A

SUMMER INTERNSHIP REPORT ON

AN OVERVIEW OF ODALAREVU ONSHORE TERMINAL

OIL AND NATURAL GAS CORPORATION

Submitted in Fulfillment for the Award of the Degree of

BACHELOR OF TECHNOLOGY IN MECHANICAL ENGINEERING

Submitted By

ARJA RAJITHA (218W1A0348)

VISTALLA MAHALAKSHMI (218W1A0344)
SAMARTHAKURTHI VARALAKSHMI (218W1A0380)

Under the guidance and supervision of

SAURABH ARUN SHRIVASTAVA

EXECUTIVE ENGINEER

(MECHANICAL)

DEPARTMENT OF MECHANICAL ENGINEERING

VELAGAPUDI RAMAKRISHNA SIDDHARTHA ENGINEERING
COLLEGE VIJAYAWADA(KANURU),520007

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 CERTIFICATE

DEPARTMENT OF MECHANICAL ENGINEERRING

This is to certify that the internship project report entitled
“AN OVERVIEW OF ODALAREVU ONSHORE TERMINAL”

Being submitted by ARJARAJITHA(218W1A0348),VISTALLA

MAHALAKSHMI(218W1A0344),SAMARTHAKURTHI VARALAKSHMI(218W1A0380).In
fulfillment of the requirements for the award of the Degree of Bachelor of Technology in
Mechanical Engineering. It is a BONAFIDE work of carried out by them. under the guidance and
supervision of

SAURABH ARUNSHRIVASTAVA EXECUTIVE ENGINEER

(MECHANICAL). .

PROJECT GUIDE:

SAURABH ARUN SHRIVASTAVA EXECUTIVE ENGINEER (MECHANICAL).

PLACE: KAKINADA

DATE: 03/06/2024 – 18/07/2024

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 ACKNOWLEDGEMENT

The satisfaction that accompanies the successful completion of any task would be incomplete
without mentioning the people who made it possible and whose constant guidance and
encouragement grown all the efforts with success.

I would like to express my deepest gratitude to OIL AND NATURAL CORPORATION for
providing me an internship opportunity. This internship made me to learn the practical
knowledge and provided me an exposure to the applications of different theories regarding
mechanical background.

I express my deepest thanks to Mrs. CH. CHANDANA of HR department and

SAURABH ARUNSHRIVASTAVA – EXECUTIVE ENGINEER(MECHANICAL) for
providing me this opportunity and guiding me to learn and providing me the required study
materials and goodlearning environment.

I would like to extend my sincere thanks to entire staff in vashishta and s-1 of mechanical
department who helped me in learning practical knowledge and equipment working principle.

The encomium goes to the professor Dr.N.VIJAY SAI, Head of Department

Mechanical Engineering Department of Velagapudi Ramakrishna Siddhartha
Engineering College Vijayawada

On conclusion, I will remember our experiences in this industrial training and presenting the
training experience to prove our ability and work for pride of the organization in all respects
wherever we get an opportunity.

With sincere regards,

ARJA RAJITHA (218W1A0348)

VISTALLA MAHALAKSHMI (218W1A0344)
SAMARTHAKURTHI VARALAKSHMI (218W1A0380
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 DECLARATION

We hereby declare that the internship project entitled “AN OVERVIEW OF ONSHORE
TERMINAL -ONGC” has been undertaken ARJA RAJITHA(218W1A0348),
VISTALLAMAHALAKSHMI(218W1A0344), SAMARTHAKURTHI(218W1A0380) and the
project report is submitted to ANDHRA UNIVERSITY COLLEGE OF ENGINEERING (A),
Visakhapatnam in partial fulfillment of the requirements for the award of degree of BACHELOR
OF TECHNOLOGY in MECHANICAL ENGINEERING.

We further declare that this project has not been submitted in full or part for the award of any
degree of this on any other educational institutions.

Submitted by
ARJA RAJITHA (218W1A0348)
VISTALLA MAHALAKSHMI (218W1A0344)
SAMARTHAKURTHI VARALAKSHMI (218W1A0380

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 INDEX

 INTRODUCTION ....................................................... 6 - 9
 SAFETY RULES and PRECAUTIONS .....................10 - 12
 INTRODUCTION TO VASHISHTA PLANT ........... 13- 14
 UTILITIES IN PLANT .............................................. 34 - 42
 MECHANICAL EQUIPMENT ................................. 43 - 48
 COMPRESSORS
 PUMPS
 TURBINES
 CONCLUSION ............................................................ 49- 50

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 INTRODUCTION

The Oil and Natural Gas Corporation Limited (ONGC) is an Indian central
public sector undertaking under the ownership of Ministry of Petroleum and Natural
Gas, Government of India. The company is headquartered in Delhi. ONGC was founded on 14
August 1956 by the Government of India. It is the largest government-owned-oil and gas
explorer and producer in the country and produces around 70 percent of India's domestic
production of crude oil and around 84 percent of natural gas. In a survey by the Government of
India for fiscal year 2019–20, it was ranked as the largest profit making Central Public Sector
Undertaking (PSU) in India. It is ranked 5th among the Top 250 Global Energy Companies
by Platts.

ONGC is involved in exploring for and exploiting hydrocarbons in 26 sedimentary

basins of India, owns and operates over 11,000 kilometers of pipelines in the country and
operates a total of 210 drilling and workover rigs. Its international subsidiary ONGC Videsh
currently has projects in 15 countries. ONGC has discovered 7 out of the 8 producing Indian
Basins, adding over 7.15 billion tons of In-place Oil & Gas volume of hydrocarbons in Indian
basins.

FOUNDATION OF ONGC IN 1956

Before the independence of India in 1947, the Assam Oil Company in the north-
eastern and Attock Oil Company in the north-western part of the undivided India were the only

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oil-producing companies, with minimal exploration input. The major part of Indian sedimentary
basins was deemed to be unfit for the development of oil and gas resources. After independence
under the act of INDUSTRIAL POLICY STATEMENT OF 1948 by the central government of
India there is a huge development in oil extrusion and processing.

Until 1955, private oil companies mainly carried out exploration of hydrocarbon
resources of India. In Assam, the Assam Oil Company was producing oil at Digboi (discovered
in 1889) and Oil India Ltd. was engaged in developing two newly discovered large
fields Naharkatiya and Moraan in Assam. In West Bengal, the Indo-Stanvac Petroleum project (a
joint venture between the Government of India and Standard Vacuum Oil Company of USA)
was engaged in exploration work. The vast sedimentary tract in other parts of India and adjoining
offshore remained largely unexplored.

In 1955, the Government of India decided to develop the oil and natural gas resources
in the various regions of the country as part of the Public Sector development. With this
objective, an Oil and Natural Gas Directorate was set up towards the end of 1955, as a
subordinate office under the then Ministry of Natural Resources and Scientific Research.

In April 1956, the Government of India adopted the Industrial Policy Resolution,
which placed Mineral Oil Industry among the schedule 'A' industries, the future development of
which was to be the sole and exclusive responsibility of the state.

Soon, after the formation of the Oil and Natural Gas Directorate, it became apparent that it would
not be possible for the Directorate with its limited financial and administrative powers as a
subordinate office of the Government, to function efficiently. So in August 1956, the Directorate
was raised to the status of a commission with enhanced powers, although it continued to be
under the government. In October 1959, the commission was converted into a statutory body by
an act of the Indian Parliament, which enhanced powers of the commission further. The main
functions of the Oil and Natural Gas Commission subject to the provisions of the Act were "to
plan, promote, organize and implement programs for development of Petroleum Resources and
the production and sale of petroleum and petroleum products produced by it, and to perform such
other functions as the Central Government may, from time to time, assign to it ". The act further
outlined the activities and steps to be taken by ONGC in fulfilling its mandate.

