Summer Training Report on Crude Oil and Drilling Fluids

SUMMER TRAINING REPORT ON
“ CRUDE OIL ANALYSIS AND DRILLING
FLUIDS ”
TRAINING TAKEN AT
KDMIPE, GEO-CHEMISTRY DIVISION
ONGC,DEHRADUN
2015
PROJECT CO-ORDINATOR SUBMITTED BY
Dr. R.K. MITTAL SHIKHA THAPA
GEO CHEMISTRY DIVISION CHEMICAL ENGINEERING
KDMIPE, ONGC GURUGHASI DAS CENTRAL
DEHRADUN UNIVERSITY

CERTIFICATE
I hereby certify that SHIKHA THAPA did her summer training from 2 june
2015 to 2 july 2015 i.e 4 weeks and her work during training which is
being presented in the project report entitled “CRUDE OIL ANALYSIS AND
DRILLING FLUIDS ” in the partial fulfillment of the requirement for the
award of certificate of summer training, submitted to the department of
geochemical, ONGC DEHRADUN is an authentic record of their own work
carried out under the supervision of Dr. R.K. Mittal ,Chief Chemist.
This is to certify that the above statement made by the candidates are
correct to the best of my knowledge.
Dr. R.K. MITTAL
chief chemist
KDMIPE
ONGC,dehradun

ACKNOWLEDGEMENT
I am very thankful to TRAINING DIVISION, ONGC ACADEMY,
DEHRADUN for providing me an opportunity to pursue the project work at
KDMIPE, ONGC, DEHRADUN .
I am highly thankful to Dr. RAJEEV KUMAR MITTAL, CHIEF CHEMIST,
ONGC ACADEMY , dehradun for their valuable guidance ,suggestions , co-
operation and providing me the every facility to accomplish my project
successfully .
Lastely I would like to thank each and every member of GEO-CHEMISRTY
DIVISION, KDMIPE ,ONGC who have been very helpful throughout my
training period.
SHIKHA THAPA

INTRODUCTION
HISTORY AND ORIGIN OF ONGC
Before the independence of India, the Assam oil Company in the north-eastern and
Attack Oil Company in north-western part of the undivided india were the only oil
producing companies, 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 Central Government of India realized the importance of oil
and gas for rapid industrial development and its strategic role in defense.
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 Goverment 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 nucIn 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. leus of geoscientists from the geological
survey of india.
A delegation under the leadership of the 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(1956-61).
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, which enhanced powers of the commission
further. The main functions of the Oil and Natural Gas Commission subject to the
provisions of the Act, were "to plan, promote, organize and implement programs for
development of Petroleum Resources and the production and sale of petroleum and
petroleum products produced by it, and to perform such other functions as the Central
Government may, from time to time, assign to it ". The act further outlined the
activities and steps to be taken by ONGC in fulfilling its mandate.
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 tones of hydrocarbons, which were present
in the country, were discovered. 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 was set up under the visionary leadership of Pandit Jawaharlal Nehru. Pandit
Nehru reposed faith in ShriKeshavDevMalviya who laid the foundation of ONGC in
the form of Oil and Gas division, under Geological Survey of India, in 1955. A few
months later, it was converted into an Oil and Natural Gas Directorate. The

