training report 2013

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Training Report

Vocational Training

Surface Team

ONGC, Ahmedabad Asset.

Presented by:-

Venkatesh Ambati

Navneeth Kumar Korlepara

Siddhant Sanjay



CERTIFICATE

This is to certify that Venkatesh Ambati and Navneeth Kumar Korlepara students of

Petroleum Engineering from Dept. of Petroleum & Petrochemical Engineering, JNTU

Kakinada and Siddhant Sanjay of Applied Geology from IIT Kharaghpur have successfully

completed Industrial Training in “Surface Operations & Artificial Lifts”, under Surface Team, Ahmedabad Asset, ONGC Ahmedabad for duration of 4 weeks (14th May 2013 to 15th June

2013).

Mr N. Khanduri

CE (P)

Project & Training Co-ordinator

[ST Dept., ONGC

Avani Bhavan, Ahmedabad]



ACKNOWLEDGEMENT

We are thankful to Mr Niranjan Khanduri [CE (P), Surface Team] for his effort in arrangingour training at Ahmedabad Asset under the Surface team. We would also like to extend our

deepest gratitude to Ms Vimla Saxena [DM (HR), ONGC] for giving us the permit to undergo

this training program. We would also like to express our sincere thanks to the

installation managers, security department and the shift in-charges of the following sites:

Kalol GCS, GCP, CTF

Motera GGS

Nawagam Desalter Plant, WWTP, CTF

Nawagam GGS-3, WIP, ETP

SCADA Control room

Sanand GGS-2, Polymer Injection

Artificial lift, SRP Automation

Kalol Instrumentation lab

Kalol GGS-7, WIP, ETP

We are also thankful to Jawaharlal Nehru Technological University (JNTU), Kakinada & IIT

Kharaghpur for providing us with encouragement, moral support and the opportunity to

undergo training at ONGC, Ahmedabad Asset. It was a treasurable learning experience and

we augmented our practical knowledge.



CONTENTS

I. Introduction to ONGC

II. Introduction to Surface Operations

III. Artificial Lift

a. Sucker Rod Pump

b. Gas Lift

IV. Group Gathering Station

V. Central Tank FarmVI. Gas Collecting Station

VII. Gas Compressor Plant

VIII. Desalter Plant

IX. Effluent Treatment Plant

X. Water Injection Plant

XI. Waste Water Treatment Plant



Introduction:

Oil and Natural Gas Corporation Limited (ONGC) (NSE: ONGC, BSE: 500312) is an

Indian multinational oil and gas company headquartered in Tel Bhavan, Dehradun, India. It is one of the

largest Asia-based oil and gas exploration and production companies, and produces around 72% of

India's crude oil(equivalent to around 30% of the country's total demand) and around 48% of its natural

gas. It is one of the largest publicly traded companies by market capitalization in India. ONGC has been

ranked 357th in the Fortune Global 500 list of the world's biggest corporations for the year 2012. It is also

among the Top 250 Global Energy Company by Platts. Its operating income is US $ 6.55 billion (2012) and

with a net profit of US $ 4.22 billion (2012).

ONGC was founded on 14 August 1956 by the Indian state, which currently holds a 69.23% equity

stake. It is involved in exploring for and exploiting hydrocarbons in 26 sedimentary basins of India, and

owns and operates over 11,000 kilometres of pipelines in the country. Its international subsidiary ONGC

Videsh currently has projects in 15 countries. ONGC has discovered 6 of the 7 commercially-producing

Indian Basins, in the last 50 years, adding over 7.1 billion tonnes of In-place Oil & Gas volume of

hydrocarbons in Indian basins. Against a global decline of production from matured fields, ONGC has

maintained production from its brownfields like Mumbai High, with the help of aggressive investments in

various IOR (Improved Oil Recovery) and EOR (Enhanced Oil Recovery) schemes. . Recovery Factor has

improved from 28 per cent (in 2000) to 33.5 per cent (in 2011). Significantly Reserve Replenishment Ratio

for the last 7 years has been more than one.

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History

Foundation to 1961

During the pre-independence period, the Assam Oil Company in the north eastern and Attock Oil

company in north western part of the undivided India were the only oil companies producing oil in the

country, with minimal exploration input. The major part of Indian sedimentary basins was deemed to be

unfit for development of oil and gas resources.

After independence, the national Government realized the importance of oil and gas for rapid

industrial development and its strategic role in defence. Consequently, while framing the Industrial Policy

Statement of 1948, the development of petroleum industry in the country was considered to be of utmost

necessity.

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. (a 50%

joint venture between Government of India and Burmah Oil Company) 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 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, 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. The department was constituted with a nucleus of geoscientists fromthe Geological survey of India.

A delegation under the leadership of Mr K D Malviya, the-then Minister of Natural Resources,

visited several European countries to study the status of oil industry in those countries and to facilitate the

training of Indian professionals for exploring potential oil and gas reserves. Experts from Romania,

the Soviet Union, the United States and West Germany subsequently visited India and helped the

government with their expertise. Soviet experts later drew up a detailed plan

for geological and geophysical surveys and drilling operations to be carried out in the 2nd Five Year Plan

(1956-57 to 1960-61).

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 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,

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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

programmes 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.

1961 to 2000

Since its inception, ONGC has been instrumental in transforming the country's limited upstream

sector into a large viable playing field, with its activities spread throughout India and significantly in

overseas territories. In the inland areas, ONGC not only found new resources in Assam but also established

new oil province in Cambay basin (Gujarat), while adding new petroliferous areas in the Assam-Arakan Fold

Belt and East coast basins (both inland and offshore). ONGC went offshore in early 70's and discovered a

giant oil field in the form of Bombay High, now known as Mumbai High. This discovery, along with

subsequent discoveries of huge oil and gas fields in Western offshore changed the oil scenario of the

country. Subsequently, over 5 billion tonnes of hydrocarbons, which were present in the country, werediscovered. The most important contribution of ONGC, however, is its self-reliance and development of

core competence in E&P activities at a globally competitive level.

ONGC became a publicly held company in February 1994, with 20% of its equity were sold to the

public and 80% retained by the Indian government. At the time, ONGC employed 48,000 people and had

reserves and surpluses worth 104.34 billion, in addition to its intangible assets. The corporation's net

worth of 107.77 billion was the largest of any Indian company.

In 1958 the then Chairman, Keshav Dev Malaviya, held a meeting with some geologists in the

Mussoorie office of the Geology Directorate where he accepted the need for ONGC to go outside India too

in order to enhance Indian owned capacity for oil production. The argument in support for this step, by LP

Mathur and BS Negi, was that Indian demand for crude would go up at a faster rate than discoveries by

ONGC in India.

Malaviya followed this up by making ONGC apply for exploration licences in the Persian Gulf. Iran

gave ONGC four blocks and Malaviya visited Milan and Bartlesville to request ENI and Phillips Petroleum to

join as partners in the Iran venture. This resulted in the discovery of the Rostum oilfield in the early 'sixties,

very soon after the discovery of Ankleshwar in Gujarat. This was the very first investment by the Indianpublic sector in foreign countries and oil from Rostum and Raksh was brought to Cochin where it was

refined in a refinery built with technical assistance from Phillips.