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 ONGC EOA OFFICE AT KAKINADA

ONSHORE AND OFFSHORE ACTIVITIES

Onshore activities refers to process that takes place on land that are associated with oil,
natural gas or condensate production the has taken place offshore. All the offshore exploration is
performed by using floating drilling units, drill ships, semi-submersible installations and jack-up
installations.

Some of the onshore assets are: Ahmedabad, Mehsana, Ankleshwar, Cambay, Assam,
Tripura, Rajahmundry, Cauvery, Kakinada, Mumbai high, Neelam – Heera, Bssien – satellite,
Coal bed methane - bokaro.

Offshore activities are defined as searching for potential underground crude oil and
natural gas reservoirs and accumulations, the drilling of exploratory wells that recover and bring
the crude oil and natural gas to the surface.

Some of the offshore assets are: Mumbai offshore [western offshore] and Eastern
offshore asset [EOA] or also called as KG basin.

Mumbai asset is divided into three assets that is MH asset, B&S asset, NEELAM-HEERA asset

Mumbai high was discovered in 1966 and it is the first oil reservoir was discovered in ONGC
even it is discovered in 1966 the production was started in 1973 due to the installations of wells
and platforms and processing unit. One of the biggest oil reservoir in india.

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OVERVIEW OF ONGC ODALAREVU: ONGC Eastern Offshore Asset, Kakinada has
its major gas terminal at Odalarevu in Amalapuram. ONGC in close association with public,
panchayat and government has been working consistently for prosperity and sustenance of the
local people here. The project includes the wells, a few of them namely VA-DA and VA-DB at
the Vashishta field and S1-A and S1-B at the S1 development. The Vashishta field is estimated
to produce 9.56 billion cubic meters (BCM) over a period of nine years with peak production
reaching 3.55 million metric standard cubic meters a day (MMSCFD) during the first five years.
The S1 field is expected to deliver 6.22BCM over a period of eight years with a peak production
of 2.2MMSCFD for the first five years. The terminal's capacity upon expansion is proposed to be
7.25MMSCFD of gas and 1,500 Cubic Meters Per Day (m3/d) of crude. The project includes the
construction of wells, storage tanks, gasification units, production units and related
infrastructure, the installation of related equipment and the laying of pipelines. The facility
accommodates a slug catcher for well fluid separation, gas compressors, high integrity pressure
protection system (HIPPS), glycol dehydration, dew point control, mono ethylene glycol
regeneration and gas metering systems and also includes utilities such as air compression,
nitrogen generation, flare system, storage tanks and diesel generators.

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 SAFETY RULES and PRECAUTIONS
Oil and gas extraction activities involve many different types of equipment and materials. These
activities can lead to a number of accidents and hazards posing major risk to the field workers.
Recognizing and preventing such hazards is critical to avoiding injuries and deaths. In the
ONGC Odalarevu Onshore Terminal, various safety measures are adopted to minimize potential
accidents and contain any type of a hazard. The first and foremost safety requirement to enter the
plant premises is proper Personal Protective Equipment (PPE) which includes

 SAFETY COVERALL
 HELMETS
 PROTECTIVE EYE WEAR GLASS
 EARMUFFS HEADPHONE
 SAFETY SHOES

There are gas and fire detectors fitted at various locations in the plant to signal the
control room for any leakage and take necessary action. Three main types of alarms exist
within the plant to alert the personnel of outbreaks containing

 FIRE
 GAS LEAKS
 ABANDONED

In case of any emergency upon sounding of the said alarms, one must immediately stop
their task and gather at the nearest muster point which are located throughout the plant. This
includes leaving their belongings behind and ensuring others have also left the premises.

One must always remain vigilante and calm during an emergency to minimize the risk
and handle the situation without any major loss. ONGC has adapted the slogan ‘All Accidents
are preventable’ and works towards standing by it in all conditions.

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Risk Assessment:

ONGC is committed to maintain high standards for health and safety at all times. However, on
rare occasion, an unplanned event can have the potential to jeopardise the safety of the crew and
cause environmental damage. Potential non-routine events that may occur during the proposed
activities of drilling operations, expansion of onshore terminal and installation of pipeline:

● BLOWOUT

● OIL SPILLS

● H2S EMISSIONS

● COLLISION INVOLVING DRILL SHIPS

● HELICOPTER CRASHES

● GAS LEAKAGE

● FIRE (if gas comes in contact with source of ignition)

● OCCUPATIONAL HAZARDS

Specific procedures and training will be carried out to ensure that the correct action would be
taken in the event of unplanned occurring. Onshore and offshore facility equipped with suitable
safety measures such as fire-fighting facility (fire suit, fire extinguisher, gas sensors etc), medical
facilities, etc. The operating personnel will be provided PPES and trained for such an eventuality
and the key responsible people will be required to hold relevant well control certification.

FIRE DEAPRTMENT:

Odalarevu Onshore Terminal has a dedicated fire-fighting unit to tackle and contain accidents
involving fire. Some of the fire-fighting equipment include

● DIESEL DRIVEN ENGINES - 3x750 m3/hr

●ELECTRIC DRIVEN ENGINES – 2x750 m3/hr

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Fires are classified into four types based on the combustion source and the material used to
contain it

 CLASS A: GENERAL FIRES – WATER CAN BE USED

 CLASS B: LIQUID & GAS FIRES – FOAM IS USED
 CLASS C: ELECTRICAL FIRES – CO2 IS USED
 CLASS D: METTALIC FIRES – DCP IS USED

NOMEX fire suit is included in the fire-fighting package for safety during such emergencies. It
contains the following features:

- Self-Contained Breathing Apparatus (SCBA) which has a capacity of 300 bar for a time period
of 45 mins approx. and weighs 6kg. It is in both overhead and jacket types.

Parts of the SCBA include

- Back plate, cylinder, face mask, main valve, manifold pressure gauge, high- and lowpressure
tubes, lung demand valve, warning whistle and shoulder straps.

Important parts of the face mask are

- Spider straps, head and forehead straps, chin-jaw and neck straps, outer and inner face mask
for inhalation and exhalation, speech diaphragm

A diesel driven fire engine includes

- 15m delivery hose - triple purpose branch nozzles

- 22.5m extended hose - water capacity of 5000 liters

- Short branch pipe nozzles - DCP capacity(500kg), foam \

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INRODUTION TO VASHISTHA PLANT

Vashishta and S1 gas fields located in the Krishna-Godavari (KG) Offshore Basin, off the
east coast of India, are being developed under a greenfield deep water development project by
India’s biggest oil and gas exploration and production company Oil & Natural Gas Corporation
(ONGC). The total investment for the integrated development is estimated to be $751.65m.
The project is expected to be completed by April 2016 with both the fields planned to be brought
online that year. Offshore drilling is scheduled to be completed within a period of six to seven
months.
The Vashishta field is estimated to produce 9.56 billion cubic metres (bcm) over a period of nine
years with peak production reaching 3.55 million metric standard cubic metres a day (MMscmd)
during the first five years. The S1 field is expected to deliver 6.22bcm over a period of eight
years with a peak production of 2.2mmscmd for the first five years.

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 The proposed development encompasses drilling, re-entry and completion of four wells,
subsea tie-back of the wells to an onshore terminal at Odalarevu and expansion of the existing
onshore terminal.
The four wells will be namely VA-DA and VA-DB at the Vashishta field and S1-A and S1-B at
the S1 development. The wells will be drilled to a depth of 2,200m and tied back to the onshore
facility in daisy chain architecture.
The daisy chain development will feature midline tees and crossovers situated at S1 wells, VA-
DB and pipeline end terminations at VA-DA. A pipeline end manifold will be present at VA-DB
to allow pigging for future expansions.
A 14in diameter and 45km-long dual pipeline will be used for the tieback that will follow the
route of the existing G1 pipeline system to have minimal impact on the seabed and the
surrounding area. The pipeline will be segmented into two sections, subsea and landfall, with
varying wall thickness.