Directorate was converted into Commission and christened Oil & Natural Gas
Commission on 14th August 1956. In 1994, Oil and Natural Gas Commission was
converted in to a Corporation, and in 1997 it was recognized as one of the Navratnas
by the Government of India. Subsequently, it has been conferred with Maharatna
status in the year 2010.Over 56 years of its existence ONGC has crossed many a
milestone to realize the energy dreams of India. The journey of ONGC, over these
years, has been a tale of conviction, courage and commitment. ONGCs’ superlative
efforts have resulted in converting earlier frontier areas into new hydrocarbon
provinces. From a modest beginning, ONGC has grown to be one of the largest E&P
companies in the world in terms of reserves and production.
ONGC as an integrated Oil & Gas Corporate has developed in-house capability in all
aspects of exploration and production business i.e., Acquisition, Processing &
Interpretation (API) of Seismic data, drilling, work-over and well stimulation
operations, engineering & construction, production, processing, refining,
transportation, marketing, applied R&D and training, etc.
Today, Oil and Natural Gas Corporation Ltd. (ONGC) is, the leader in Exploration &
Production (E&P) activities in India having 72% contribution to India’s total
production of crude oil and 48% of natural gas. ONGC has established more than 7
Billion Tones of in-place hydrocarbon reserves in the country. In fact, six out of seven
producing basins in India have been discovered by ONGC. ONGC produces more
than 1.27 million Barrels of Oil Equivalent (BOE) per day. It also contributes over
three million tons per annum of Value-Added-Products including LPG, C2 - C3,
Naphtha, MS, HSD, Aviation Fuel, SKO etc.
ABOUT ONGC
Oil and Natural Gas Corporation Limited (ONGC) is an Indian multinational oil
and gas company headquartered in Dehradun, India . It is a public secttor undertaking
(PSU) of the goverment of India, under the administrative control of the Ministry of
Petroleum and Natural Gas . It is India's largest Oil and Gas exploration and
production company. It produces around 69% of India's crude oil(equivalent to
around 30% of the country's total demand) and around 62% of its natural gas.
ONGC currently holds a 68.94% equity stake. It is involved in exploring for and
exploiting hydrocarbons in 26 sedimentary basins of India, and owns and operates
over 11,000 kilometers 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 (enhance oil recovery) schemes.
ONGC has many matured fields with a current recovery factor of 25-33%.Its Reserve
Replacement Ratio for between 2005 and 2013, has been more than one.During FY
2012-13, ONGC had to share the highest ever under-recovery of INR 494.2 million
an increase of INR 49.6 million over the previous financial year) towards the under-
recoveries of Oil Marketing Companies (IOC, BPCL and HPCL).
Administrative Ministry: Ministry of Petroleum & Natural Gas, Government of India
2nd Floor, Shastri Bhawan Dr. R.P. Marg, New Delhi-110001
Share Capital i) Authorised : Rs. 15000.00 crore
ii) Issued and Subscribed : Rs. 2138.87 crore
iii) Paid Up : Rs. 2138.87 crore
Present Shareholding : The shareholding pattern as on 16 th March 2007 is as
follows:
Name(%)
a) President of India - 74.13
b) Body Corporates - 10.49
c) FI Is / NRI/ FR/Resident Indivs -10.59
d) IFIs /Mutual Fund/Banks - 4.59
e) Resident Individuals. - 1.84
f) Others - 0.14
NOTE: Status of shareholding pattern changes every fortnight.
Listing with Stock: The Securities of the Company are presently Exchanges listed
with the following stock exchanges:
i) Bombay Stock Exchange, Mumbai
ii) The National Stock Exchange of India Ltd, Mumbai The Company has the
following ASSETS /PLANTS/ BASINS/ REGIONS/ INSTITUTES/ SERVICES:

A. ASSETS/ PLANTS:
1.Mumbai High Asset, Mumbai
2.Neelam & Heera Asset, Mumbai
3.Bassein & Satellite Asset, Mumbai
4.Uran Plant, Uran
5.Hazira Plant, Hazira
6.Ahmedabad Asset, Ahmedabad
7.Ankleshwar Asset, Mehsana
8.Mehsana Asset, Mehsana
9.Rajamundry Asset, Rajamundry
10. Karaikal Asset, Karaikal
11. Assam Asset, Nazira
12. Tripura Asset, Agartala
B. BASINS:
1. Western Offshore Basin, Mumbai
2.Western Onshore Basin Vadodara
3.KG Basin, Rajamundry
4.Cauvery Basin , Chennai
5.Assam & Assam-Arakan Basin , Jorhat
6.CBM- BPM Basin , Kolkata
7.Frontier Basin , Dehradun
C. REGIONS:
1.Mumbai Region, Mumbai
2. Western Region, Baroda
3. Eastern Region, Nazira
4. Southern Region, Chennai
5. Central Region, Kolkata
D. INSTITUTES:
1. Keshava Dev Malaviya Institute of Petroleum Exploration (KDMIPE), Dehradun
2. Institute of Drilling Technology (IDT), Dehradun