2000 to present

In 2003, ONGC Videsh acquired Talisman Energy's 25% stake in the Greater Nile Oil project. In 2006

a commemorative coin set was issued to mark the 50th anniversary of the founding of ONGC, making it

only the second Indian company (State Bank of India being the first) to have such a coin issued in its

honour.

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In 2011, ONGC applied to purchase of 2000 acres of land at Dahanu to process offshore gas. ONGC

Videsh, along with Statoil ASA (Norway) and Repsol SA (Spain), has been engaged in deep-water drilling off

the northern coast of Cuba in 2012. On 11 August 2012, ONGC announced that it had made a large oil

discovery in the D1 oilfield off the West coast of India, which will help it to raise the output of the field

from around 12,500 barrels per day (bpd) to a peak output of 60,000 bpd.

In November 2012, ONGC Videsh agreed to acquire ConocoPhillips' 8.4% stake in the Kashagan

oilfield in Kazakhstan for around US$5 billion, in ONGC's largest acquisition to date. The acquisition is

subject to the approval of the governments of Kazakhstan and India and also to other partners in theCaspian Sea field waiving their pre-emption rights. ONGC is currently the most profitable Public Sector Firm

of India. It has topped the coveted list of top ten most profit-making PSUs of India for the year of 2011-12.

ONGC Videsh

ONGC Videsh Limited (OVL) is the international arm of ONGC. It was rechristened on 15 June 1989.

It currently has 14 projects across 16 countries. Its oil and gas production reached 8.87 MMT of O+OEG in

2010, up from 0.252 MMT of O+OEG in 2002/03.

ONGC Tripura Power Company

ONGC Tripura Power Company Ltd (OTPC) is a joint venture which was formed in September 2008

between ONGC, Infrastructure Leasing and Financial Services Limited and the Government of Tripura. It is

developing a 726.6 MW CCGT thermal power generation project at Palatana in Tripura which will supply

electricity to the power deficit areas of the north eastern states of the country.

ONGC Ahmedabad

ONGC Ahmedabad was established in 1961 with the first onshore production started in 1961 from

Ankleshwar. Production in the 1st year of production was 0.044 MMT with peak production achieved of

9.67 MMT in 1989-90.

1st

well drilled: 31st

March 1957 (Jawlamukhi)

1st SRP: 1970 (Nawagam # 38)

Total wells drilled: 2280

Oil wells: 1420 Gas wells: 41

Water injection wells: 291

Effluent injection wells: 68

Ahmedabad Asset Oil Fields

Area-I: Kalol, Motera, Wadu, Paliyad,Veer Govindpura

Area-II: Ahmedabad, Nawagam, Nandej, Wasna, Mehlaj, Hirapur, Asmali, Sadra, Vatrak

Area-III: Sanand, Jhalora, Viraj, South-Kadi,Wamaj, Sviraj

Area-IV: Limbodra, Gamij, Walod, Halisa

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Introduction to Surface Operations:

The production of oil is being obtained from three types of wells:-

(i) Self Drive wells

(ii) Sucker Rod Pump (SRP) wells

(iii) Artificial Lift wells

Self-drive wells have their own pressure to produce. Sucker Rod Pumps works on the

principle of hand pumps to produce form the well. And in Artificial Lift wells either gas is

injected or water is injected for the production of oil. The wells having a high flux are

mainly subjected to artificial lift. The gas injection can be done as a continuous process or

can be done in a fixed interval process.

The crude fluids - which contain water, crude oil and gas - produced from the various

fields are being transported through pipelines to a Group Gathering Station (GGS). In a GGS,

the hydrocarbon fluids are being separated from impurities and water by the process of

three stage separator which separates the fluids on the basis of acceleration due to gravity

and retention time. The produced gas is being transported through pipelines to Gas

Collecting Station (GCS). In a GCS, the collected gas is subjected to a gravity separation

through various types of separators like high pressure separators, low pressure separators

and group separators. The processed crude oil from many GGSs is being transported

to a Central Tank Farm (CTF) where again the crude oil is subjected to separation processin a “heater treater” which also works with a dozing of de-emulsifier injection before the

inlet followed by heating process in the first stage, gravity settling in the second stage and

the third stage is electrostatic separation.



Later on the processed crude is being transported to the Desalter plant for the

further reduction of the water content of the crude oil to 0.09%- 0.10%. In a desalter plant,

the received oils again subjected to three stage separation process after which final crude

oil is recovered with 0.10% water cut which is being transported through pipeline to the

nearby refinery for production of finished products. The collected gas at GCS is at very

low pressure of about 2-5 kgf/cm2

pressure which is being transferred to a GasCompression Plant (GCP) to compress the gas to a pressure of 40-45 kgf/cm

2to use the gas

for the injection process for enhance oil recovery through GCS. The waste water collected

from all separation processes are being sent to Effluent Treatment Plant (ETP) where the

trace oil is being recovered from the waste water. The treated water is being sent to a

Water Injection Plant (WIP) which is being pumped to various wells for enhance oil recovery

process. The recovered water from Desalter Plant is being sent to Waste Water

Treatment Plant (WWTP).



ARTIFICIAL LIFTS

Most oil reservoirs are of the volumetric type where the driving mechanism is the

expansion of solution gas when reservoir pressure declines because of fluid production. Oil

reservoirs will eventually not be able to produce fluids at economical rates unless natural

driving mechanisms (e.g., aquifer and/or gas cap) or pressure maintenance mechanisms

(e.g., water flooding or gas injection) are present to maintain reservoir energy. The onlyway to obtain a high production rate of a well is to increase production pressure

drawdown by reducing the bottom-hole pressure with artificial lift methods.

Approximately 50% of wells worldwide need artificial lift systems. The commonly used

artificial lift methods include the following:

. Sucker rod pumping

. Gas lift

. Electrical submersible pumping

. Hydraulic piston pumping

. Hydraulic jet pumping

. Plunger lift

. Progressing cavity pumping

Sucker Rod Pumping:-

Sucker rod pumping is also referred to as ‘‘beam pumping.’’ It provides mechanicalenergy to lift oil from bottom hole to surface. It is efficient, simple, and easy for field people

to operate. It can pump a well down to very low pressure to maximize oil production rate. It

is applicable to slim holes, multiple completions, and high-temperature and viscous oils.

The system is also easy to change to other wells with minimum cost. The major

disadvantages of beam pumping include excessive friction in crooked/ deviated holes, solid-

sensitive problems, and low efficiency in gassy wells, limited depth due to rod capacity, and

bulky in offshore operations. Beam pumping trends include improved pump-off controllers,

better gas separation, gas handling pumps, and optimization using surface and bottom-hole

cards.