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 SURFACE FACILITIES

PROCESS FLOW CHART

This section of the plant includes the following equipment:

 Inlet scrubbers gas

 compressor package gas
 dehydration package

 gas/gas heat exchanger

 low temperature separators

PROCESS DESCRIPTION:

Well fluid is transported to the onshore terminal through subsea pipelines

using the pressure from offshore wells. Brief description about the processing facilities as well as
utilities and offsites for new terminal at Odalarevu is given below.

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 SLUG CATCHER

Production fluid received at onshore is passed through slug catcher for first stage of separation.
The multi-pipe slug catcher will separate the well fluid in to HC gas, HC liquid and water
streams while flowing through pipe fingers. The separated gas will be further treated,
compressed and conditioned to meet desired sale gas specifications. Generated HC condensate
(if any) shall be transferred to existing facilities for further processing. Separated produced water
will flow into the treatment facilities for treatment and disposal. Separated gas from slug catcher
will receive further treatment in inlet scrubber for removal of 99.9% liquid over 10 microns. This
will ensure that small particles of liquid do not go into the compressors. All compressor units
will be equipped with auxiliary systems such as interstage and outlet gas coolers and inlet,
interstage and outlet liquid separators to retain the larger particles of condensate liquid after
cooling.

THREE PHASE SEPARATOR :

In the process plant we are using a horizontal three phase separator as a slug
catcher. In a horizontal three-phase separator, fluid enters the vessel through an inlet, and
immediately hits an inlet diverter. This sudden impact provides the initial separation of liquid
and vapour and begins the gas-oil separation process. In the liquid collection section of the
vessel, the oil and emulsion separate, forming a layer (or “pad”) above the free water. A weir
maintains the oil level, while an interface liquid level controller maintains the water level.

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 HORIZONTAL THREE PHASE SEPARATOR

The oil spills over the top of the weir, and then a level controller, which operates
the oil dump valve, controls its level. An interface level controller also senses the height of
the oil-water interface. This controller signals another dump valve to release as much water
from the vessel as is needed to maintain the oil-water interface at the pre-determined height.
Meanwhile, gas rises to the top of the separator. It flows horizontally and exits through a mist
extractor to a high pressure control valve, which maintains constant vessel pressure.

 When compared to a vertical separator, horizontal separator is more preferable due to

having a lower centre of gravity then a vertical separator by this ability a horizontal
separator is more stable and also provides a longer retention time in separation of oil and
water.

PROCESS GAS COMPRESSORS:

 There are 7 compressors at the VA terminal and 5 at the G1 terminal.

 The gas compression system has logic for engine control in the engine control
panel. The logic for compressor control is PLC based remote control panel.

 These are equipped with a driving unit (gas engine) and auxiliary systems like
inter stage, outlet gas coolers, inlet, inter-stage and outlet liquid separators.

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  Compressors can be started and stopped by a local panel or from the operator
station in the control room.

 A test named the LLF Test (Look, Listen, Feel Test) is conducted to look after
the compressors and to avoid emergencies.

 From gas-gas exchangers to 7 compressors line, there is a common pipe of 40

inches where the gas comes. This 40-inch line is called the gas suction line. stage
suction separator to avoid moisture and remove it from gas that came in when the
gas travelled.

 Gas is filtered in suction strainers then it goes to 1st stage suction separator of
140 microns.

 The first stage has 3 LP cylinders (low-pressure cylinders). This gas is passed to
the 1st stage suction volume bottle which is then made to pass through three 1st
stage cycles and then later to the 1st stage-discharge volume bottle. 1st stage-
discharge bottles have three 16.25 inches diameter cylinders. This gas is made to
go to 1st stage intercooler.

 Now the 2nd stage of suction separation begins followed by the 3rd stage of
suction separation begins. 2nd stage-discharge bottles have two 10.50 inches
diameter cylinders and the 3rd stage-discharge bottle has one 10.00 inches
diameter cylinder.

 The difference between these three stages is the number of stage cycles involved.
The 1st stage has three-stage cycles while 2nd and 3rd have two and one stage
cycles respectively.

 At the end of the 3rd stage of cooling, the gas is passed to after cooler discharge
separator or is directly discharged for further processing.

 This entire 3 stage 6’’ stroke reciprocating double-acting compressor is driven

with the gas engine.

GAS DEHYDRATION UNIT:

Natural gas is dehydrated to remove water vapor. This step is essential to avoid
formation of hydrates, oversaturation of natural gas and corrosion of equipment that happen due
to the presence of water vapour. A Gas Dehydration Unit (GDU) setup is employed to eliminate

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the presence of water from gas. To remove water from natural gas, a liquid called Tri-Ethylene
Glycol (TEG) is used. When the gas comes in contact with TEG, the water vapours entrained in
the gas are absorbed in the TEG. The TEG essentially soaks up the TEG.

WORKING:

The gas from wells moves along the gas processing chain by first going to the slug catchers, the
gas compressors and then reaches the gas dehydration package. The design of gas drying system
uses Lean TEG as liquid absorber in liquid-gas Absorber. The glycol absorbs the water from the
gas phase along with some other components (heavy hydrocarbons). The Rich glycol (rich in
water) is then regenerated by heating which is flowed by stripping the semi-Lean glycol with
stripping / dehydrating gas. The purpose of GDU is to remove water from compressed process
gas to meet the sales maximum water specification – 4.7 lb/MMSCF. Two complete trains, each
consisting of absorption and regeneration sections are envisaged for processing total 247.2
MMSCFD (7 MMSCMD) process gas. The GDU is designed for a unit availability of 96%. Each
glycol regeneration system is designed to produce 4.5 t/h of Lean glycol with a purity of 99.1%
Wt. Flowsheet The flowsheet depicting the sequence of operations occurring in the Gas
Dehydration Package is shown below

Gas Dehydration Package: The Gas Dehydration package in the Vashishta terminal contains
mainly five sections:

1. Absorption phase: Consists of all the equipment used to remove water from gas using TEG.

2. Regeneration phase: Consists of all the equipment used to separate water absorbed from TEG.

3. pH Control and Corrosion inhibitor: Consists of equipment used to maintain glycol in the
required pH range in order to avoid oxidation and decomposition of TEG.

4. Fresh glycol storage package: Consists of equipment used for glycol make up of both trains

5. Glycol drain facilities: This is common to both trains.

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1.ABSORPTION PHASE:

GLYCOL ABSORBER – The wet gas enters the Glycol Absorber through the inlet integrated
scrubber at 66.2 barg and 38°C. In this one, condensates are separated from the gas. The gas
flows upwards in the column through the chimneys of the glycol tray. Condensates are routed to
HC closed drain under level control. This column is fitted with structured packing in order to
ensure adequate contact between liquid and vapour. One bed of structured packing is installed to
reach the required water dew point. The Lean glycol is fed at the top of the column and evenly
distributed across its entire crosssectional area by the glycol distributor. Then, flowing
downwards, wets the structured packing ABSORPTION PHASE/ SECTION GLYCOL
ABSORBER 50 surface. The dehydration by absorption takes place as the wet gas flows
upwards through the packing, contacting the wetted surface. The glycol rich in water (i.e., Rich
glycol) is recovered above from the chimney tray of the Glycol Absorber and flows to the Glycol

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mesh demister (double mat) is installed to recover the liquid glycol entrained with the dried gas.
Dehydrated gas from the top of Glycol Absorber goes to Glycol Filter Coalescer after passing
through Lean Glycol / Gas Exchanger.

LEAN/GLYCOL GAS EXCHANGER - In sufficient quantities, hydrocarbon can cause foaming

in glycol regeneration system. To ensure that hydrocarbon is not condensed out of the gas stream
to the glycol circulation system, the Lean glycol is maintained approximately 5°C above the
dehydrated gas stream leaving the Glycol Absorber. The Lean Glycol / Gas Exchanger is
designed for Dehydrated gas from Lean / Glycol Gas Exchanger is routed to Glycol Filter
Coalescer this purpose. Dehydrated gas is heated from 39.3°C to 40.5°C. Glycol is cooled from
82.4°C to 44.3°C.

