WINTER TRAINING REPORT

OIL AND NATURAL GAS CORPORATION LTD.

SKILL DEVELOPMENT CENTRE

8th Floor, CDMA Tower-II, No.1, Gandhi Erwin Road, Egmore, Chennai-600008

BY
NISHANTH G
ABIJITH K S
B. TECH. PETROLEUM ENGINEERING
JCT COLLEGE OF ENGINEERING AND TECHNOLOGY,
COIMBATORE

MENTORED BY : GUIDENCE BY :
Mr. M. RAMANAIAH Mr. V. R. GANESHUN
Mr. P. DAMODAR
Mr. P. NANDAKUMARAN
Mr. PHANENDRA BABU
Mr.J. RAVICHANDRAN
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 AKNOWLEDGEMENT

We would like to express our deep gratitude to our guide Mr. P. NANDAKUMAR for his
gracious support, encouragement and guidance throughout the entire course of training
period.

We would also like to thank the staff of production department, well logging, reservoir
studies and also the working personals of various departments in ONGC Chennai who have
spent their valuable time to make us understand various concepts practically which lead to the
conceptualisation of the project. We would like to thank the staff of SDC (Skill Development
Centre) for giving us this valuable training opportunity at ONGC Chennai.

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 TABLE OF CONTENTS

1. OVERVIEW OF ONGC
2. PRELIMINARIES OF OIL AND GAS PRODUCTION
3. HIGH PRESSURE AND HIGH TEMPERATURE WELLS
4. DRILLING
5. WELL LOGGING
6. ARTIFICIAL LIFTING
7. ENHANCED OIL RECOVERY
8. HSE IN OIL AND GAS INDUSTRY
9. CONCLUSION

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 1.OVERVIEW OF ONGC

Maharatna ONGC is the largest crude oil and natural gas Company in India, contributing
around 70 per cent to Indian domestic production. Crude oil is the raw material used by
downstream companies like IOC, BPCL, and HPCL to produce petroleum products like
Petrol, Diesel, Kerosene, Naphtha, and Cooking Gas-LPG.

This largest natural gas company ranks 11th among global energy majors (Platts). It is the
only public sector Indian company to feature in Fortune’s ‘Most Admired Energy
Companies’ list. ONGC ranks 18th in ‘Oil and Gas operations’ and 183rd overall in Forbes
Global 2000. Acclaimed for its Corporate Governance practices, Transparency International
has ranked ONGC 26th among the biggest publicly traded global giants. It is most valued and
largest E&P Company in the world, and one of the highest profit-making and dividend-
paying enterprise.
ONGC has a unique distinction of being a company with in-house service capabilities in all
areas of Exploration and Production of oil & gas and related oil-field services. Winner of the
Best Employer award, this public sector enterprise has a dedicated team of over 33,500
professionals who toil round the clock in challenging locations.

ONGC Videsh is a wholly owned subsidiary of Oil and Natural Gas Corporation Limited
(ONGC), the National Oil Company of India, and is India’s largest international oil and gas
Company. ONGC Videsh has participation in 41 projects in 20 countries namely Azerbaijan,
Bangladesh, Brazil, Colombia, Iraq, Israel, Iran, Kazakhstan, Libya, Mozambique, Myanmar,
Namibia, Russia, South Sudan, Sudan, Syria, United Arab Emirates, Venezuela, Vietnam and
New Zealand. ONGC Videsh maintains a balanced portfolio of 15 producing, 4
discovered/under development, 18 exploratory and 4 pipeline projects. The Company
currently operates/ jointly operates 21 projects. ONGC Videsh had total oil and gas reserves
(2P) of about 711 MMTOE as on April 1, 2018.

1.1 Global Ranking

 ONGC received Dun & Bradstreet Award 2018 in the 'Oil and Gas Exploration'
category
 ONGC received 4 PSE Excellence Awards from Indian Chamber of Commerce in
2016
 This Top Energy Company in India, ranked 11th globally as per Platts Top 250
Global Energy Rankings, 2017
 Ranked 464 in the Newsweek Green Rankings World's Greenest Companies 2016
 Ranked 14th among global Oil and Gas Operations industry in Forbes Global 2000
list, 2017 of the World's biggest companies for 2017; Ranked 443 in the overall list,
2017 - based on Sales (US$ 19.89 billion), 288 on Profits, 470 in Assets and 300
Market Value.
 Ranked 26 in 'Transparency in Corporate Reporting' among the world's 124 largest
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listed companies published by Transparency International, 2014(Up from 39 in 2012)

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1.2 Health, Safety & Environment

ONGC has implemented globally recognized QHSE management systems conforming to

requirements of ISO 9001, OHSAS 18001 and ISO 14001 at ONGC facilities and certified by
reputed certification agencies at all its operational units. Corporate guidelines on incident
reporting, investigation and monitoring of recommendations has been developed and
implemented for maintaining uniformity throughout the organization in line with
international practice.
Corporate Disaster Management Plan and guidelines have been developed for uniform
disaster management all across ONGC. ONGC has also developed Occupational Health
physical fitness criteria for employees deployed for offshore operations. Occupational Health
module has now been populated on SAP system.

