hr of

the reprocessing NGL produced during annual shut down of KRU.

Reprocessing is for a period of 5.33 months (160 days) in a year (corresponding

to 8.25 days NGL production). With process optimization and de-bottlenecking

the present processing capacity is 1.45 MMTPA.

The KRU consists of the following sections:

NGL feed receiving Naphtha column feed preheat

Naphtha fractionation

Kerosene column feed preheat

Kerosene fractionation

NGL processing

55

KRU

56

ATF production process

57

STORAGE:

Liquid and gaseous products must be stored during intervals between

production, transportation, refining , blending and marketing. The objective

of storage at each of these stages is firstly to supply a sufficient balance of

each stock to ensure continuity of operation and secondly to ensure that the

product is conserved and maintained at an acceptable level of quality.

Various storage equipments are:

Horton spheres – These are spherical tanks used for storage of gases that are under pressure. It is used to store LPG and Propane.

Floating Roof Tank – these type of tank are used to store liquids that

are volatile in nature e.g. petroleum products.

Fixed Roof tanks - these are used for storage of non volatile liquids.

The products are sent to the various storage tanks and spheres

Products Capacity Storage

LPG 225000 m3 Horton Spheres(9 nos.)

ARN 66000 m3 Floating Roof Tanks(4 nos.)

NGL 66000 m3 Floating Roof Tanks(4 nos.)

SKO 25000 m3 Floating Roof Tanks (5 nos.)

HSD 1000 m3 Fixed Roof Tanks (2 nos.)

Propane 311 m3 Horton Sphere

58

COGEN, OFFSITE AND UTILITIES

COGENERATION:

The electricity requirements of the Hazira plant are met through an in-house

electricity generation system without depending upon an external source. The

Co- generation plant is used for this purpose. Apart from generation of

electricity the plant also undertakes the generation and distribution of HP and

LP steam throughout the plant wherever required.

The main feed for the generation of electricity is the LP gas generated within

the plant. A gas turbine system has been put in place to utilize this gas, with a

daily usage of 0.7- 0.8 MMT. Initially, the gas is compressed and then it is sent

to a combustion chamber, after which it is used in gas turbine through which

electricity is generated. The exhaust gases coming from the gas turbine are used

for heating up water in a boiler. Whenever heating is not required, a special flap

is there, which is opened so that the exhaust is released into the atmosphere.

Special arrangements are made to ensure continuous flow of water. The steam

generated is utilized in the main generator.

The DM plant takes raw water, which is then dematerialized to generate steam.

Exhaust gas is used in two stages - HP and LP, with HP steam generating and

then LP steam. Then it goes to economizer and from there it goes to exhaust line

and is exhausted into the atmosphere.

The whole system has 3 plants of 20 MW capacities, of which two are running

at present. Of the power generated, 30 MW is utilized by the Hazira plant. Rest

10MW is given to other customers.

No steam turbine is there, so whatever the steam is generated; it is supplied to the Hazira plant for further use.

A Combined cycle efficiency of about 55% is achieved by this process. The

whole of co-generation unit is controlled and monitored through the control

room where special panels are installed ( mfg. industrial and power system)

which shows real time operations going on and thus serves ease of use and

operation.

59

Components of electricity generation system :

Gas turbine Compressor Combustion chamber Turbine Gas turbine load compartment Gas turbine inlet plenum Gas turbine inlet duct Gas turbine exhaust duct GT generator Generator excitation compartment Starting motor. Inlet filter house Fuel gas module Generator pedestral Generator step up transformer

Transformer Lube boil module Liquid fuel module Atomizing air module Bypass stack Heat recovery steam generator HP steam drum IP steam drum LP steam drum Water feed pump Heat recovery steam generator stack Sea water lift pump Cooling water pump Steam turbine IP/LP compressor HP compressor Condenser

60

Steam turbine generator Discharge Channel Condensate hot well pump Condensate water tank

Water treatment system

Raw water tank

DM water tank

OFFSITE:

Apart from the major process units described above, Hazira plant also has

offsite facilities spread over a wide area where the various products

obtained from the processing facilities are stored temporarily. Storage of LPG is done in LPG spheres, which are large spherical storage tanks, divided into two phases, consisting of six and three spheres in first and

second phase, respectively. The design capacity of the tanks is 2500 m3,

with a

safe filling capacity of 2100 m3. Presently, however these tanks are being used

for 1200 m3 of storage. A pressure of about 8.5 kg/ cm

2 is maintained.