GLYCOL FILTER COALESCER - Glycol Filter Coalescer is fitted with coalescing cartridges to
limit TEG carry-over to downstream unit. Glycol recovered in the Glycol Filter Coalescer is
recycled back to the Rich glycol stream leaving the Glycol Absorber under level control.

DEHYDRATED GAS - Online moisture analyser is provided on the dehydrated gas line leaving
Glycol Filter Coalescer in order to continuously monitored the water content / dew point of the
dehydrated gas. A small split stream is withdrawn from dehydrated gas leaving the Glycol Filter
Coalescer in order to be used as stripping gas in the Glycol Stripping Column. Dehydrated gas
from train A is then mixed with dehydrated gas from train B before leaving the Gas Dehydration
unit for further processing. Flow control valve is provided on each train, upstream of both trains
joining to control the good flow distribution to both trains.

2. REGENERATION PHASE / SECTION:

The Rich glycol coming from chimney tray of the Glycol Absorber is sent to the tube side of the
Glycol Reflux Condenser then to the Cold Rich / Lean Glycol Exchanger before entering the
Rich Glycol Flash Drum.

 COLD/RICH LEAN EXCHANGER - The Cold Rich / Lean Glycol Exchanger is a

tubular exchanger type (BEM type). It is provided for energy conservation to reduce the
total heat input required for the regeneration process (reduction of Glycol Reboiler duty).

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  RICH GLYCOL FLASH DRUM - The Flash Drum is a horizontal 3-phase separator,
operated at low pressure (3.5 barg, 75°C) whose purpose is to separate gases and
hydrocarbon condensates from Rich glycol. For this matter, the Flash Drum settling
compartment is designed for 30 minutes of Rich Glycol retention time. The large
pressure-drop through the level control valve downstream the Glycol Absorber causes the
release of a substantial quantity of light hydrocarbon components, previously dissolved in
the Rich glycol. The produced gas is routed to the Flare Header under pressure control.
The recovered hydrocarbon condensates are routed to the Closed Drain Header under
level. To allow circulation of the glycol during the start-up of the regeneration unit, the
Flash Drum has to be pressurized with Fuel Gas. Pressure of Fuel gas is controlled at 3.5
barg by a sell actuated pressure control valve. During start-up, operator has to open the
ball valve on the fuel gas line to the vessel. The Rich Glycol leaves the flash drum under
active level control, for further processing in the Glycol still column. Before entering the
still column, it flows through the Filtration package and Hot Rich / Lean Exchanger.

 FILTRATION PACKAGE - The cartridges filters are installed on the flash drum Glycol
outlet line. These filters remove any solid particles from the Rich Glycol stream to
prevent from fouling the heat transfer exchangers within the Glycol Regeneration Unit
from plugging of the distribution holes of the glycol distributor in the Glycol Absorber.
The filters are equipped with 25 microns cartridges for the first start-up of the unit. The
normal operating filter mesh size is 5 microns absolute (i.e., filtration efficiency 99.9% of
particles above 5 µm). Filter shall maintain solid content below 100 ppmwt. Rich Glycol
is then routed to the charcoal filter. The charcoal filter is installed on the glycol outlet
line. This filter removes any impurities and dissolved hydrocarbons or degradation
products. The filter is designed for 100% of Rich Glycol flow.

 HOT RICH / LEAN EXCHANGER - The Rich glycol coming from the Charcoal Filter
A enters into the Hot Rich / Lean Exchanger. The Hot Rich / Lean Exchanger is a hairpin
type. It is provided for energy conservation to reduce the total heat input required for the
regeneration process (reduction of Glycol Reboiler duty). 53 The purpose of the Glycol
Re boiler, Glycol Still Column and Glycol Stripping Column is to remove the water
contained in Rich glycol. The Rich glycol is heated up to 204°C thanks to hot oil

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 circulation in the bundle. The Glycol Reboiler operates at as low a pressure as possible to
help desorption of the water. Any volatile material (water, hydrocarbons not released in
the Flash Drum) passes into vapour phase and travels up the Glycol Still Column where it
is contacted with liquid travelling down the column. The Rich glycol coming from
chimney tray of the Glycol Absorber is sent to the tube side of the Still Column Reflux
Condenser where it provides a reflux at top of the Glycol Still Column. The reflux
flowing down the Glycol Still Column cools the rising vapour and induces glycol
condensation, thus reducing glycol losses. The heated Rich Glycol is then routed to the
Glycol Flash Drum where any released hydrocarbon vapour is vented. Increasing reflux
reduces glycol losses but increases the duty of the Glycol Reboiler and the traffic load in
the Still Column. The temperature at the top of the Still Column should be between 90
and 110°C. Lower temperature is better but can only be obtained at reduced capacity. A
higher temperature could mean significant glycol losses. The glycol level in the Glycol
Reboiler is constant. Indeed, stripping column is integrated to the Glycol Reboiler. Thus,
Glycol from the Glycol Reboiler overflows into the Glycol Stripping Column. The
purpose of the Stripping Column is to push further the desorption of the water The Rich
glycol coming from the Charcoal Filter is heated from 75.0°C to 159.9°C by exchanging
heat with the hot Lean glycol leaving the Glycol Stripping Column. Then, the Rich glycol
is routed to the Glycol Still Column. At the same time, the Lean glycol is cooled from
197.5°C to 110.1°C through Glycol / Glycol Exchangers before its entry into the Glycol
Surge Drum.

 GLYCOL REGENERATION SECTION (REBOILER, STILL AND STRIPPING

COLUMNS) - The purpose of the Glycol Circulation Pumps is to send the Lean glycol
to the top of the Glycol Absorber at Absorber's working pressure. Two pumps are
installed (one in operation, one in stand-by). The pumps are plungers (triplex) pumps.
These volumetric pumps deliver a constant flowrate of glycol. A pulsation dampener is
installed on discharge of each pump. For operation with reduced gas capacity (turndown),
a glycol by-pass line, connected from the discharge of the Glycol Circulation Pumps to
the Glycol Surge Drum, is implemented in order to reduce the glycol flow rate routed to
the Lean Glycol / Gas Exchanger. still contained in the glycol leaving the Glycol

23 | P a g e
 Reboiler. Stripping is performed using dehydrated gas coming from Glycol Filter
Coalescer. The Stripping Column is fitted with random packing (Pall rings or equivalent)
to ensure contact between the vapour and liquid phases. The Lean Glycol leaves the
bottom of the Stripping Column at 197.5°C and flows through the Glycol / Glycol
exchangers and where it is cooled down to 82.7°C prior entering the Glycol Surge Drum.

 GLYCOL SURGE DRUM - The Glycol Surge Drum provides a buffer volume for the
circulating glycol. The Lean Glycol enters the vessel from the Cold Rich / Lean Heat
Exchanger (Glycol cooled at 82.7°C). The Surge Drum is sized for 14 days Glycol
consumption hold-up (estimated volume: 0.7 m²). The liquid level in the Surge Drum
must float and therefore cannot be controlled. Lean Glycol is then cooled further to
approximately 45°C by the Lean Glycol / Gas Exchanger after being pumped by the
Glycol Circulation Pumps. Glycol make-up from Fresh Glycol facilities is performed in
the Glycol Surge Drum. Surge Drum is pressure balanced with Stripping Column in order
to maintain an equal pressure between the two vessels, thus allowing gravity flow from
one vessel to the other thanks to their difference in elevation. It also allows the free
variation of the level in Surge Drum.