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 2. PRELIMINARIES OF OIL AND GAS PRODUCTION

There are mainly four steps involved in the production of crude oil and gas. They are:
1. Exploration
2. Gas and Crude Oil Production
3. Processing
4. Transportation.

2.1 EXPLORATION:
Exploration means a scientific search set by the geologists and geophysicists for locating the
probable regions of oil and gas. In general terms this refer to the entire gamut of search for
hydrocarbons with the help of geological and geophysical surveys integrated with laboratory
data backup, selection of suitable locations of exploratory test-drilling and testing of such
wells.

Fig 1.1 Seismic Survey for offshore

Geophysical technology greatly reduces the risk of drilling. Wells are drilled to test a
geological theory or model that is generated in the Wide Area Geological Review and
validated by seismic data. The relative position of rock layers can be imaged from the
patterns of acoustic sound waves that are reflected from subsurface formations. For two-
dimensional (2D) seismic operations, field crews run parallel lines of sound recorders at wide
intervals to cover large areas in a relatively inexpensive manner. Once a field is discovered,
3D seismic can be run in a grid pattern with close sound recorders to delineate the most
attractive places to drill additional wells and determine the areal extent of a formation.

2.2GAS AND CRUDE OIL PRODUCTION:

According to generally accepted theory, Crude Oil is derived from ancient biomass. It is a
fossil fuel derived from ancient fossilized organic materials. More specifically, crude oil and
natural gas are products of heating of ancient organic materials (i.e. kerogen) over geological
time. Three conditions must be present for oil reservoirs to form: a source rock rich in
hydrocarbon material buried deep enough for subterranean heat to cook it into oil; a porous
and permeable reservoir rock for it to accumulate in; and a cap rock (seal) or other
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mechanism that prevents it from escaping to the surface. Within these reservoirs, fluids will
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typically organize themselves like a three-layer cake with a layer of water below the oil layer
and a layer of gas above it according to their densities, although the different layers vary in
size between reservoirs. Because most hydrocarbons are lighter than rock or water, they often
migrate upward through adjacent rock layers until either reaching the surface or becoming
trapped within porous rocks (known as reservoirs) by impermeable rocks above. However,
the process is influenced by underground water flows, causing oil to migrate hundreds of
kilometers horizontally or even short distances downward before becoming trapped in a
reservoir. When hydrocarbons are concentrated in a trap, an oil field forms, from which the
liquid can be extracted by drilling and pumping.
Prospects must be well defined in order to obtain oil and gas leases from landowners prior to
the drilling of a wildcat well after the necessary land work has been completed, the drilling
rig is moved on site and crews work 24 hours a day to drill a hole for the calculated depth.
Once the hole has been drilled to the target formation, the well is logged with electronic
downhole measurement tools to record the characteristics of the subsurface rock formations.
If logging indicates the well is productive, it is cased with steel pipe and a wellhead of shutoff
valves is installed to prepare for production. The well is completed by perforating holes in the
casing at the depth of the producing formation. Once a successful test well or series of wells
has been drilled, the economic potential of the hydrocarbon discovery must be determined.
This step includes estimating how much oil and gas is present (reserves), the probable selling
price, the cost of continuing the exploration effort as well as the cost of full field
development, and the taxes, royalties, and other expenses associated with producing the oil
field. If the venture looks promising, the final step is taken—development of a newly
discovered field.

Fig1.2: Typical oil and gas Well Configuration

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2.3 PROCESSING:

Production consists of a number of operations that allow the safe and efficient production of
hydrocarbons from the flowing wells. The key operations that will be conducted at the
surface include:
 Produced Hydrocarbon Separation
 Gas Processing
 Oil and Gas Export
 Well Testing
 Produced Water Treatment and Injection
 Utillities to support these processes
In Offshore Production the Pipelines and Risers facility uses Subsea production wells. The
typical High Pressure (HP) wellhead at the bottom right, with its Christmas tree and choke, is
located on the sea bottom. A production riser (offshore) or gathering line (onshore) brings the
well flow into the manifolds. As the reservoir is produced, wells may fall in pressure and
become Low Pressure (LP) wells. This line may include several check valves. The choke,
master and wing valves are relatively slow, therefore in case of production shutdown,
pressure before the first closed sectioning valve will rise to the maximum wellhead pressure
before these valves can close. The pipelines and risers are designed with this in mind. Short
pipeline distances is not a problem, but longer distances may cause multiphase well flow to
separate and form severe slugs, plugs of liquid with gas in between, travelling in the pipeline.
Severe slugging may upset the separation process, and also cause overpressure safety
shutdowns. Slugging might also occur in the well as described earlier. Slugging may be
controlled manually by adjusting the choke, or with automatic slug controls. Further, areas of
heavy condensate might form in the pipelines. At high pressure, these plugs may freeze at
normal sea temperature, e.g. if production is shut down or with long offsets. This may be
prevented by injecting ethylene glycol. Check valves allow each well to be routed into one or
more of several Manifold Lines. There will be at least one for each process train plus
additional Manifolds for test and balancing purposes. The Check valves systems have been
not included in the diagram to avoid complexity of the diagram. The well-stream may consist
of Crude oil, Gas, Condensates, water and various contaminants. The purpose of the
separators is to split the flow into deable fractions. The main separators are gravity type. As
mentioned the production choke reduces the pressure to the HP manifold and First stage
separator to about 3-5 MPa (30-50 times atmospheric pressure). Inlet temperature is often in
the range of 100-150 degrees C. The pressure is often reduced in several stages, three stages
are used, to allow controlled separation of volatile components. The purpose is to achieve
maximum liquid recovery and stabilized oil and gas, and separate water. A large pressure
reduction in a single separator will cause flash vaporization leading to instabilities and safety
hazards. An important function is also to prevent gas blow-by which happens when low level
causes gas to exit via the oil output causing high pressure downstream. The liquid outlets
from the separator will be equipped with vortex breakers to reduce disturbance on the liquid
table inside. Emergency Valves (EV) are sectioning valves that will separate the process
components and blow-down valves that will allow excess hydrocarbons to be burned off in
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the flare. These valves are operated if critical operating conditions are detected or on manual
command, by a dedicated Emergency Shutdown System There also needs to be enough
capacity to handle normal slugging from wells and risers. Other types of separators such as
vertical separators, cyclones (centrifugal separation) can be use to save weight, space or
improve separation. There also has to be a certain minimum pressure difference between each
stage to allow satisfactory performance in the pressure and level control loops. The second
stage separator is quite similar to the first stage HP separator. In addition to output from the
first stage, it will also receive production from wells connected to the Low Pressure manifold.
The pressure is now around 1 MPa (10 atmospheres) and temperature below 100 degrees C.
The water content will be reduced to below 2%. An oil heater could be located between the
first and second stage separator to reheat the oil/water/gas mixture. This will make it easier to
separate out water when initial water cut is high and temperature is low. The heat exchanger
is normally a tube/shell type where oil passes though tubes in a cooling medium placed inside
an outer shell. The third stage basically uses a Flash-Drum. Further reduction of water
percentage is done in the GDU (Gas Dehydration Unit). On an installation such as this, when
the water cut is high, there will be a huge amount of produced water. Water must be cleaned
before discharge to sea. Often this water contains sand particles bound to the oil/water
emulsion. The environmental regulations in most countries are quite strict, It also places
limits other forms of contaminants. This still means up to one barrel of oil per day for the
above production, but in this form, the microscopic oil drops are broken down fast by natural
bacteria. Various equipments are used, first sand is removed from the water by using a sand
cyclone. The water then goes to a hydrocyclone, a centrifugal separator that will remove oil
drops. The hydrocyclone creates a standing vortex where oil collects in the middle and water
is forced to the side. Finally the water is collected in the water de-gassing drum.
Dispersed gas will slowly rise to the surface and pull remaining oil droplets to the surface by
flotation. The surface oil film is drained, and the produced water can be discharged to sea.
Recovered oil in the water treatment system is typically recycled to the third stage separators.
The gas train consist of several stages, each taking gas from a suitable pressure level in the
production separator’s gas outlet, and from the previous stage. Incoming gas is first cooled in
a heat exchanger and goes into the compressors. For the compressor operate in an efficient
way, the temperature of the gas should be low. The lower the temperature is the less energy
will be used to compress the gas for a given final pressure and temperature. Temperature
exchangers of various forms are used to cool the gas, The separated gas may contain mist and
other liquid droplets. Liquid drops of water and hydrocarbons also form when the gas is
cooled in the heat exchanger, and must be removed before it reaches the compressor. If liquid
droplets enter the compressor they will erode the fast rotating blades for which gas is passed
through a scrubber and reboiler system to remove the remaining fraction of water from the
gas.

2.4 TRANSPORTATION:
The gas pipeline is fed from the High Pressure compressors. Oil pipelines are driven by
separate booster pumps. For longer pipelines, intermediate compressor stations or pump
stations will be required due to distance or crossing of mountain ranges.
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 3. HIGH PRESSURE HIGH TEMPERATURE WELLS

High pressure/high temperature (HP/HT) wells are those where the undisturbed bottom hole
temp at prospective reservoir depth or total depth is greater than 300°F or 150°C, and either
the maximum anticipated pore pressure of any porous formation to be drilled through exceeds
a hydrostatic gradient of 0.8 psi/ft, or a well requiring pressure control equipment with a rated
working pressure in excess of 10000 psi. Drilling wells with these characteristics pose special
challenges.