Rod Pump Operation – Concept

a) Pump grabs a “bite” of fluid on each down stroke of the pump, as the

“mouth” of the traveling valve opens on the down stroke, and grabs a bite of

whatever is within the compression chamber.

b) Upstroke closes the traveling valve, traps the fluids in the chamber and physically lifts

them up the well a few feet. This bite is simply stacked below the previous bite until

enough bites start running out at the surface of the well.

c) Standing Valve opens at the start of upstroke to admit fluids into the compression

chamber from the reservoir, and closes on down stroke of pump to prevent these fluids

from returning to the formation.



Advantages:-

• Provides mechanical energy to lift oil

• Efficient, simple and easy to operate

• High system efficiency.

• Optimization controls available.

• Economical to repair and service.• Positive displacement / strong drawdown.

• Upgraded materials reduce corrosion concerns

Disadvantages:-

•Excessive friction in crooked/deviated holes

•Solid-sensitive problems

•Less effective in high gas-oil ratios

•Limited depth due to rod capacity•Bulky in offshore operations.



Gas Lift System:-

Gas lift technology increases oil production rate by injection of compressed gas into

the lower section of tubing through the casing –tubing annulus and an orifice installed in the

tubing string. Upon entering the tubing, the compressed gas affects liquid flow in two ways:

(a) The energy of expansion propels (pushes) the oil to the surface and(b) The gas aerates the oil so that the effective density of the fluid is less and, thus,

easier to get to the surface.

There are four categories of wells in which a gas lift can be considered:

1. High productivity index (PI), high bottom-hole pressure wells.

2. High productivity index (PI), low bottom-hole pressure wells.

3. Low productivity index (PI), high bottom-hole pressure wells.

4. Low productivity index (PI), low bottom-hole pressure wells.

Wells having a PI of 0.50 or less are classified as low productivity wells. Wells having a

PI greater than 0.50 are classified as high productivity wells. High bottom-hole pressures

will support a fluid column equal to 70% of the well depth. Low bottom-hole pressures will

support a fluid column less than 40% of the well depth.

Gas lift technology has been widely used in the oil fields that produce sandy and

gassy oils. Crooked/deviated holes present no problem. Well depth is not a limitation. It is

also applicable to offshore operations. Lifting costs for a large number of wells are generally

very low. However, it requires lift gas within or near the oil fields. It is usually not efficient

in lifting small fields with a small number of wells if gas compression equipment is required.

Gas lift advancements in pressure control and automation systems have enabled the

optimization of individual wells and gas lift systems.

Purpose: Decrease pressure at reservoir and increasing production rate.



Continuous Gas Lift

A continuous gas lift operation is a steady-state flow of the aerated fluid from

the bottom (or near bottom) of the well to the surface. In continuous gas lift, a small

volume of high-pressure gas is introduced into the tubing to aerate or lighten the fluid

column. This allows the flowing bottom-hole pressure with the aid of the expanding

injection gas to deliver liquid to the surface. To accomplish this efficiently, it is desirable todesign a system that will permit injection through a single valve at the greatest depth

possible with the available injection pressure.

Intermittent Gas Lift

Intermittent gas lift operation is characterized by a start-and-stop flow from the bottom

(or near bottom) of the well to the surface. This is unsteady state flow. Intermittent gas lift

method is suitable to wells with (1) high PI and low reservoir pressure or (2) low PI and low

reservoir pressure. In intermittent gas lift method, the high pressure gas is injected in the

tubing to reduce the density of production fluid and hence bring drawdown. The injection

of gas causes slug flow in the tubing where fluid column is lifted upward by gas. The vital

part of intermittent gas injection is the time cycle of injection.

Gas Lift Installations:

There are three types of gas lift installations

(A) Open installation

(B) Semi closed installation

(C) Closed installation

Open installation

In the open gas lift installation, the tubing is simply hung inside the casing string, andno packer is run in the well. This is the original installation type used in early day of

gas lifting when no gas lift valves were installed on the tubing.

Semi closed installation

This has a packer installed in the tubing to seal off the tubing-casing annulus.

This is most common type of installation for continuous gas lift well. The packer

keeps produced fluid from entering the annulus, and prevents the casing pressure

directly communicating with formation. This installation is also used in intermittent

gas lift wells. It is not the best choice for wells exhibiting very low B.H.P.



Closed installation

This is similar to semi-closed installation, except that a standing valve is placed in the

tubing string below the bottom gas lift valve to prevent fluids from moving onward.

Thus the high pressure gas injected into the tubing from the annulus can’t

increase backup pressure on formation; any produced fluid standing in the tubing will

not flow back into the formation. These features make the closed installation theoption of choice for intermittent gas lift.



Applications:

• Continuous or intermittent flow.

• Tubing and casing flow.

• Wells where pressurized injection gas is readily available.

• Wells with insufficient BHP; deep wells that cannot flow against hydrostatic head.

• Kick off wells that will flow naturally once heavier completion fluids arevacated from production spring.

• Unload water from gas wells that would otherwise prevent gas production.

• Tolerance to sand and solids production.

Advantages:

• High degree of flexibility and design rates.

• Subsurface equipments are wire line retrievable.• Handles sandy conditions well.

• Allows for full bore tubing drift.

• Surface wellhead equipment requires minimal space.

• Multi-well production from single compressor.

• Multiple or slim hole completion.

Disadvantages:

• Needs high-pressure gas well or compressor.

• Single well application may be uneconomical.

• Performance dependent on fluid viscosity.

• Application limited by bottom-hole pressure.

• It applies High back-pressure.



Group Gathering Station (GGS):

GGS (Group Gathering Station) is an installation which receives oil through manifolds

from its different assigned fields. Oil is separated here in the form of oil, gas and water.

Separated oil is sent to CTF (Crude Tank Farm) for further treatment, separated gas is sent

to GCP (Gas Compressor Plant) through GCS (gas collecting station) in order to receive back

compressed gas is sent at 3kgf/cm2 and received back at 41kgf/cm2. Water from GGS is sentto ETP (Effluent Treatment Plant) and then to CWIP (Central Water Injection Plant) for its

further treatment. This treated water finally from CWIP is sent back to GGS after its

treatment to impart water injection programme for different wells. Both water injection

and gas injection programmes are carried out and controlled by GGS.

Process Description: - Oil is received in GGS following headers

1. Group header

2. Test header

3. Emulsion header

4. High pressure header

Group Header (oil & gas):-

Well fluid from the wells to header, to bath heater, for preheating & then to group

separator .Oil water mixture after separation of gas in group separator goes to heater-treater for emulsion treatment .Oil from heater-treater goes to oil storage tank & from

tank it goes it is pumped to CTF with the help of oil dispatch pumps. Gas from the group

separator goes to booster compressor for compression and goes to the gas grid of GCS from

GGS which is measured by flow recorder.

Test Header (oil & gas):-

One test header with section valve is provided to facilitate testing of individual wells

one well can be tested one at a time. The well to be tested is diverted to test separatorwhere liquid and gas separation take place. Gas is sent to gas grid and oil flows into two

Tank cum Separators (TCS). Metering facility is provided for oil & gas.