 GLYCOL CIRCULATION PUMPS - The purpose of the Glycol Circulation Pumps is to

send the Lean glycol to the top of the Glycol Absorber at Absorber's working pressure.
Two pumps are installed (one in operation, one in stand-by). The pumps are plungers
(triplex) pumps. These volumetric pumps deliver a constant flowrate of glycol. A
pulsation dampener is installed on discharge of each pump. For operation with reduced
gas capacity (turndown), a glycol by-pass line, connected from the discharge of the
Glycol Circulation Pumps to the Glycol Surge Drum, is implemented in order to reduce
the glycol flow rate routed to the Lean Glycol / Gas Exchanger. Reducing the glycol flow
rate to the Lean Glycol / Gas Exchanger will limit the temperature increase of the dry
gas. The by-pass flow rate is manually set by opening / closing a globe valve installed on
this line.

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3. pH CONTROL & CORROSION INHIBITOR AGENT:

In order to avoid the oxidation and decomposition of TEG solution, the Lean TEG needs
to be maintained at a pH range between 6.5 to 8, Rich MEG between 5.5 to 11. Injection of basic
components like amines, sodium carbonates is required for this. Corrosion inhibitors plate out on
metal surfaces and form a protective film that is effective in reducing corrosion. Amines
simultaneously control the pH of TEG solution and is used as a corrosion inhibitor. Chemical
injection is performed in a batch mode into the Lean Glycol that leaves the Glycol Surge Drum.

4. FRESH GLYCOL STORAGE PACKAGE:

The fresh glycol storage package is made up of fresh glycol storage tank and fresh glycol
transfer pumps. This package is common to both trains of the GDU. The fresh glycol storage
tank is a horizontal tank that stores glycol, used to compensate glycol losses in the two glycol
absorbers and the two regeneration units. Make-up glycol requirement for glycol circulation loop
is to be fulfilled by adding fresh glycol to the glycol surge drum. To avoid degradation of the
fresh glycol by air, the fresh glycol storage tank is blanketed with nitrogen.

5. GLYCOL DRAIN FACILITIES:

Glycol Drain Drum and Glycol Drain Pumps are common for glycol absorber and glycol
regeneration section of both trains. Glycol Drain Drum is designed to handle the entire liquid
inventory of one train in case of maintenance or shutdown activities. Glycol Drain Pumps are
used to transfer the collected TEG to the Rich Glycol Flash 56 Drum through the filters for reuse.
Fuel gas is used for blanketing the drum to avoid degradation of the TEG during intermediate
storage.

REFRIGERATION PACKAGE UNIT:

Sweetened & Dehydrated Gas from the GDU (Gas Dehydration unit) is processed
in this unit. This process is based on the removal of heavy hydrocarbons by lowering the
temperature / the pressure of the gas. The net gas separated in this unit is divided into two
streams; one stream is taken as the sale gas product and is sent to the sale gas product header.

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A part of net gas is sent to the stripping gas header. The separated condensate is routed to the HC
condensate header and then to CSU. The Dew Point Depression Unit is designed to remove the
heavier hydrocarbons associated with the gas coming from GDU to ensure condensate free
transportation of product gas meant for sale, which may get exposed to different temperatures
during transportation. Sweet and Dehydrated Gas is treated in this unit to lower its hydrocarbon
dew point well below the minimum temperature which the gas may attain in the pipeline. As per
gas (ex-DPDU) quality specification, the gas shall not exceed a hydrocarbon dew point above -
3°C below 100 bars. To meet this requirement Dew point depression unit is designed to chill the
gas up to -9°C and to recover the condensate formed due to gas cooling which is sent to CSU for
processing.

REFRIGERATION PACKAGE FOR HYDROCARBON DEW POINT

Refrigeration

Propane has excellent thermodynamic properties, leading to high energy efficiency. For
instance, the latent heat of vaporisation of propane is almost two times higher than that of the
most common HFC refrigerants this means a higher cooling / heating effect for the same

26 | P a g e
refrigerant mass flow. It works on the principle of Joule Thomson Cooling effect. Propane
refrigeration can produce refrigeration at −40°F, which is adequate for the hydrocarbon dew
point controlling operation for pipeline gas applications. Refrigeration is used to achieve the bulk
condensation of natural gas liquids. Propane refrigerant is the primary medium used in gas
processing. The main control aspects are compression, compression driver, refrigerant
condenser, economizers, and chillers. Both centrifugal and reciprocating compressors are
commonly used in this service with turbine, electric motor, or gas engine drivers. The purpose of
the lube oil is to run the compressor efficiently that to reduce the friction between the metal parts
and decrease the wear and tear inside the compressor.

MEG RECOVERY UNIT (MRU)

Process description: This scheme is a “full stream” scheme that treats all the incoming Rich
MEG solution and produces Lean MEG at 80%wt concentration and free of salts composition
and operates. The conditions for the incoming Rich MEG are as follows.The MRU consists of
five functional sections:

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Section 1 – PRETREATMENT

The incoming inlet rich MEG enters into the degasser where gases and
hydrocarbons are removed from the rich MEG stream. The inlet settling compartment where the
Rich MEG is separated from hydrocarbons tanks to interface control and the oil outlet
compartment. The mixture of Rich MEG of condensate flows into settling compartment. The
heavier phase (i.e., Rich MEG) settles in then compartment while the lighter hydrocarbon phase
(condensate) separates and rises above the Rich MEG level. The condensate phase overflows
over their weir into the hydrocarbon collecting compartment while the Rich MEG is sent under
level control to the degassing boot and further to the Rich MEG settling tank. The Degassing
Boot provides a further buffer volume for degassing before entering settling tank in order to
avoid perturtoration of selling of solids in tank. Rich MEG settling tank is a low-pressure storage
with nitrogen blanketing. The tank also provides sufficient residence time for settling of sand /
sludge in settling zone of tank. The sand / sludge can be removed during tank shutdown. Rich
MEG settling tank pumps transfer Rich MEG to reclaiming section through strainers to remove
suspended solids which would not have settled into Rich MEG settling tank. Before entering
reclamation section, Rich MEG is used as cooling medium, first in Lean MEG from cooler, then
in Rich MEG / water exchanger and finally in Lean / Rich MEG exchanger. This allows to
preheat Rich MEG before its entry in vacuum section. At Rich / Lean MEG exchanger outlet,
aqueous solution of caustic soda is added continuously to ensure that reclaiming unit operates in
basic condition with pH close to 11 to protect unit metallurgy against excessive corrosive attack.
20% wt. caustic soda solution is used for this, which is stored in dedicated caustic tank. It is
injected by caustic injection pumps. The actual amount of caustic required will depend on
flowrate of incoming MEG feedstock.

Section 2 – MEG VACUUM RECLAIMING

The Rich MEG coming from the Lean / Rich MEG exchanger enters the MEG vacuum
reclaimer vessel. Upon flashing into the MEG vacuum reclaimer vessel, water and MEG will
vaporize while salts and other solids contained in the inlet stream will not vaporize and will
instead become concentrated at the bottom. Vapours exiting the MEG vacuum reclaimer vessel
are directed into the MEG still column. Both of these vessels operate at sub atmospheric

28 | P a g e
pressure. This allows the MEG / Water mixture entering the vessels vaporize at approximately
118ºC will be below the degradation temperature of MEG (about 165ºC). MEG / H2O / Salt
slurry is continuously pumped from the bottom of the MEG Vacuum reclaimer vessel by the
reclaimer circulation pumps, which sends the slurry back to the vessel after heating in the
reclaimer circulation heater. Boiling of the slurry circulating through the reclaimer circulation
heater is undesirable as it would result in solids deposition which would very rapidly foul the
heat transfer surface of the exchanger. Boiling is therefore deliberately suppressed by imposing a
backpressure on the reclaimer circulation heater using a pressure reducing device that is sized for
a large pressure drop. In addition, maintaining a very high circulation rate through the heater in
combination with the flow operating pressure in the system will minute the possibility of thermal
degradation of MEG by

- Lowering the required operating temperature

- Limiting the temperature rise of the MEG

- Lowering the temperature of heat transfer surface

- Minimizing the period of time that the MEG stream in contact with the heat transfer surface.