3.1Drilling fluid considerations

Where possible, high temperature wells are drilled with oil-based fluids (OBFs) or synthetic-
based fluids (SBFs), because of the thermal limitations of most water-based fluids (WBFs).
Such limitations of WBFs include:
 Temperature-induced gelation
 High risk of CO2 contamination from the formation being drilled and/or from the
degradation of organic mud additives
 Increased solids sensitivity that is related to high temperatures
Historically, WBFs have relied on bentonite clay for both rheology and filtration control.
When tested at temperatures ≥ 300°F under laboratory conditions, bentonite slurries begin to
thermally flocculate. Under HP/HT conditions with significantly elevated temperatures, a
traditional WBF such as the lignosulfonate system might thicken so much that it no longer is
usable or requires drastic and costly dilution and conditioning.
The ability to maintain bentonite and other active solids in a deflocculated state is the key to
obtaining acceptable rheological and fluid-loss properties for WBFs exposed to high
temperatures. Bentonite can be used in relatively low concentrations, if it is supplemented
with a high-temperature, high-molecular-weight synthetic polymer for additional carrying
capacity. This combination helps to make it possible to maintain 6% by weight of low-gravity
solids and a particle-size-distribution (PSD) of these solids in an acceptable micron range.
Adding polymeric deflocculant at depths where elevated temperatures are expected assists in
rheology control.
An HP/HT viscometer typically is used to monitor the temperature stability of the drilling
fluid, and to evaluate its rheological properties at up to 500°F and 20,000 psia. This test is
especially useful for determining whether high-temperature flocculation occurs in water-
based muds. The test results can be presented graphically by plotting the change in viscosity
with respect to temperature over the heating and cooling cycle, which establishes a baseline
for recognizing indicators of temperature instability.
There are a number of ways to minimize problems with temperature gelation, including:

 Eliminating lignite and lignite derivatives from the WBF formulation

 Lowering the bentonite concentration
 Supplementing the high-temperature water-based system with synthetic polymers and
copolymers
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OBFs and SBFs are subject to temperature thinning. Surface density should be corrected on
the basis of downhole pressure data from a PWD tool. Hydraulics-modeling software that
accurately accounts for fluid compressibility and the effect of temperature can improve the
performance of the SBF system by allowing more precise surface conditioning.

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 4. DRILLING

Drilling services account for more than 55 per cent of ONGC’s capex. In 2017, 501 wells
were drilled, the highest ever in the company’s history. The cycle speed went up by about
25% and cost reduction of over 40% in drilling cost from FY’15 levels was recorded.
ONGC operates some 105 drilling and 74 work over rigs. It is among the few companies in
the world to have drilled 127 deepwater wells in diverse and challenging areas, establishing
itself as one of the leading oil drilling companies in India.
There has been a major progress in terms of technology infusion – introduction of Under-
Balanced Drilling, use of Advanced Hybrid Bits, resource optimization through Batch
Drilling in Offshore & Pad Drilling in Onshore.
In order to have a more focused approach towards onshore, offshore (shallow waters) and
offshore (deep waters) operations a new concept 'Company within Company' has been rolled
out to bring about operational efficiency in offshore drilling operations.
An in-house innovative PLC controlled Safety System for Travelling block movement has
been successfully installed on an on-shore drilling rig.

4.1 Well drilling & Work-over operations

Radial drilling, a productivity improving drilling technology, has been carried out in four
wells for the first time to enhance reach in the reservoir and increasing flow path.
Hydro fracturing technology has been playing crucial role in enhancing productivity of the
wells all around the world. So ONGC, being a mainstream oil drilling company, plans for
execution of HF jobs in low potential wells, which were not economically viable earlier and
may be taken up now due to lower cost of the job.

4.2 Well testing & Stimulation

Well Stimulation Services in ONGC has indigenized products worth nearly 9.8 million and
developed 10 vendors in the process. It has also saved 364.4 million through use of
indigenous equipment and services in its Make in India efforts, keeping up to its position of a
leading oil drilling company in India.
Rig BHEL 120 VI of Well Services was successfully refurbished thereby adding a fresh lease
of life to the Workover Rig.
Successful fracturing of deepest and highest temperature well at Rajahmundry was carried
out by in-house team (depth of 4069.5 Mts and BHT – 165.5°C) using in-house developed
fracture fluid for this high temperature.

4.3 Drilling – Where, What, and How

The actual process of drilling a well is much the same as using a power drill to perform a
workshop task.
 Before drilling, measurements are made to show where to drill.
 The material, the size of the hole and how deep to drill will determine the proper type
of drill bit
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  It will also determine how big the drill motor needs to be to drive the bit in a rotary
motion.
The concept of the overall drilling process is relatively simple. There is a potential reservoir
located deep beneath the earth’s surface. In order to gain access and extract oil or gas, a hole
must be drilled through the various rocks, materials and layers to reach it.
In oil and gas drilling, the “how” to drill the well, is the subject of this module and, is often,
the last element to be considered. First, the team must define:
 Where to drill – based on the exploration and evaluation work, the geology and
potential subsurface structure
 What – determined by the reservoir and strata which set the well profile, both depth
and hole size
Having defined the above, the drilling engineer can develop the “how“, including
 The optimal drilling rig
 A detailed well design and construction
 Needed operational safety and contingency planning
 The important “go” and “no-go” decision points in the operation

4.4 Horizontal Wells

Despite the fact that most oil and gas deposits are wider than they are thick, for more than a
century, vertical drilling remained the preferred method. A horizontal well is more costly,
but is able to reach subsurface objectives that could not easily be reached with a vertical
borehole. Because horizontal wells can drain a larger area, fewer are needed, which means
less surface infrastructure. This reduced footprint makes horizontal drilling ideal for
reservoirs that are shallow, spread out, fractured or in sensitive environments.
These factors, and technological advances that have made horizontal wells commercially
viable, have led to a 20-fold increase in the number of horizontal wells in the US over the
past two decades. With a vertical well a geologist’s role is primarily to evaluate “what has
been drilled.” With horizontal wells geologists now become part of the drilling operation,
actively involved in steering the well along a desired profile and responding to feedback data
as drilling occurs.
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 5.WELL LOGGING

Well logging, also known as borehole logging is the practice of making a detailed record (a
well log) of the geologic formations penetrated by a borehole. The log may be based either on
visual inspection of samples brought to the surface (geological logs) or on physical
measurements made by instruments lowered into the hole(geophysical logs). Some types of
geophysical well logs can be done during any phase of a well's history: drilling, completing,
producing, or abandoning. Well logging is performed in boreholes drilled for the oil and gas,
groundwater, mineral and geothermal exploration, as well as part of environmental and
geotechnical studies.