Emulsion Header:-

Well fluid flows from the wells to header and goes to emulsion separator for separating

liquid and gas. Liquid goes to heater treater for emulsion separation; oil from heater treater

goes to oil storage tank and gas from emulsion separator and heater treater goes to the gas

grid of GCS which is measured by flow recorders.



Various operating systems of Group Gathering System are as follow:-

MANIFOLD: -

Purpose:

• To group the wells based on their pressure.

• To group the wells based on quality of oil, i.e. pure or emulsion• To isolate any wells for testing purpose.

• To divert wells to the required header through operation of valves

SEPARATOR: -

It is primarily used to separate a combined liquid-gas well stream into

components that are relatively free of each other. The name separator usually is applied

to the vessel used in the field to separate oil and gas coming directly from oil or gas well, or

group of wells.

Separators are classified as “two-phase” if they separate gas from the total

liquid stream and “three-phase” if they also separate the liquid stream into its crude oil and

water components. Scrubber is a type of separator which has been designed to handle flow

streams with unusually high gas to liquid ratios. Most of the separators that were installed

in ONGC were two phase vertical separator with working pressure of 6 kgf/cm2

and tested

at 9 kgf/cm2

with safety valve opening at 6.6 kgf/cm2.

Components / Sections of a Separator

• Primary Separation Section

• Liquid Accumulation Section

• Secondary / Gravity Settling Section

• Mist Extraction / Coalescing section

Inlet Diverter / primary separation section: The inlet stream to the separator is typically a

high-velocity turbulent mixture of gas and liquid. Due to the high velocity, the fluids enterthe separator with a high momentum. The inlet diverter, sometimes referred to as the

primary separation section, abruptly changes the direction of flow by absorbing the

momentum of the liquid and allowing the liquid and gas to separate. This results in the

initial “gross” separation of liquid and gas.

Liquid Accumulation Section: The liquid collection section, located at the bottom of the

vessel, provides the required retention time necessary for any entrained gas in the

liquid to escape to the gravity settling section. In addition, it provides a surge volume to

handle intermittent slugs. The degree of separation is dependent on the retention timeprovided. Retention time is affected by the amount of liquid the separator can hold, the



rate at which the fluids enter the vessel, and the differential density of the fluids. Liquid-

liquid separation requires longer retention times than gas-liquid separation.

Gravity Settling Section: As the gas stream enters the gravity settling section, its

velocity drops and small liquid droplets that were entrained in the gas and not

separated by the inlet diverter are separated out by gravity and fall to the gas

liquid interface. The gravity settling section is sized so that liquid droplets greater than 100to 140 microns fall to the gas-liquid interface while smaller liquid droplets remain with the

gas. Liquid droplets greater than 100 to 140 microns are undesirable as they can

overload the mist extractor at the separator outlet.

Mist Extractor Section: Gas leaving the gravity settling section contains small liquid

droplets, generally less than 100 to 140 microns. Before the gas leaves the vessel, it

passes through a coalescing section or mist extractor. This section uses coalescing elements

that provide a large amount of surface area used to coalesce and remove the small droplets

of liquid. As the gas flows through the coalescing elements, it must make numerousdirectional changes. Due to their greater mass, the liquid droplets cannot follow the rapid

changes in direction of flow. These droplets impinge and collect on the coalescing

elements, where they fall to the liquid collection section.

Classification of separator:

(1)Horizontal separator

(2)Vertical separator

(3)Spherical separator

Normally vertical or horizontal two phase separators are being used in ONGC.

Horizontal Separators:

The fluid enters the separator and hits an inlet diverter, causing a sudden

change in momentum. The initial gross separation of liquid and vapour occurs at the

inlet diverter. The force of gravity causes the liquid droplets to fall out of the gasstream to the bottom of the vessel, where it is collected. The liquid collection section

provides the retention time required to let entrained gas evolve out of the oil and rise

to the vapour space and reach a state of equilibrium. The liquid leaves the vessel

through the liquid dump valve. The liquid dump valve is regulated by a level controller.

The level controller senses changes in liquid level and controls the dump valve

accordingly. Gas and oil mist flow over the inlet diverter and then horizontally through the

gravity settling section above the liquid. As the gas flows through this section, small

droplets of liquid that were entrained in the gas and not separated by the inlet diverter areseparated out by gravity and fall to the gas-liquid interface. Some of the drops are of such a



small diameter that they are not easily separated in the gravity settling section. Before the

gas leaves the vessel, it passes through a coalescing section or mist extractor. This section

uses elements of vanes, wire mesh, or plates to provide a large amount of surface area

used to coalesce and remove the very small droplets of liquid in one final separation

before the gas leaves the vessel. The pressure in the separator is maintained by a pressure

controller mounted on the gas outlet. The pressure controller senses changes in the

pressure in the separator and sends a signal to either open or close the pressure controlvalve accordingly. By controlling the rate at which gas leaves the vapour space of the vessel,

the pressure in the vessel is maintained and balanced.

Vertical Separators:

As in the horizontal separator, the inlet diverter does the initial gross

separation. The liquid flows down to the liquid collection section of the vessel. There are

seldom any internals in the liquid collection section except possibly a still well for

the level control float or displacer. The still well usually consists of walled box or tube,open on the top and bottom. Its function is to stop wave action in the separator from

interfering with the level controller’s operation. Liquid continues to flow downward

through this section to the liquid outlet. As the liquid reaches equilibrium, flow and

eventually migrate to the vapour space. The level controller and liquid dump valve operate

the same as in a horizontal separator. The gas flows over the inlet diverter and then

vertically upward toward the gas outlet. Secondary separation occurs in the upper gravity

settling section. In the gravity settling section the liquid droplets fall vertically downward

counter velocity of a liquid droplet is directly proportional to its diameter. If the size of a

liquid droplet is too small, it will be carried up and out with the vapour. Thus, a mistextractor section is added to capture small liquid droplets. Gas goes through the mist



extractor section before it leaves the vessel. Pressure and level are maintained as in a

horizontal separator. Vertical separators are commonly used in flow streams with low to

intermediate gas-liquid ratios. They are well suited for production containing sand and

other sediment and thus are often fitted with a false cone bottom to handle sand

production.

Spherical Separators

Spherical separators are a special case of a vertical separator where there is nocylindrical shell between the two heads. Fluid enters the vessel through the inlet diverter

where the flow stream is split into two streams. Liquid falls to the liquid collection section,

through openings in a horizontal plate located slightly below the gas-liquid interface. The

thin liquid layer across the plate makes it easier for any entrained gases to separate and

rises to the gravity settling section. Gases rising out of the liquids pass through the mist

extractor and out of the separator through the gas outlet. Liquid level is maintained by a

float connected to a dump valve. Pressure is maintained by a back pressure control valve

while the liquid level is maintained by a liquid dump valve. Spherical separators were

originally designed to take advantage, theoretically, of the best characteristics of both



horizontal and vertical separators. In practice, however, these separators actually

experienced the worst characteristics and are very difficult to size and operate.

They may be very efficient from a pressure containment standpoint, but because (1) they

have limited liquid surge capability and (2) they exhibit fabrication difficulties, they are

seldom used in oil field facilities.