A portion of MEG /H2O/ Salts slurry flowing through the circulation loop is diverted to the
solids handling area in order to limit the salts concentration in the loop to 10% wt. (5% wt. of
suspended solids + 5% wt. of dissolved salts). Nitrogen (purity above 99.5% volume) is added
on a continuous basis to purge air that could potentially leak into the process through leaky
valves, flanges or other connections. Operators should adjust this purge flow based on the
periodic sampling and analysis of the vacuum pumps and gas regulated nitrogen purge should
normally be adjusted by the operator to maintain.

Section 3 – SOLID HANDLING

As MEG and water are evaporated in the MEG Vacuum reclaimer vessel, the slurry
SECTION-3 SOLID HANDLING 63 circulating in the recirculation loop is concentrated with
10% wt. solids (5% suspended and 5% dissolves). In order to maintain this concentration in a

29 | P a g e
loop, a slip stream is continuously removed from the thickened slurry to the salt sediment vessel
where salts are further concentration before being removed via a centrifuge. When entering, the
salt sediment vessel solids fall down to the bottom of the vessel while the liquid returns to the
MEG vacuum reclaimer vessel the bottom of the salt sediment vessel progressively and forms a
highly concentrated salt slurry (25% wt. of salts) which constantly circulates through the slurry
pumps. This slurry is cooled by the slurry cooler to promote growth of salt crystals and reduce
temperature of the mother liquor sent to the centrifuge. Hence the slurry can be sent to the
centrifuge where salts are removed, which will consequently decrease salt concentration in the
loop. The centrifuge is a completely automated filtering basket type machine operating in the
batch cycles. It's PLC control system (supplied by centrifuge vendor) that automatically controls
all aspects of the centrifuge are determined by the centrifuge vendor. The centrifuge operates in
batch mode. During the feed plate, slurry is introduced into the centrifuge basket, rotating at
medium speed. After the desired speed, despite the cake accumulates on the basket, the feed is
shut off and the basket rotation speed increase to dry the cake. In order to decrease MEG losses
in the produced salt cake target less than 20% wt. of pure MEG in the cake and to replace it by
water. when the water washing step is performed to push away the MEG initially present in the
cake and the centrifuge baskets is maintained at high speed in order to dry the salt cake. Then the
speed is reduced to low plough speed during this part of the processing cycle dry cake (above
90% wt. solids by weight) is escaped from the basket walls and dumped to the brine mixing tank.
During the centrifuge's feed, all liquids that are discharged from the centrifuge are collected and
sent to the concentrate collection drum. These liquids are then returned to the MEG vacuum
reclaimer vessel under automatic level that control the concentrate collection drum operates
under a moderate nitrogen pressure to allow back to the MEG vacuum reclaimer vessel, while
the higher elevation of the centrifuge allows for gravity flow to the concentrate collection drum.

Section 4 – PRODUCT HANDELLING

Vapours produced at the MEG vacuum reclaimed vessel travel upwards through
the packed section of the MEG still column. These vapours are contracted counter currently with
reflux water which is water that is injected at the top the MEG Still Column (allowing partial
condensation of these vapours). This partial condensation results in a salt-free Lean MEG
product that exits the bottom of the MEG Still Column and a distilled water vapour stream that

30 | P a g e
exits through the top of the column. The salt-free Lean MEG is pumped by the Lean MEG
product pumps and cooled in two stages by the Lean / Rich MEG exchanger and Lean MEG trim
cooler to be delivered at battery limit at a temperature not exceeding 40ºC. Vapours exiting the
top of the MEG Still Column are cooled in the MEG Still overhead condensed water, which
condenses most of the water present. The condensed water then enters the MEG Still Reflux
Drum where liquid water is separated from any condensable vapours. The water is then pumped
tanks to MEG Still Reflux pumps. A part of the water is used as reflux water and returned to the
MEG Still Column. The other part of the produced water is cooled by the Rich MEG / water
Exchanger before being sent alternatively to the Brine Mixing Tank for dissolution of salts or
directly to export. Any condensate in MEG Still Column reflux drum can be skimmed and then
pumped to battery limit using the HC condensate Export pump.

Note: During washing sequence of the centrifuge, a part of the produced water is sent to
centrifuge and this operation is intermittent. The vacuum in the reclaiming section and in the
MEG Still Column is created by the vacuum pumps. These vacuum pumps are liquid ring pumps
that do not require any lubrication. The vacuum is created as the non-condensable vapours from
the MEG Still Drum are sucked into the vacuum pumps and compressed. The vent gases stream
exiting the vacuum pumps package may then be delivered to the battery limit for discharge to
flare header as required.

Section 5 – SALT REDISSOLUTION

The salts cake produced by the centrifuge is redissolved in the brine mixing tank
with water coming from MEG still reflux drum, to produce a brine mixture that is sent to the
water treatment package. The water treatment package can accept only very limited number of
solids. However, the salt cake from the centrifuge contains two types of salts: monovalent salts
and divalent salts. As divalent salts mostly do not redissolve in water they be extracted from the
brine. This is performed in the TSS package (out of pH scope), the brine mixing tank and TSS
package operate in batch following the centrifuge. After a centrifuge batch, salts are recovered
in the brine mixing tank, which then exports a batch of brine (containing dissolved monovalent
salts and solid divalent salts) to the TSS package. The TSS package in turn extracts a batch of
solid divalent salts and produce a batch of treated brine, composed of water and dissolve

31 | P a g e
monovalent. The brine mixing tank then receives a batch of produced water from the overhead
system to be ready to dissolve salts from the next centrifuge batch. The raw brine from the brine
mixing tank is pumped by the brine transfer pumps. In order to avoid solids deposits, the brine
transfer pumps are also used to maintain a constant circulation in brine mixing tank bottom. The
temperature of the brine mixture is limited to 50ºC maximum at MEG package battery limits.

PH CONTROL OF MRU:

An aqueous solution of caustic soda is continuously added into the process to

ensure that the reclaiming unit operates in a basic condition with a pH close to 11. This elevated
pH protects the unit metallurgy against excessive corrosive attack which could be caused by the
presence of CO2, oxygen, or organic acids. This caustic injection ensures also that any calcium
ions present precipitate as Calcium Hydroxide and not as CaCl2 within MEG vacuum Reclaimer
vessel. The actual amount of caustic required will depend on the flowrate of the incoming MEG
feedstock and the inorganic and organic acid content of this feedstock. Sampling of the MEG
solution is the most effective method to control the pH of the process stream and inject the
correct rate of soda. Thus, the pH value of the MEG Reclaiming Unit shall carefully be checked.
Indeed, in case the pH is found below 10, the caustic soda injection rate shall be increased
accordingly.

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 UTILITIES IN PLANT

INSTRUMENT AIR

The term “Instrument Air” refers to an extremely clean supply of compressed air that is free from
contaminates such as moisture & particulates. A system may utilize instrument air for various
types of pneumatic equipment, valves & electrical controls. It must be free of oil and dust and
dry enough to ensure that no water condenses anywhere in the system. It must be free of oil and
dust and dry enough to ensure that no water condenses anywhere in the system.

CAUSTIC TANK - Caustic tanks contain sodium hydroxide in order to main the pH of 11 so as
to prevent any clogging and corrosion in the pipeline especially in the MRU unit.