5.1 Wireline logging

The oil and gas industry uses wireline logging to obtain a continuous record of a formation's
rock properties. Wireline logging can be defined as being "The acquisition and analysis of
geophysical data performed as a function of well bore depth, together with the provision of
related services." Note that "wireline logging" and "mud logging" are not the same, yet are
closely linked through the integration of the data sets. The measurements are made referenced
to "TAH" - True Along Hole depth: these and the associated analysis can then be used to
infer further properties, such as hydrocarbon saturation and formation pressure, and to make
further drilling and production decisions.

Wireline logging is performed by lowering a 'logging tool' - or a string of one or more

instruments - on the end of a wireline into an oil well (or borehole) and recording
petrophysical properties using a variety of sensors. Logging tools developed over the years
measure the natural gamma ray, electrical, acoustic, stimulated radioactive responses,
electromagnetic, nuclear magnetic resonance, pressure and other properties of the rocks and
their contained fluids. For this article, they are broadly broken down by the main property
that they respond to.

The data itself is recorded either at surface (real-time mode), or in the hole (memory mode) to
an electronic data format and then either a printed record or electronic presentation called a
"well log" is provided to the client, along with an electronic copy of the raw data. Well
logging operations can either be performed during the drilling process (see Logging While
Drilling), to provide real-time information about the formations being penetrated by the
borehole, or once the well has reached Total Depth and the whole depth of the borehole can
be logged.

Real-time data is recorded directly against measured cable depth. Memory data is recorded
against time, and then depth data is simultaneously measured against time. The two data sets
are then merged using the common time base to create an instrument response versus depth
log. Memory recorded depth can also be corrected in exactly the same way as real-time
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corrections are made, so there should be no difference in the attainable TAH accuracy.
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The measured cable depth can be derived from a number of different measurements, but is
usually either recorded based on a calibrated wheel counter, or (more accurately) using
magnetic marks which provide calibrated increments of cable length. The measurements
made must then be corrected for elastic stretch and temperature.

There are many types of wireline logs and they can be categorized either by their function or
by the technology that they use. "Open hole logs" are run before the oil or gas well is lined
with pipe or cased. "Cased hole logs" are run after the well is lined with casing or production
pipe.
Wireline logs can be divided into broad categories based on the physical properties measured.

5.2 History
Conrad and Marcel Schlumberger, who founded Schlumberger Limited in 1926, are
considered the inventors of electric well logging. Conrad developed the Schlumberger array,
which was a technique for prospecting for metal ore deposits, and the brothers adapted that
surface technique to subsurface applications. On September 5, 1927, a crew working for
Schlumberger lowered an electric sonde or tool down a well in Pechelbronn, Alsace, France
creating the first well log. In modern terms, the first log was a resistivity log that could be
described as 3.5-meter upside-down lateral log.
In 1931, Henri George Doll and G. Dechatre, working for Schlumberger, discovered that the
galvanometer wiggled even when no current was being passed through the logging cables
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down in the well. This led to the discovery of the spontaneous potential (SP) which was as
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important as the ability to measure resistivity. The SP effect was produced naturally by the
borehole mud at the boundaries of permeable beds. By simultaneously recording SP and
resistivity, loggers could distinguish between permeable oil-bearing beds and impermeable
nonproducing beds.

In 1940, Schlumberger invented the spontaneous potential dipmeter; this instrument allowed
the calculation of the dip and direction of the dip of a layer. The basic dipmeter was later
enhanced by the resistivity dipmeter (1947) and the continuous resistivity dipmeter (1952).
Oil-based mud (OBM) was first used in Rangely Field, Colorado in 1948. Normal electric
logs require a conductive or water-based mud, but OBMs are nonconductive. The solution to
this problem was the induction log, developed in the late 1940s. The introduction of the
transistor and integrated circuits in the 1960s made electric logs vastly more reliable.
Computerization allowed much faster log processing, and dramatically expanded log data-
gathering capacity. The 1970s brought more logs and computers. These included combo type
logs where resistivity logs and porosity logs were recorded in one pass in the borehole.
The two types of porosity logs (acoustic logs and nuclear logs) date originally from the
1940s. Sonic logs grew out of technology developed during World War II. Nuclear logging
has supplemented acoustic logging, but acoustic or sonic logs are still run on some
combination logging tools.
Nuclear logging was initially developed to measure the natural gamma radiation emitted by
underground formations. However, the industry quickly moved to logs that actively bombard
rocks with nuclear particles. The gamma ray log, measuring the natural radioactivity, was
introduced by Well Surveys Inc. in 1939, and the WSI neutron log came in 1941. The gamma
ray log is particularly useful as shale beds which often provide a relatively low permeability
cap over hydrocarbon reservoirs usually display a higher level of gamma radiation. These
logs were important because they can be used in cased wells (wells with production casing).
WSI quickly became part of Lane-Wells. During World War II, the US Government gave a
near wartime monopoly on open-hole logging to Schlumberger, and a monopoly on cased-
hole logging to Lane-Wells. Nuclear logs continued to evolve after the war.
After the discovery of nuclear magnetic resonance by Bloch and Purcell in 1946, the nuclear
magnetic resonance log using the Earth's field was developed in the early 1950s by Chevron
and Schlumberger.[citation needed] The NMR log was a scientific success but an engineering
failure. More recent engineering developments by NUMAR (a subsidiary of Halliburton) in
the 1990s has resulted in continuous NMR logging technology which is now applied in the
oil and gas, water and metal exploration industry.