3. Institute of Reservoir Studies, Ahmedabad
4. Institute of Oil & Gas Production Technology, Navi Mumbai
5. Institute of Engineering & Ocean Technology, Navi Mumbai
6. Geo- data Processing & Interpretation Center (GEOPIC), Dehradun
7. ONGC Academy , Dehradun
8. Institute of Petroleum Safety, Health & Environment Management, Goa .
9. Institute of Biotechnology & Geotectonics Studies, Jorhat
10. School of Maintenance Practices, Vadodara
11. Regional Training Institutes, Navi Mumbai, Chennai, Sivasagar & Vadodara.
Functions & Duties
Oil And Natural Gas Corporation has been established to carry out the objectives
specified in the Memorandum & Articles of Association of the Company. The main
objectives are:
1.To acquire whole or any part of the undertaking, business, the assets/liabilities,
rights, obligations, power, goodwill, privileges, functions and associated
establishment of whatever nature of the Oil & Natural Gas Commission [Established
under the Oil & Natural Gas Commission Act (No. 43 of 1959)] and for that purpose
carry into and carry into effect such agreements, contracts, arrangements as may
become necessary.
2. To plan, promote, organize and implement programmes for the development of
Petroleum Resources and the Production and Sale of Petroleum and Petroleum
Products produced by it and for all matters connected therewith.
3. To plan, promote, organize exploit and implement programmes for the efficient
development of petroleum and petroleum products and alternate resources of energy,
and the production, distribution, conservation and sale of Petroleum and other
products/services produced by it and for all the matters connected therewith.
4. To carry out exploration and to develop and optimise production of hydrocarbons
and to maximise the contribution to the economy of the country. To carry out
geological, geophysical or any other kind of surveys for exploration of petroleum
resources; to carry out drilling and other prospecting operations; to probe and

estimate the reserve of petroleum resources; to undertake, encourage and promote
such other activities as may lead to the establishment of such reserves including
geological, chemical, scientific and other investigations.
5. To search for, purchase, take on lease or license, obtain concession or otherwise
acquire any estate or interest in, develop the resources of work, dispose off or
otherwise turn to account, land or sea or any other place in whole of India or in any
other part of the world containing or likely to contain, petroleum, petroleum
resources or alternative sources of energy or other oils in any form, asphalt, bitumen
or similar substances or natural gas, chemicals or any substances used, or which is
thought likely to be useful for any purpose for which petroleum or any oils in any
form, asphalt, bitumen or similar substances or natural gas is, or could be used or to
that end to organise, equip or employ expeditions, commissions, experts and other
agents and to sink wells, to make boring and otherwise to search for, obtain, exploit,
develop, render suitable for trade, petroleum, other mineral oils, natural gas, asphalt,
or other similar substances or product thereof.
6. To undertake, assist, encourage or swap or promote the production of petroleum
resources and to carry on in all their respective branches all or any of the business of
producing, treating, (including the redefining of crude oil) storing, transportation,
importing, exporting, swapping and generally dealing in or with, petroleum or other
crude oils, asphalt, bitumen, natural gas, refinery gasses, liquefied petroleum gas and
all other kind of petroleum products, chemicals and any such substances aforesaid.
7. To carry on all marketing and distribution of all kinds of petroleum products and to
purchase or otherwise acquire manufacture, refine, treat, reduce, distil, blend purify
and pump, store, hold transport, use, experiment with market distribute, exchange,
supply, sell or otherwise dispose of, import, export and trade and generally deal in
any and all kinds of petroleum products, oil, gas and other volatile substances.
8. To carry on all or any of the businesses of the sale and purchase of petroleum and
other crude oil, asphalt, bitumen, natural gas, liquefied petroleum gas, chemicals and
all kinds of petroleum products, treat and turn to account in any manner whatsoever
petroleum and other crude oils, asphalt, bitumen, natural gas, liquefied petroleum gas
and all kinds of petroleum products, chemicals and any such substance as aforesaid.
9. To establish, provide, maintain and perform scientific, technical, engineering,