FLARE SYSTEM

Flare system

A Flare System is an arrangement of piping and specialised equipment that collects hydrocarbon
releases from relief valves, blowdown valves, pressure. control valves and manual vents and
disposes of them by combustion at a remote and safe location. Flares are important safety
devices used in refineries and petrochemical facilities. They safely burn excess hydrocarbon
gases which cannot be recovered or recycled. A typical flare system consists of:

● PSV outlet pipes, sub header connected to main flare header, main flare header connected to
knock out drum, the outlet of the flare knock-out drum to flare stack. A knockout drum to
remove and store condensable and entrained liquids.

● Single or multiple burner units and a flare stack.

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Flare systems provide hydrocarbon facilities with safe and efficient discharge of relief and waste
gases by controlled open flame burning. The important features of a flare system are:

When any equipment in the plant is over-pressured, the pressure relief valve is an essential safety
device that automatically releases gases and sometimes liquids. The height of the flame depends
on the volume of released gas, while brightness and color depend upon composition. The
released gases and liquids are routed through large piping systems called flare headers to the
flare. The released gases are burned as they exit the flare stacks. Commonly, flares are equipped
with a vapor-liquid separator (also known as a knockout drum KOD) upstream of the flare to
remove any large amounts of liquid that may accompany the relieved gases to avoid fireballs. To
keep the flare system functional, a small amount of gas is continuously burned, like a pilot light,
to assure that the flare system is always ready for its primary purpose as an over-pressure safety
system.

FUEL GAS SYSTEM

FUEL GAS The average natural gas processed in the plant every day is 1.828MMSCMD out of
which 1.734MMSCMD is sent to GAIL and the rest is used in generating electricity using two
GTGs.

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DIESEL

Diesel essential utility in the plant which is used in times of emergency where both the GTG
cannot be used to generate electricity. Emergency diesel generators are used to generate
electricity for the most important parts in the plant.

FIREWATER - Fire water refers to water that has been used in firefighting and requires
disposal. In many cases, it is a highly polluting material and requires special care in its disposal.

Objective: Taken the dehydrated and dew pointed sales gas from Gas header and supply this gas
as the fuel gas at required pressure by Pressure controller. This system includes the following
equipment:

 Fuel gas heater

 Fuel gas KO (knock out) drum

 Fuel gas oil heater

 Fuel gas treatment package

FUEL GAS SYSTEM

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PROCESS DESCRIPTION:

The fuel gas is heated in the fuel gas electric heater prior to let down across PV-2302 A/B to a
pressure of 25 bar. The fuel gas then passes through the fuel gas knockout drum to ensure that
any liquid which may have formed across let down valve, is removed. The fuel gas hot oil heater
then increases temperature to 40.6 degree Celsius to ensure that fuel gas is distributed with
adequate superheat to prevent condensation within the distribution piping or equipment. Based
on an Operating temperature of 40.6 degree Celsius the system will provide a minimum super
heat of 10 degree Celsius to the fuel gas at all times. High pressure fuel gas is distributed to Gas
turbine package at 20 bar pressure. Another fuel gas stream is further let down across PV-2302
to A/B to a pressure of 5 bar for distribution to the low-pressure users. The low-pressure fuel gas
system supplies fuel gas to the following users:

1. Gas compressor packages (ON-Z-1301 A/B/C/D/E/F/G))

2. Gas dehydration package (ON-Z-1401)

3. Hot oil heater (ON-H-2201)

HOT OIL SYSTEM

HOT OIL HEATER

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Hot oil heaters, sometimes called thermal fluid heaters or heat medium heaters, are used in a
variety of situations depending on the industry in which they are used. A thermal oil boiler fires
through a helical coil and generates energy from the hot products of combustion. This, by
heating the coil through radiation and convection. The coil heats the thermal oil or fluid that is
pumped through the thermal oil boiler. The thermal oil heats coils in various types of heat users.

PROCESS DESCRIPTION:

Hot oil is circulated through hot oil circulation pumps to waste heat recovery unit and fired
heater for heating purpose. In normal operation, hot oil is heated in waste heat recovery unit.
Where, hot oil outlet temperature is controlled at 240 degree Celsius by controlling the flue gas
from running gas turbine. Hot oil heater while in hot standby condition with Pilots running
condition. In case gas turbine is not running or flue gas is not available for heating purpose,
required heating shall be achieved in the hot oil heater. Hot oil is then sent to the hot oil supplier
header to feed all hot oil users. For MEG Reclaimer Circulation heater, hot oil inlet temperature
is to be restricted to 200 degree Celsius. Therefore, a stream from hot oil circulation pump is
mixed with hot oil steam from the hot oil supply header under temp control. After heating, hot

37 | P a g e
oil from all the users are collected in the Hot oil return header and then routed to hot oil
expansion vessel.

Hot oil expansion tank is provided for the four following reasons:

• To provide expansion volume for oil while it is being heated up during start-up.

• To provide a net positive suction head for the hot oil circulation pumps.

• To flash of absorbed gases (if any) in hot oil streams.

• To provide storage capacity for top up requirements.

As the hot oil system operates as a closed system, a filter is also included downstream of the
circulation pumps, where a small slip stream of flow will be directed through filter at each
passing. This ensures that over time, particulate matter can be removed from system, preventing
any build up.

Equipment description:

Hot oil expansion vessel:

Operating pressure :1.5 bar

Operating temperature :169°C

Design pressure FP by :13.35

Design temperature:300°C

Dia :2700 mm

TI to TL length :6700 mm

System volume : 27.9m3 and Expansion volume:14.4 m3

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Hot oil circulation pumps:

Pressure (suction or discharge) :1.59 bar

Operating temperature:169°C

Design pressure :15 bar

Design temperature Capacity :300 °C :158.5 m3/hr

Hot oil filter is located downstream of the sperms a single filter element designed to remove
particles.100 microns or larger from a slipstream of hot oil Only slipstream of hot oil is to be
filtered (as the requirement is to prevent build up of fine solids in the system). Filter can be
isolated from maintenance by two block valves (a positive isolation through spectacle Blinds)
without disruption to hotel system.

WASTE HEAT RECOVERY UNIT:

Waste heat recovery unit

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It is basically a flue gas heat recovery system from hot exhaust flow gas coming from gas turbine
which is used for heating hot oil (Therminol-55). Waste heat recovery unit are a combo of heat
recovery tubes, bare as well as extended surface tubes supported in tube sheets and ducting
whose primary objective is to utilize the excess heat from a combustion process (gas turbine
exhaust) and use it in energy efficient manner to heat process fluid in tubes. WHRU primarily
consists of heat recovery tubes through which process fluid to be heated flows. A lot of ducting
for flow of hot flue gases for which the heat is to be recovered and stack through which the
cooled flue gases flow out to atmosphere. There is other auxiliary equipment like dampers that
are an integral part of system as well.

NITROGEN GENEREATION SYSTEM:

NITROGEN GENERATION SYSTEM

Equipment: Nitrogen generation pkg

Equipment no: ON-Z-2403

Objective: Nitrogen will be used for inert gas blanketing and miscellaneous purging purposes.

Details

Type : Membrane type producing 98.5% (by vol.) pure nitrogen.

No of Membranes : 6 ( two trains each having 3 membranes 1 W+ 1S)

No of Pre-Filters : Two ( 1W+ 1S)

Capacity: 50 Nm3/hr (200 Nm3/hr)

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Opr Pressure : 7.5 Kg/cm2 ( 13 Kg/cm2 design pr)

Note: Each Membrane train Protected by dedicated dust filter

PRODUCT SPECIFICATIONS:

Delivery of Natural Gas to GAIL'S Gas Grid: (at plant Battery limit B/L)

1. Water Dew Point at line pressure: 0 0C

2. Hydrocarbon Dew point at line pressure: 0 0C

Delivery condition of Crude Oil pipeline: (at Battery limit B/L)

1. Crude oil to stabilized BS&W < 0.1% and 2. Pour Point: 18 0C

Produced water effluent delivery conditions as per PCB guidelines: Produced water effluent to
be delivered to ONGC's water tank at existing plant must have:

1. Oil content < 10 PPM. And 2. TSS (Total Suspended Solids) < 100 PPM.

Chemical Injection:

1. Methanol to be sent offshore to be injected at the PLEM / well heads.

2. One 0.5-inch nominal tube (1 mm WT) inside main umbilical.

3. Tubing design pressure of > 352 kg/cm2(g).

4. Normal operating pressure of 292.7 kg/cm2(g). and 5. Flow rate is 0.545 bbl. methanol per
MMSCMD gas dosage.

Pour-Point Depressant Injection:

1. PPD line from onshore terminal to G-1 field.

2. 0.5-inch nominal tube (1 mm WT) inside main umbilical.