Many modern oil and gas wells are drilled directionally. At first, loggers had to run their tools
somehow attached to the drill pipe if the well was not vertical. Modern techniques now
permit continuous information at the surface. This is known as logging while drilling (LWD)
or measurement-while-drilling (MWD). MWD logs use mud pulse technology to transmit
data from the tools on the bottom of the drillstring to the processors at the surface.
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Fig : Caliper log

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 6. ARTIFICIAL LIFTING

Artificial lift is a method used to lower the producing bottomhole pressure (BHP) on the
formation to obtain a higher production rate from the well. This can be done with a positive-
displacement downhole pump, such as a beam pump or a progressive cavity pump (PCP), to
lower the flowing pressure at the pump intake. It also can be done with a downhole
centrifugal pump, which could be a part of an electrical submersible pump (ESP) system. A
lower bottomhole flowing pressure and higher flow rate can be achieved with gas lift in
which the density of the fluid in the tubing is lowered and expanding gas helps to lift the
fluids. Artificial lift can be used to generate flow from a well in which no flow is occurring or
used to increase the flow from a well to produce at a higher rate. Most oil wells require
artificial lift at some point in the life of the field, and many gas wells benefit from artificial
lift to take liquids off the formation so gas can flow at a higher rate.
The major forms of artificial lift are:
 Sucker-rod (beam) pumping
 Electrical submersible pumping (ESP)
 Gas lift and intermittent gas lift
 Reciprocating and jet hydraulic pumping systems
 Plunger lift
 Progressive cavity pumps (PCP)
There are other methods, such as the electrical submersible progressive cavity pump (ESPCP)
for pumping solids and viscous oils, in deviated wells. This system has a PCP with the motor
and some other components similar to an ESP. Other methods include:

 Modifications of beam pump systems

 Various intermittent gas lift methods
 Various combination systems.
 Continuous Belt Transportation

6.1 Selecting an artificial lift system

To realize the maximum potential from developing any oil or gas field, the most economical
artificial lift method must be selected. The methods historically used to select the lift method
for a particular field vary broadly across the industry. The methods include:
 Operator experience
 What methods are available for installations in certain areas of the world
 What is working in adjoining or similar fields
 Determining what methods will lift at the desired rates and from the required depths
 Evaluating lists of advantages and disadvantages
 “Expert” systems to both eliminate and select systems
 Evaluation of initial costs, operating costs, production capabilities, etc. with the use of
economics as a tool of selection, usually on a present-value basis
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These methods consider:
 Geographic location
 Capital cost
 Operating cost
 Production flexibility
 Reliability
 “Mean time between failures”
In most cases, what has worked best or which lift method performs best in similar fields serve
as selection criteria. Also, the equipment and services available from vendors can easily
determine which lift method will be applied. However, when significant costs for well
servicing and high production rates are a part of the scenario, it becomes prudent for the
operator to consider most, if not all, of the available evaluation and selection methods. See
Artificial lift selection methods. If the “best” lift method is not selected, such factors as long-
term servicing costs, deferred production during workovers, and excessive energy costs (poor
efficiency) can reduce drastically the net present value (NPV) of the project. Typically, the
reserves need to be produced in a timely manner with reasonably low operating costs.
Conventional wisdom considers the best artificial lift method to be the system that provides
the highest present value for the life of the project. Good data are required for a complete
present-value analysis, and these data are not always broadly available.

Environmental and geographical considerations may be overriding issues. For example,

sucker-rod pumping is, by far, the most widely used artificial lift method in onshore US
operations. However, in a densely populated city or on an offshore platform with 40 wells in
a very small deck area, sucker-rod pumping might be a poor choice. Also, deep wells
producing several thousands of barrels per day cannot be lifted by beam lift; other methods
must be considered. Such geographic, environmental, and production considerations can limit
the choices to only one method of lift; determining the best overall choice is more difficult
when it is possible to apply several of the available lift methods.
Artificial lift method selection should be a part of the overall well design. Once the method is
selected, the wellbore size required to obtain the desired production rate must be considered.
Many times, a casing program has been designed to minimize well-completion costs, but it is
later found that the desired production could not be obtained because of the size limitation on
the artificial lift equipment. This can lead to an ultimate loss of total reserves. Even if target
production rates can be achieved, smaller casing sizes can lead to higher long-term well-
servicing problems. If oil prices are low, it is tempting to select a small casing size to help
with current economics. Obviously, wells should be drilled and completed with future
production and lift methods in mind, but this is often not the case.