The LPG from here is transferred to tankers, which are shipped to different

locations either through road or rail. Ethyl mercaptane, which is used for the

detection of leakages, is mixed with LPG here only, so that any leakage further

down line can be identified easily.

For propane storage, presently only one tank is there, with capacity half that of LPG tanks. Eight Naphtha tanks are available; each having a capacity of 16,500 Kl.

Naphtha from here is transported to ships for export to other countries

through nearby ports.

Fig: Naphtha tanks

62

UTILITIES:

Utilities are the services which are essential for the operation of the plant,

though these may not contribute directly towards the revenue generated.

The major utility systems the plant has include:

Air system

Inert gas system

Water system

o Raw water treatment plant o Fire water pump house

o Cooling water system o DM water system

Emergency Preparedness

Cogeneration and steam systems

Effluent treatment and disposal plant

Fuel gas network

I/G Plant Air is used in many places within the plant. Inert gas systems are used for

purging to ensure hydrocarbon/air free state during shutdown and start-up

activities. Inert gas is prepared from the atmosphere at the inert gas plant

through the PSA (pressure swing adsorption), in which the air is passed through

carbon molecular sieves, which have the granules of a special compound which

adsorbs N2 at the surface, and relieves O2, when under pressure. The container

is then depressurized so that the entrapped nitrogen escapes which is then

delivered to appropriate location. Nitrogen is used for regular processes in

KRU (as sealing medium in certain pumps) Two towers work in conjugation, one working under adsorption mode and

the other in regeneration mode. The requirement of nitrogen is approximately

400m3/hr. Instrument air is utilized in automatic plants, for use by instruments, so it has

to be free from any kind of moisture. Plant air, which may have some moisture

is used in SRU plant

63

RAW WATER TREATMENT PLANT

Another important utility system is the water system. Water is utilized in almost

all the units. The water requirement for the Hazira plant is met by Tapti river,

the source being about 30-40 km from the Plant, through a weir designed to

ensure continuous supply of water. The water is then kept into reservoirs at the

plant, in which it is allowed to settle, and then is pumped out to various

locations. The total consumption of water at the plant is about 20,000 kl/day.

The water is used as service water for plant usage, and as make up water in

cooling towers (to counter evaporation losses etc.)

Drinking water is also supplied after adequate treatment, not only to the plant

but also to nearby villages for social obligation and to nearby ONGC

residential colony.

Cooling water and service water lines are spread throughout the plant as sea

green pipelines. Red lines are for firefighting systems.

Raw water systems have an operating capacity of about 2000 m3/hr.

(5 pumps x 750 m3/hr, 2 standby).

64

CONCLUSION

The industrial training at ONGC, Hazira has been a very good learning

experience for me. The knowledge of theoretical subject is not enough for any

engineering stream. One has to have the practical knowledge to remove the gap

between the actual and expected performance.

Training helped me to know and develop various technical and communication

skills. It also gives us a lot of knowledge about the process, its equipments and

operational phases. The training is an important step towards us becoming

successful engineers. The most important lesson that I have learned is

discipline, management and cooperation. With the immense cooperation of the

ONGC family not only did I grasp technical knowledge regarding all the

industrial issues and operations but also filled in the gap that always existed in

real while studying a theoretical subject with the same being put into practical

use. Working in the largest gas processing plant really gives me the honor of

being a part of this beautiful family. With this I would really like to thank each

and every personal I have interacted in the plant and who have helped so deep in

clearing all the problems that I faced.

65