CHEMICAL DOSING SYSTEM: -

Purpose:

• To mix demulsifier chemicals into emulsion oil before it enters heater treater.Process:

• Demulsifier chemical is pumped into emulsion oil stream before heater-

treater. To obtain optimum results proper dosing element should be injected.

HEATER TREATER: -

Purpose:

• Demulsification of oil into oil and water by chemical thermal and electrical

means.



Process:

Heater treater is a horizontal vessel employing a vertical flow pattern. Methods

of heating, chemical action, electrical coalescence, water washing of oil & settling for

demulsfication are used. Movements of fluids are controlled by differential pressure

combined with static head. Parts/components of heater treater are:

• Inlet degassing section

• Heating section

• Differential oil control chamber

• Coalescing section (Electrical chamber)

Inlet degassing section:

Emulsion oil from separator is first mixed with demulsifier & then taken into

heater treater. Emulsion oil first enters inlet degassing section. A fire tube is fitted in theheater-treater encompassing degassing section & heating section. Due to the effect of heat,

the free gas in emulsion oil is liberated & then enters into heating chamber through the

equalizer. The fluid enters into the heating chamber through multiple orifice distributors.

Heating section:

This section consists of a fire tube bent at 180°.The constant level in maintained by weir

height. Oil enters this section from bottom of degassing section & passes through

heater at bottom and washing action takes place & free water & solids fall out of oil

stream. The water level in this section is controlled by a weighted, displacement type

interface control valve. The oil and entrained water flow upwards from the distributors

around the fire tubes, where the required temperature is reached. The increase in

temperature of oil releases some additional gas. The heat released gas then joins the free

gas from the inlet section and is discharged from the treater through a gas pressure control

valve. Burners are designed for maximum heat output with minimum fuel consumption and

maintenance requiring little adjustments. Pilots are fixed type and require no adjustments.

Fuel gas supply is to be properly adjusted and regulated which is free of liquids & solidparticles.

Differential oil chamber:

The fluids from the heating chamber enter into this chamber through a fixed where it does

not allow the gas to pass into electrical chamber which is hazardous. The gas which enters

heating chamber through equalizer leaves the heater treater from the top of this chamber

through a mist extractor contained in a centrifugal scrubber. From scrubber the gas

releases into a gas line through back pressure control valve, which maintains the pressure



of vessel. The oil level in the chamber is controlled by the oil level controller which operates

through a float.

Coalescing Section (Electrical Chamber):

Heater treater uses a high voltage potential on the electrodes for coalescing of water

droplets in the final phase of processing. The electrodes are suspended on the insulatedhanger from the upper portion of vessel. The ‘Ground’ electrode is furnished with solid

steel hangers to ensure grounding with the steel of the treater. An externally mounted, oil

immersed high voltage transformer is furnished to provide the power to electrodes.

The transformer uses 240 volts in primary & supplied about 16500 volts in secondary. The

high voltage secondary is connected to charged electrode through a specially designed

high voltage entrance bussing for insulation. Secondary is also connected to voltmeter &

external pilot indicating lamp. The oil & entrained water enter the coalescing section from

the differential control chamber through multiple, full length distributors. As the oil &

entrained water come into contact with electrical field in the grid area, final coalescing of water takes place. The water falls back to the water area at the bottom and the clean oil

continues to rise to the top, where it enters a collector and is discharged through the clean

oil outlet control valve.



STORAGE SYSTEM: -

Purpose:

• To store oil before pumping

• To measure oil produced

Process:

• Oil from heater-treater and separator is taken into overhead cylindrical tanksfor measurement.

OIL DESPATCH SYSTEM: -

Purpose:

• To dispatch oil from GGS to CTF.

Process:

• To store oil before pumping

• To measure oil produced from heater-treater and separator is taken into

overhead cylindrical tanks for to dispatch oil from GGS to CTF.• Oil is pumped from storage tanks to CTF by reciprocating pumps.

EFFLUENT DISPOSAL SYSTEM: -

Purpose:

• To dispose effluent water from effluent handling tanks to effluent treatment

plant.

Process:

• Effluent water is disposed by pumping effluent to effluent treatment plant

through pipeline.

WATER INJECTION MANIFOLD: -

Process:

• To divert water in water injection wells.

• To monitor water injection in water injection wells.Purpose:

• Water coming from water injection plant is diverted to different water

injection wells through different lines of wells.



Central Tank Farm (CTF): -

FUNCTION:

CTF only receives the oil from GGS. Two types of oil are received from GGS;

treated as well as untreated oil. Treated oil is directly dispatched to desalter plant through

dispatch pumps, removal of water effluent from oil. Water cut of around 5% is maintainedat CTF plant and the water cut is further reduced to 0.25%with the removal of salts at the

desalter plant. The main function o of CTF is to maintain water cut of fluid to 5% and is sent

to desalter plant for further treatment.

Various operating systems of central tank farm are as follow:-

MANIFOLDS: -

Purpose:

• To receive oil from GGS in controlled manner

• Both treated and untreated oil is received from the manifold

STORAGE TANKS: -

Purpose:

• They are used to store the treated and untreated oil from GGS

• They help in taking measurements of oil collected and how much to bedispatched.

(In Kalol, there are 18 storage tanks of 1-10 with each 2000 m3 and 11-18 with

each 10000 m3. In Nawagam, there are 8 storage tanks with each 2000 m3.)

HEATER TREATER: -

Purpose:

• Demulsification of oil into oil and water by chemical thermal and

electrical means.

The process has been explained in the GGS installation part.

EFFLUENT STORAGE TANK: -

Purpose:

• It is used for storing water effluent. These effluents are removed from heater

treater and they are directed to effluent storage tank.



OIL RECOVERY PUMPS:-

Purpose:

• In the effluent storage tank water effluent settles at the bottom and oil is

recovered at its top.

These oil recovery pumps help in pumping the recovered oil to the dispatch pumps.

EFFLUENT PUMPS:-

Purpose:

• These pumps help in pumping the discharged effluent from effluent

tank to ETP (effluent treatment plant) for its further treatment.

DISPATCH PUMPS:-

Purpose:

• They are in the final stage of the whole process of CTF plant. Their

main function is to dispatch or pump the oil recovered to desalter plant

where removal of further salts take place and water cut till 0.25% is

achieved which is in accordance to the refineries norms and regulations.

Commonly centrifugal pumps are used. The figure shows a common centrifugal pump

with its working. The capacity of the pump will depend on the work that the pump is used

in.



Gas Collecting Station (GCS): -

Function:

Its main function is gas collection and distribution. GCS receives associated gas from

GGS and the dry gas directly from the transferred to GCP (Gas Compressing Plant) for their

further compression. Now the compressed gas is back by GCS and is sent to GGS for gasinjection in the gas lift wells.