6.2Reservoir pressure and well productivity

Among the most important factors to consider when selecting an artificial lift system are
current and future reservoir pressure and well productivity. If producing oil or liquid rate is
plotted (X axis) against producing bottomhole pressure (BHP) [Y axis], one of two inflow
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performance relationships (IPR) usually is seen. Above the bubblepoint pressure, the liquid
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rate vs. pressure drop below the reservoir pressure (drawdown) is linear. Below the
bubblepoint pressure, a relationship similar to that described by Vogel occurs. illustrates
production vs. drawdown relationships as a single IPR with a bubblepoint of 750 psig and an
average reservoir pressure of 2,000 psig. If the necessary data are available, a single-phase
IPR expression for either gas or liquid flow is available from radial-flow equations. Gas
deliverability curves show a nonlinear dependence of gas rate similar to the liquid rate vs.
pressure on a Vogel curve.

Liquid-rate IPR curves can have a gas-to-liquid ratio associated with the liquid rate, and gas
deliverability curves can have a liquid production (e.g., bbl/MMscf/D) associated with the
gas rates. Our discussion will focus on IPRs with liquid production as a function of the
flowing BHP.
Some types of artificial lift can reduce the producing sandface pressure to a lower level than
other artificial lift methods. For pumping wells, achieving a rate that occurs below the
bubblepoint pressure requires measures to combat possible gas interference because gas
bubbles (free gas) will be present at the intake of the downhole artificial lift installation. In
addition to setting the pump below the perforations, such measures include the use of a
variety of other possible gas-separation schemes and the use of special pumps to compress
gas or reduce effects of “fluid pound” in beam systems. However, the artificial lift method of
gas lift is assisted by the production of gas (with liquids) from the reservoir.

The reward for achieving a lower producing pressure will depend on the IPR. With the IPR
data available, a production goal may be set. For low-rate wells, the operator would want to
produce the maximum rate from the well. For high-rate wells, the production goal can be set
by the capacity or horsepower limit of a particular artificial lift method.
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 7. ENHANCED OIL RECOVERY

Enhanced oil recovery (EOR) is the technique or process where the physicochemical
(physical and chemical) properties of the rock are changed to enhance the recovery of
hydrocarbon. The properties of the reservoir fluid system which are affected by EOR process
are chemical, biochemical, density, miscibility, interfacial tension (IFT)/surface tension (ST),
viscosity and thermal. EOR often is called tertiary recovery if it is performed after
waterflooding.

7.1 Techniques
There are three primary techniques of EOR: gas injection, thermal injection, and chemical
injection. Gas injection, which uses gases such as natural gas, nitrogen, or carbon dioxide
(CO2), accounts for nearly 60 percent of EOR production in the United States. Thermal
injection, which involves the introduction of heat, accounts for 40 percent of EOR production
in the United States, with most of it occurring in California. Chemical injection, which can
involve the use of long-chained molecules called polymers to increase the effectiveness of
waterfloods, accounts for about one percent of EOR production in the United States. In 2013,
a technique called Plasma-Pulse technology was introduced into the United States from
Russia. This technique can result in another 50 percent of improvement in existing well
production.

7.2 Gas injection

Gas injection or miscible flooding is presently the most-commonly used approach in
enhanced oil recovery. Miscible flooding is a general term for injection processes that
introduce miscible gases into the reservoir. A miscible displacement process maintains
reservoir pressure and improves oil displacement because the interfacial tension between oil
and water is reduced. This refers to removing the interface between the two interacting fluids.
This allows for total displacement efficiency. Gases used include CO2, natural gas or
nitrogen. The fluid most commonly used for miscible displacement is carbon dioxide because
it reduces the oil viscosity and is less expensive than liquefied petroleum gas. Oil
displacement by carbon dioxide injection relies on the phase behavior of the mixtures of that
gas and the crude, which are strongly dependent on reservoir temperature, pressure and crude
oil composition.

7.3Thermal injection
In this approach, various methods are used to heat the crude oil in the formation to reduce its
viscosity and/or vaporize part of the oil and thus decrease the mobility ratio. The increased
heat reduces the surface tension and increases the permeability of the oil. The heated oil may
also vaporize and then condense forming improved oil. Methods include cyclic steam
injection, steam flooding and combustion. These methods improve the sweep efficiency and
the displacement efficiency. Steam injection has been used commercially since the 1960s in
California fields. In 2011 solar thermal enhanced oil recovery projects were started in
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California and Oman, this method is similar to thermal EOR but uses a solar array to produce
the steam.
In July 2015, Petroleum Development Oman and GlassPoint Solar announced that they
signed a $600 million agreement to build a 1 GWth solar field on the Amal oilfield. The
project, named Miraah, will be the world's largest solar field measured by peak thermal
capacity.
In November 2017, GlassPoint and Petroleum Development Oman (PDO) completed
construction on the first block of the Miraah solar plant safely on schedule and on budget,
and successfully delivered steam to the Amal West oilfield.
Also in November 2017, GlassPoint and Aera Energy announced a joint project to create
California’s largest solar EOR field at the South Belridge Oil Field, near Bakersfield,
California. The facility is projected to produce approximately 12 million barrels of steam per
year through a 850MW thermal solar steam generator. It will also cut carbon emissions from
the facility by 376,000 metric tons per year.