3. Maximum flow rate of 0.11 GPM (2000 PPM basis).

4. Maximum working pressure of 352 kg/cm2.

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 MECHANICAL EQUIPMENT
COMPRESSOR:
In the process plant compressors are used for processing and utility systems. The
compressors which are used for utility is screw type compressors the compressors which are used
for gas processing is reciprocrating positive displacement compressors.

EQUIPMENT: GAS COMPRESSOR PKG EQUIPMENT

NO : ON-Z-1301A/B/C/D/E/F/G

NO OF UNITS : 7( 6W+ IS)

Make : DRESSER-RAND

Model : 6” HOS 6-3

Capacity : 0.8 MMSCMD each(Total : 4.8MMSCMD)

PRIMEMOVER - Make : CATERPILLER GAS ENGINE

Model : G3616 ADME3

Speed : 1000 rpm Rating : 3762KW

• Logic for Engine control located in Engine control panel

• Logic for Compressor control is PLC based remote control panel

• Each compressor package is equipped with driving unit(Gas Engine) and auxiliary systems
such as

• Inter-stage and outlet gas coolers, inlet, inter-stage and outlet liquid separators.

• Each Compressor Pkg can be started and stopped from local panel or from Operator.

Brief Description of Compressor Package

Gas Compressor Package was designed as per site requirement and for a medium of Natural Gas.
Gas Compressor Package model was Designed, manufactured, Installed by M/s Dresser-Rand.
Installed was a Three stage 6” stroke Reciprocating Double acting Compressor driven with Gas

42 | P a g e
Engine. 1 st stage was equipped with #03 no’s of 16.25” Dia. Cylinders  2nd stage was
equipped with #02 no’s of 10.50” Dia. Cylinders 3 rd stage was equipped with #01 no’s of
10.00” Dia. Cylinder. Gas Compressor was designed for a suction pressure of 6.78BarG and final
discharge of 67BarG with a capacity of 0.8MMSCMD per Each compressor. Gas Engine is
Caterpillar Make 3616 model Engine. Process Gas Compressor operated with a PLC based
control system, all operational controls will be controlled from Control room only.

GAS COMPRESSOR

Operational Sequence of Process Gas Compressor:

Suction header 40” Piping line feed Natural Gas for individual compressor with a branch piping
of 12” line. Gas was first filtered in suction strainers and will through to 1st stage suction
separator where liquid content in Gas will separate and Natural gas will enter 1st stage suction
volume bottle to 1st stage cylinders. In 1st stage suction gas will be compressed and cooled in
inter stage Air cooled heat exchanger and will through to 2nd stage suction separator where

43 | P a g e
liquid content in Gas will separate and Natural gas will enter 2nd stage suction volume bottle to
2nd stage cylinders. The same process will continue in 3rd stage also and cooled in After cooler
Air cooled heat exchanger and through 6” piping line compressor High pressure Gas will pass to
further process.

OPERATING CHARACTERISTICS AND GENERAL DATA:

PUMPS:
Definition: A mechanical device which raises pressure or move fluids.

Classification:

Roto-dynamic pumps (Centrifugal Pumps )

radial

axial

mixed flow

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Positive Displacement Pumps :

Reciprocating pumps : piston (single acting, double acting)

Plunger

Diaphragm

Rotary pumps :

gear pump

vane pump

screw pump

NOTE: In the process plant there are five pumps in which three are driven by diesel engine and
two are driven by electricity. One should be running in them and other rest of the pumps are
under stand by if there is a case of any fire accident in diesel storage then we need to shut down
all the diesel driven pumps and start electrical driven pumps in case of any accident in turbine or
electricity department we need to operate the diesel driven pumps and shut down the diesel
driven pumps all the pumps are centrifugal type pumps only.

CENTRIFUGAL PUMP:

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Fluid is pressurized by the fluid motion generated due to rotating impeller. Pressure is
proportional to the rotor speed. Generally used for low-pressure and high-volume flow
applications. These pumps provide a smooth and continuous flow but the flow output decreases
with increase in system resistance (load).

GAS TURBINE SYSTEM:

A gas turbine is a machine delivering mechanical power or thrust. It does this using a gaseous
working fluid. The mechanical power generated can be used by, for example, an propeller or
alternator. The outgoing gaseous fluid can be used to generate thrust. In the gas turbine, there is a
continuous flow of the working fluid.

Basic Components:

 Inlet system: Collects and directs air into the gas turbine. Often, an air cleaner and
silencer are part of the inlet system.

 Compressor: Provides compression, and, thus, increases the air density for the
combustion process. The higher the compression ratio, the higher the total gas turbine
efficiency.

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  Combustor: Adds heat energy to the airflow. The output power of the gas turbine is
directly proportional to the combustor firing temperature.

 Gas Producer Turbine: Expands the air and absorbs just enough energy from the flow to
drive the compressor.

 Power Turbine: Converts the remaining flow energy from the gas producer into useful
shaft output work.

 Exhaust System: Directs exhaust flow away from the gas turbine inlet.

SYSTEMS IN GAS TURBINE:

 Air System

– Air intakes are located high up & multiple filters

– Exhaust discharged out stacks

 Fuel System – Commercial fuels like kerosene, natural gas, propane, petrol.

 Lubrication System – Supply bearings and gears with oil.

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 CONCLUSION

The oil and gas sector plays a vital role in influencing decision making for all the other important
sections of the economy as it is among the eight core industries in India. Oil and Natural Gas
Corporation Limited (ONGC), a company with a global vision and noble mission, is the premier
exploration and production company in India and contributes around 74% of India's crude oil
and around 63% of its natural gas production. It is India's Top Energy Company and ranks 20th
among global energy majors. Acclaimed for its Corporate Governance practices, Transparency
International has ranked ONGC 26th among the biggest publicly traded global giants. Apart from
exploration, development, and production of crude oil and natural gas, both onshore and
offshore, it also engages in refining, transportation, and marketing of petroleum products.

The company is deepening its technical and operational expertise in deep water E&P and is
increasingly assessing the prospect of high pressure-high temperature and ultra-deep water plays
in India. Winner of the Best Employer award, a dedicated team of over 25,000 professionals toil
round the clock in challenging locations.

ONGC EOA, HPHT Asset, Kakinada deals with two terminals located in the Odalarevu region
of Andhra Pradesh, along the eastern coast of India, namely G1 terminal, a part of their offshore
oil and gas production infrastructure, potentially and Vashishta Terminal, a significant project
undertaken by ONGC.

As a public sector enterprise, ONGC has a long and cherished tradition of commendable
initiatives, institutionalized programmes and practices of Corporate Social Responsibility which
have played a applaudable role in the development of several underdeveloped regions of the
country.

Overall, ONGC plays a crucial role in India's energy security and has a significant presence both
domestically and internationally in the oil and gas industry. It has been a wonderful experience
training in this industry.

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The employees and the staff were helpful and were always ready to guide me in the plant and
also in getting a better understanding of the theoretical concepts. This has been a very good
experience for me, understanding the industrial approach to the theoretical part.

The objectives of the company made me to know the importance of industrial knowledge and its
application in the working field. Finally, I conclude my report by thanking all the employees of
ONGC, Kakinada for guiding me throughout my internship program

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