Overall Process:-

Gas lines from different wells are connected to theTest Header. It is followed by Low

Pressure Header (LP), High Pressure Header (HP) and Group Header (GP) connected to

separators. The associated gas is initially dubbed "wet gas" as it is saturated with water and

liquid alkanes. The gas is typically routed through scrubbers, compressors and coolers

which will remove the bulk of the liquids. This “dry gas” may be exported, re-injected into

the reservoir, used for gas lift, flared or used as fuel for the installation's power generators.

The gas from the separators is either sent to consumers at low pressures or sends to GCP

(Gas Compressing Plant) to compress the gas and increase thepressure to deliver it to long

distance consumers or eject in the well for gas lift. The pressure in LP pipes are about 2-4

kgf/cm2

and gas which comes back from GCP is around 40Kg/cm2.

The important operations in GCS are as follows: -

Gas Collection: -

The gas from different wells is collected through the valve manifold. The manifold is used to

collect the gas in a controlled manner. The gas collected from the wells is wet and

contains liquid alkanes.

Gas Measurement (input):-

The collected gas is passed through the Test Header, which measures the amount of gas collected from each individual well. Then the gas is passed to the Group Header from

where it is sent to the separators.

Gas Separation:-

The measured gas is then passed through the separators which will remove the bulk of

liquids from the associated gas. There are different types of separators used in the station

to free the gas from liquid. The associated liquid collected issent to CTF.



Gas Measurement (output):-

The separated gas is then passed through Gas Measurement Systems to measure the

amount of gas output. This gas is either exported to consumer, which consumes gas at LP or

sent to GCP to compress the gas and use it for Gas lift andexporting it to distant consumers.

The main purpose of GCS is separation of associatedliquids from the gas. This process is

carried out by using different types of separators.

The following separators were used in GCS Kalol:

• Associated Gas Scrubber

• Group Separator ( 2 stage separator)

• LP Separator

• HP Separator

The consumers of GCS Kalol are:

• IFFCO

• GAIL

• GCP

Gas Analysis:-

COMPOUND MOL%

Methane(CH4) 87.150

Ethane(C2H6) 5.22

Propane(C3H8) 2.5

I-butane 1.35

N-butane 0.82

I-pentane 0.36

N-pentane 0.39

Hexane 0.68Heptane 0

Octane 0

Nonane 0

Decane plus 0

Carbon di oxide(CO2) 1.36

Nitrogen(N2) 0.160

Water(H20) 0

Hydrogen sulphide(H2S) 0Carbon Monoxide(CO) 0



Oxygen(O2) 0

Helium(He) 0

Argon 0



GAS COMPRESSION PLANT (GCP): -

About

The Gas Compression plant, ONGC is located in Kalol, Ahmedabad. Its function is to

compress the gas. It has a capacity of 150000 m3/day. It hasa total of 10 gas compressors (6

in old plant and 4 in new plant) and a water treatment plant with 2 reverse osmosisplant and chemical treatment plant. The main function of GCP is to compress the gas it

receives from Gas Collecting Station (GCS) and then send it back to GCS and other receivers

like Reliance, IFFCO etc. It receives gas from GCS at about 3 kgf/cm2

and compresses it in

two stages to about 40 kgf/cm2. In the first stage it compresses the gas to 12 kgf/cm

2and in

the second stage it compresses it to 40 kgf/cm2.This gas is then received by GGS through

GCS and here itis used for gas injection in gas lift wells. It uses demineralized and pure

water to cool this gas in gas coolers.

Plant Description:

The various components of the plants are

• Inlet Separator

• Gas Compressors

• Discharge separator

• Condensation Drum

• Gas Coolers• Reverse Osmosis Plant

• Degasser tank

• Cation and anion exchangers

• Cooling tower

INLET SEPERATOR:

Purpose:

To separate liquid hydrocarbons from the gas coming from GCS (gas collectionstation)

Process:

It has baffles which helps in separating gas from condensate at the

reduced temperature and pressure of separator.



GAS COMPRESSORS:

Purpose:

Its main purpose is to compress gas at high pressure to increase its flowing

pressure.

Process:The compression is done in two steps. In the first step the gas is compressed to

12 kgf/cm2

and in the second step it is compressed to 40 kgf/cm2.

DISCHARGE SEPERATOR:

Purpose:

It’s a final stage separator in which the gas from inter gas cooler is

received after cooling. Again here final separation of the gas from condensate

takes place, and the gas evolved is further sent to GCS (gas collection station). Itsfunction is same as inlet separator.

CONDENSATE DRUM:

This is the storage drum for the condensates which receives the liquid hydrocarbons

from the inlet, suction and discharge separator. The gas is set to cold flare while the liquid

hydrocarbons, left at the bottom of the drum, is sent to the Central Tank Farm for further

treatment through a condensate transfer pump.

GAS COOLERS:

It is a type of heat exchanger. It contains baffles and one shell and two tubes pass

exchanger system. It is used to cool the gas. It is done at two points (receiving gas

from first stage compression and second stage compression)- inter gas cooler and after

gas cooler. In this heat exchanger, water enters from one side and the gas from other side.

Here, counter current flow takes place. And hence the gas is cooled.

RAW WATER STORAGE TANK:

The raw water which comes from submersible pump is stored in this tank. It is then

passed to R.O. plant for its processing.

REVERSE OSMOSIS PLANT:

Its function is to remove the TDS (Total Dissolved Solids) from the raw water.

Some of the chemicals like Sodium Hydrosulphite, Sulphuric acidand Sodium Hypochloriteare also used for this purpose. The water is passed through the membranes. The TDS does



not pass through the membrane and is stored in a separate vessel. The treated water is

further passed to the degasser tank.

DEGASSER TANK:

In the Degasser tank, carbon dioxide and sulphuric acid removal takes place. Gasses

removed are blown by blower so that it remains at the top while the water is passed to thecation and anion exchange towers.

CATION AND ANION EXCHANGE TOWERS:

The basic function of this tower is to remove the hardness content in the water and

different salts, sulphates etc. Here exchange of ions take place between electrolytes. After

that process, water is sent to the cooling tower.

COOLING TOWER:

It is used to cool water. From here, water is passed to the gas coolers. The cold water

is required to cool the hot gas in the heat exchanger.



Desalter Plant: -

Introduction:-

The oil we get directly from the reservoir containsmany unwanted components

which are required to be removed by the upstream industries before it is sent to the

refineries. The unwanted components include the saline water, different emulsifications of oil and water, drilling fluids and other formation chemicals. These are required to be

removed before it is sent to the refineries. Crude oil from different wells is first sent to

GGS (Group Gathering Station). Here, the oil is coming from different wells is collected at

a single station. From GGS the oil is received at thede-salter plant. From there it is sent to

CTF (Central Tank Farm).

North Gujarat crude is presently processed at de-salter plant and it transported

to Koyali refinery at Vadodara by KNK pipeline. The crude produced from north Gujarat is

having high salinity and high BS&W content. in order to reduce the salinity and BS&W

content to the limit which match the requirement of refinery ,ONGC decided to put a

centralized de-salter plant at Nawagam Gujarat where all North Gujarat oil is

processed before pumping to refinery. Produced water from the de-salter vessel are

sent to WWTP for further treatment & dispatch to ETPS of GGS-II & GGS-III,

Nawagam, for sub surface disposal.