7.4 Steam flooding

Steam flooding (see sketch) is one means of introducing heat to the reservoir by pumping
steam into the well with a pattern similar to that of water injection. Eventually the steam
condenses to hot water; in the steam zone the oil evaporates, and in the hot water zone the oil
expands. As a result, the oil expands, the viscosity drops, and the permeability increases. To
ensure success the process has to be cyclical. This is the principal enhanced oil recovery
program in use today.

Solar EOR is a form of steam flooding that uses solar arrays to concentrate the sun’s
energy to heat water and generate steam. Solar EOR is proving to be a viable alternative to
gas-fired steam production for the oil industry.

7.5 Chemical injection

The injection of various chemicals, usually as dilute solutions, have been used to aid mobility
and the reduction in surface tension. Injection of alkaline or caustic solutions into reservoirs
with oil that have organic acids naturally occurring in the oil will result in the production of
soap that may lower the interfacial tension enough to increase production. Injection of a
dilute solution of a water-soluble polymer to increase the viscosity of the injected water can
increase the amount of oil recovered in some formations. Dilute solutions of surfactants such
as petroleum sulfonates or biosurfactants such as rhamnolipids may be injected to lower the
interfacial tension or capillary pressure that impedes oil droplets from moving through a
reservoir. Special formulations of oil, water and surfactant, microemulsions, can be
particularly effective in this. Application of these methods is usually limited by the cost of the
chemicals and their adsorption and loss onto the rock of the oil containing formation. In all of
these methods the chemicals are injected into several wells and the production occurs in other
nearby wells.
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7.6 Polymer flooding
Polymer flooding consists in mixing long chain polymer molecules with the injected water in
order to increase the water viscosity. This method improves the vertical and areal sweep
efficiency as a consequence of improving the water/oil Mobility ratio.
Surfactants may be used in conjunction with polymers; They decrease the surface tension
between the oil and water. This reduces the residual oil saturation and improves the
macroscopic efficiency of the process.
Primary surfactants usually have co-surfactants, activity boosters, and co-solvents added to
them to improve stability of the formulation.
Caustic flooding is the addition of sodium hydroxide to injection water. It does this by
lowering the surface tension, reversing the rock wettability, emulsification of the oil,
mobilization of the oil and helps in drawing the oil out of the rock.

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 8. HSE IN OIL AND GAS INDUSTRY

Health, Safety, and Environmental (HSE) management is an integral part of any business and
is considered to be extremely essential when it comes to managing business in oil and gas
sectors. HSE requirements are generally laid out considering the expectations of the
divisional compliance with that of the standard policies. This is the most important part of
HSE through legislation in the recent decades and thus forms the basis of HSE regulations in
the present era. Apart from setting out the general duties and responsibilities of the employers
and others, it also lays the foundation for subsequent legislation, regulations, and
enforcement regimes. HSE standards are circumscribed around activities that are “reasonably
practicable” to assure safety of the employees and assets as well. HSE regulations impose
general duties on employers for facilitating the employees with minimum health and safety
norms and members of the public; general duties on employees for their own health and
safety and that of other employees, which are insisted as regulations.

8.1Importance of Safety
There are risks associated with every kind of work and workplace in day‐today life. Levels of
risk involved in some industries may be higher or lower due to the consequences involved.
These consequences affect the industry as well as the society, which may create a negative
impact on the market depending upon the level of risk involved. It is therefore very important
to prevent death or injury to workers, general public, prevent physical and financial loss to
the plant, prevent damage to the third party, and to the environment.
Hence, rules and regulations for assuring safety are framed and strictly enforced in offshore
and petroleum industries, which is considered to be one of the most hazardous industries. The
prime goal is to protect the public, property, and environment in which they work and live. It
is a commitment for all industries and other stakeholders toward the interests of customers,
employees, and others. One of the major objectives of the oil and gas industries is to carry out
the intended operations without injuries or damage to equipment or the environment.
Industries need to form rules, which will include all applicable laws and relevant industry
standards of practice. Industries need to continuously evaluate the HSE aspects of equipment
and services. It is important for oil and gas industries to believe that effective HSE
management will ensure a good business. Continuous improvement in HSE management
practices will yield good return in the business apart from ensuring goodness of the
employees. From the top management through the entry level, every employee should feel
responsible and accountable for HSE. Industries need to be committed to the integration of
HSE objectives into management systems at all levels. This will not only enhance the
business, but also increase the success rate by reducing risk and adding value to the customer
services.
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 9.CONCLUSION

I can honestly say that my time spent interning with ONGC Chennai resulted in one of the
best winters of my life. Not only did I gain knowledge but I also had the opportunity to meet
many fantastic experienced people. The atmosphere at the SDC office was always welcoming
which made me feel right at home.

Overall, my internship at ONGC Chennai has been a success. I was able to gain practical
skills, work in a fantastic environment, and make connections that will last a lifetime. I could
not be more thankful

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