DESALTER PLANT: NAWAGAM

A desalter is a process unit on an oil refinery that removes salt from the crude oil.

The salt is dissolved in the water in the crude oil, not in the crude oil itself. The desalting is

usually the first process in crude oil refining. The salt content after the desalter is

usually measured in PTB (pounds of salt per thousand barrels) of crude oil.

Desalter Process:-

Desalter plant is having three trains and 330 m3/hr oil (max.) is treated in each train.

Crude from tank is pumped through feed pump at 10 kgf/cm2 pressure to the heatexchanger at 30°C and heated up to 60°C by hot crude feed from desalter vessel. From heat

exchanger it is routed through gas fired heater where it is heated up to 90°C in two stages

and this heated crude is mixed with wash water through mixing valve and feed to

desalter vessel at kgf/cm2

(there are two desalter valve in each train having holding

capacity is 255m3 and new vessel having holding capacity of 270 m3 can put in series or

we can put stand alone vessel in line at a time) where oil and salty water in incoming

feed is separated by electrostatic means in the desalter. On application of high voltage

electric field water droplet in the oil coalesce and settle down due to the density difference

taking along with them other solid particles present in the feed. The product crude is



taken out from the top of the desalter and is cooled to 50°C by exchanging heat

with heat exchanger and this processed crude is send to storage tank. Where again

residual water is drained and TMB crude sample is taken from the tank for testing

in chemical laboratory for conforming whether the crude meets the requirement of

the refinery otherwise again processed crude is send for reprocess through

reciprocating pump having capacity of 120 m3/hr. Processed crude from the storage tank

is pumped to CTF by booster pump, from CTF it is send to Koyali refinery at Vadodarathrough the KNK line.

PROCESS FLOW CHART:



2) Heat Exchanger:

Demulsifiers work better at high temperatures. So the treated crude oil which is very hot is

used at shell side and the untreated crude oil at the tube side is used in a shell and tube

heat exchanger. The exchanger very effectively heats up the crude oil and raises

Its temperature from 30°C to 55°C.

3) Economizer:

From heat exchangers oil is sent to economizers. Here the oil is further heated up to 65°C.

4) Heater:

This temperature of 65°C is not enough for effective demulsification oil and water.

For raising the temperature further it is sent to heater where it is heated through a burner.

Its temperature rises from 65°C to 90°C.

5) Desalter Vessel:

Final separation of oil and water takes place here.It contains a system of electrostatic grid

which is very effective in removing water from oil. It has two outlets for draining

water and the oil above the water is easily recovered in the floating type receiving

tank. The water which is drained through outlets contains 100 ppm of oil. This small

amount of oil is further recovered when it is sent to WWTP (Waste Water Treatment Plant).

6) Booster Pumps:-

Processed crude is send to CTF through 30” pipeline to CTF and from CTF to koyali Terminal.

To boost up the pressure for CTF, booster pump (10 P-115/116/117/118) having the

capacity of approx. 330 m3/hr is provided. At a time 3 booster pumps are running

For five pumps at CTF. Approximately 600 m3/hr crude is send to koyali Terminal from CTF.

7) Process Water System:

Wash water is required for efficient desalting of crude. Some water mixed with the

crude to enhance the separation water from crude. Raw water is used for this

purpose. Raw water is coming from bore wells. Total six bore wells are inthe plant but out

of six bore wells four are dried and fifth & six bore well is used. This water is stored in tanks

(T-101 A/B) having capacity of 600m3. Water and crude are mixed through mixing valve.

Process water pumps having capacity of 400 m3/hr provides for this purpose.



8) Fire Network:

Fire water pipeline (approximately 5 km) network is provided in case of any incident of fire

in desalter plant. There are 19 nos. of BGU/MCP, 15 Smoke detector, 51 gas detectors, 44

fire monitors and 106 fire hydrants are provided. Fire water line pressure is maintained at

10 kgf/cm2. This pressure is maintain with the help of Fire water pumps- 2 diesel

operated having capacity of 410m3

/hr and 1 electrical operated having capacity of 410m

3/hr and 2 Jockey pumps having capacity of 10m

3/hr. There are two fire water

reservoir having storage capacity of 3240m3

for fire water storage. Bore well water is

used as fire water.

EQUIPMENT CAPACITY & SPECIFICATION:



Effluent Treatment Plant (ETP): -

The main function of this plant is to collect effluent water coming from GGS and CTF

and treat that water. It is expected that this plant must receive water having 2000 ppm of

oil content. But sometimes this may not happen and hence oil must be removed and again

sent back to CTF from there. Finally the treated water is sent to water injection plant for

final treatment.

OPERATIONS:

Manifold:-

Its main function is to receive water effluent frominstallations like GGS, CTF and

lagoon in a controlled manner.

Storage Tank: -

It helps in storing effluent water obtained. Here oil and water is separated oil through

a pump is sent to lagoon and it is collected there as sludge. Mostly the storage tanks are

open roof type. Open roof types are preferred because the total cost of treatment is not

compensated in the floating roof type tanks. There are 2-3 tanks for storage depending

upon the discharge from installation.

Agitator: -

Its main function is to separate oil from water by addition of compounds like

alum, catalyst polymers and non-polymers. It consists of blades which agitates the water

withthe addition of above chemicals. Therefore water molecules are separated from oilmolecules. Finally after this process the whole solution is transferred to clari flocculator.



Clari flocculator: –

It helps in separation of oil from water. It consists of a huge circular cylindrical tank

with a hollow cylinder inside. The solution of oil and water enters through this hollow

cylinder with oil on top. Oil separates at the top of its periphery and pumped through

pump to lagoon and collected as sludge there. Whereas water is sent to filter for its further

purification.

Filter: -

Its purpose is to filter the water for the impurities and contaminants present in it.

The filter consists of membrane made up of sand andgravel. Water is circulated here and

all the particles are filtered by them. Back wash waterarrangement is also made in order to

clean the filter when its cleaning is required. After this the water is sent to conditioning

tank where pH level is maintained by the addition of chemicalslike SHMP. And finally the

treated water is sent to WIP (water injection plant) where it is mixed with treated rawwater and sent to GGS for water injection process.



Water Injection Plant (WIP): -

Water injection refers to the method in oil industry where water is injected

back into the reservoir, usually to increase pressure and therebystimulate production.

Water injection wells can be found both on- and offshore, to increase oilrecovery from an

existing reservoir.

Water is injected

(1) To support pressure of the reservoir (also known as void age replacement), and

(2) To sweep or displace oil from the reservoir, and push it towards a well.

Normally only 30% of the oil in a reservoir can be extracted, but water injection increases

that percentage (known as the recovery factor) and maintains the production rate of

a reservoir over a longer period of time.

Sources of injected water:-

Any and every source of bulk water can be, and has been, used for injection. The

following sources of water are used for recovery of oil:

Produced water is often used as an injection fluid. This reduces the potential of

causing formation damage due to incompatible fluids, although the risk of scaling or

corrosion in injection flow lines or tubing remains. Also, the produced water, being

contaminated with hydrocarbons and solids, must be disposed of in some manner, anddisposal to sea or river will require a certain level of clean-up of the water stream first.

However, the processing required rendering produced water fit for reinjection May be

equally costly. As the volumes of water being produced are never sufficient to replace

all the production volumes (oil and gas, in addition to water), additional "make-up"

water must be provided. Mixing waters from different sources exacerbates the risk of

scaling.

Sea water is obviously the most convenient source for offshore production facilities, and it

may be pumped inshore for use in land fields. Where possible, the water intake isplaced at sufficient depth to reduce the concentration of algae; however, filtering,

de-oxygenation and biociding is generally required.

Aquifer water from water-bearing formations other than the oil reservoir, but in the

same structure, has the advantage of purity where available.

River water will always require filtering and biociding beforeinjection.



Filters:-

The filters must clean the water and remove any impurities, such as shells and

algae. Typical filtration is to 2 micrometers, but really depends on reservoir requirements.

The filters are so fine so as not to block the pores of the reservoir. Sand filters are a

common used filtration technology to remove solid impurities from the water. The sand

filter has different beds with various sizes of sand granules.

The sea water traverses the first, finest, layer ofsand down to the coarsest and to

clean the filter, the process is inverted. After the water is filtered it continues on to

fill the deoxygenation tower. Sand filters are bulky, heavy, have some spillover of

sand particles and require chemicals to enhance water quality. A more sophisticated

approach is to use automatic self-cleaning back flushable screen filters (suction

scanning) because these do not have the disadvantages sand filters have.

The importance of proper water treatment is often underestimated by oilcompanies and engineering companies. Especially with river and seawater, intake

water quality can vary tremendously (algae blooming in spring time, storms and

current stirring up sediments from the seafloor) which will have significant impact on

the performance of the water treatment facilities. If not addressed correctly, water

injection may not be successful. This results in poor water quality, clogging of the reservoir

and loss of oil production.

De-oxygenation:-

Oxygen must be removed from the water because it promotes corrosion and growth

of certain bacteria. Bacterial growth in the reservoir can produce toxic hydrogen

sulfide, a source of serious production problems, and block the pores inthe rock. A

deoxygenation tower brings the injection water into contact with a dry gas stream

(gas is always readily available in the oilfield). The filtered water drops into the de-

oxygenation tower, splashing onto a series of trays, causing dissolvedoxygen to be lost to

the gas stream. An alternative method, also used as a backup to deoxygenation

towers, is to add an oxygen scavenging agent such as sodium bisulfate.

Water injection pumps:-

The high pressure, high flow water injection pumps are placed near to the de-

oxygenation tower and boosting pumps. They fill the bottom of the reservoir with the

filtered water to push the oil towards the wells like a piston. The resultof the injection is not

quick, it needs time. Water injection is used to prevent low pressure in the reservoir.

The water replaces the oil which has been taken, keeping the production rate and the

pressure the same over the long term.



FUNCTION:-

The main function of WIP is to treat the water and maintain oil level of 10 ppm.

Amount of oil is checked in the chemistry lab of installation, so regular checking is

done so that 10 ppm is maintained. The water sample is also checked for its salinity,

alkalinity, and pH (around 7.00) and hence record is maintained of each day of inspection.

After this final treated water is sent to GGS through water injection manifold and fromthere this water is used for water injection programs in different wells. Water is pumped

to GGS at 52kgf/cm2.

WATER INJECTION MANIFOLD:-

Purpose:

• It’s a place where treated raw water and water form ETP is mixed up, and

they are measured here.

CHEMICAL INJECTION PLANT:-

Purpose:

• It is used for the treatment of raw water for removing its hardness. After this

it is mixed with water obtained from ETP. Normally it is done because the water

available from ETP is not available in sufficient amount for water injection

purpose; therefore some mixing of treated raw water is done.

Process:

• Here the raw water is made to enter in the chemical tanks. The chemical

such as SHMP and oxygen scavenger is mixed with it which removes hardness to a

great extent and after this it is pumped to treated water tank in which it is mixed

with water obtained from ETP.

BALANCING TANK:-

Purpose:• It helps in measurement of water from ETP and helps in diverting

optimum of water to treated tank.

TREATED TANK:-

Purpose:

• It’s a place where treated raw water and water from ETP is mixed up, and

they are measured here. Finally the water is pumped through water injection

manifolds to GGS for carrying out further activities.



Waste Water Treatment Plant (WWTP): -

Waste water treatment plant also known as WWTP, hassame function as that of ETP.

WWTP receives the waste water from the Desalter plant and treat it. The oil content in

waste water is up to 100ppm which is then recovered through treatment.

EQUIPMENTS:

1. Settling tanks –

The simplest form of primary treating equipment is a settling (skim) tank or vessel.

These items are normally designed to provide long residence times during which

coalescence and gravity separation can occur.

2. Plate coalescers: –

Plate coalescers are skim tanks or vessels that use internal plates to improve

the gravity separation process. Various configurations of plate coalescers have been

devised. These are commonly called parallel plate interceptors (PPI), corrugated plate

interceptors (CPI), or crossflow separators. All of these depend on gravity separation to

allow the oil droplets to rise to a plate surface where coalescence and capture occur.

Types of plate coalescres:-

Parallel plate interceptor (PPI): The first form of a plate coalescer was the parallel plate

interceptor (PPI). This involved installing a series of plates parallel to the longitudinalaxis of an API separator (a horizontal rectangular cross section skimmer). The plates

form a "V" when viewed along the axis of flow so that the oil sheet migrates up the

underside of the coalescing plate and to the sides. Sediments migrate towards the

middle and down to the bottom of the separator, where they are removed.

Corrugated plate interceptor (CPI): The most common form of parallel plate interceptor

used in oil facilities is the corrugated plate interceptor (CPI). This is a refinement of the PPI

in that it takes up less plan area for the same particle size removal, and has the

added benefit of making sediment handling easier. In CPIsthe parallel plates are corrugated

(like roofing material) with the axis of the corrugationsparallel to the direction of flow. Theplate pack is inclined at an angle of 45° and the bulk water flow is forced downward. The oil

sheet raises upward counter to the water flow and is concentrated in the top of each

corrugation. When the oil reaches the end of the plate pack, it is collected in a channel and

brought to the oil-water interface.

3. Skimmers/coalescers: –

Several designs that are marketed for improving oil-water separation rely on

installing plates within horizontal skimmers or free-water knockouts to encouragecoalescence and capture of the oil particles within the water continuous phase.



4. Precipitators/coalescing filters: -

Coalescing filters employing sand, anthracite, or a fibrous element to catch the

oil droplets and promote coalescence have been used. The filter media are designed for

automatic backwash cycles. They are extremely efficient at water cleaning, but clog easily

with oil and are difficult to backwash. The backwash fluid must be disposed of, which leads

to further complications.

training report 2013

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