project management, consulting/contacting services including but without limiting to
technical studies, design, construction, maintenance, repair all kinds of works and
buildings, procurement, inspection expediting, management of construction and
related services for petroleum reservoir, storage and transportation of oil, gas and
other minerals by pipeline in or otherwise, seismic data acquisition, interpretation,
logging, drilling, cementing, other oil fields related equipment.
10. To promote, organise, or carry on the business of consultancy services in any field
of activity in which the Company is engaged in or connected therewith.
It is a duty of ONGC to do its business operation within the objectives specified in
the Memorandum & Articles of Association in a most fair and transparent manner. It
is also a duty of ONGC to protect interest of its stakeholders as well as to maximize
the wealth of the shareholders. ONGC is committed to achieve its goals as enshrined
in the Vision & Mission Statement of the Company, which is enumerated below:
OUR VISION
To be a world-class Oil and Gas Company integrated in energy business with
dominant Indian leadership and global presence.
OUR NEW VISION
GIVEN BY HON'BLE PRESIDENT OF INDIA DR. APJ ABDUL KALAM
“I would suggest ONGC to give world leadership in management of energy source,
exploration of energy sources, diversification of energy sources, technology in
Underground Coal Gasification, and above all, finding new ways of tapping energy
wherever it is, to meet the ever-growing demand of the country.”
STRATEGIC VISION: 2001-2020
Focusing on core business of E&P, ONGC has set strategic objectives of :
• Doubling reserves (i.e. accreting 6 billion tonnes of O+OEG) by 2020; out of this 4
billion tonnes are targeted from the Deep-waters.
• Improving average recovery from 28 per cent to 40 per cent.
• Tie-up 20 MMTPA of equity Hydrocarbon from abroad.

• The focus of management will be to monetise the assets as well as to assetise the
money.
OUR MISSION
World Class
• Dedicated to excellence by leveraging competitive advantages in R&D and
technology with involved people.
• Imbibe high standards of business ethics and organizational values.
• Abiding commitment to safety, health and environment to enrich quality of
community life.
• Foster a culture of trust, openness and mutual concern to make working a
stimulating and challenging experience for our people.
• Strive for customer delight through quality products and services.
Integrated In Energy Business
• Focus on domestic and international oil and gas exploration and production business
opportunities.
• Provide value linkages in other sectors of energy business.
• Create growth opportunities and maximize shareholder value.
Dominant Indian Leadership
• Retain dominant position in Indian petroleum sector and enhance India's energy
availability.
The ONGC Group of Companies comprises of –
1. ONGC Videsh Limited (OVL) : OVL is the wholly own
subsidiary of ONGC which has been mandated to carry out
international E&P business operations of the parent company.
2. Mangalore Refinery and Petrochemicals Limited (MRPL) :
This is a 71.60% subsidiary of ONGC. It is the only other
listed company besides parent ONGC within the ONGC group.

3. ONGC Nile Ganga BV (ONG BV) : This is the wholly
owned subsidiary of ONGC Videsh Limited which, in turn, is
100% owned by ONGC. The company was incorporated in
Netherlands and has 25% participating interest in the Greater
Nile Oil Project in Sudan producing crude oil from on-shore
blocks earmarked for the purpose.
4. ONGC Mittal Energy Limted (OMEL) : This is the joint
venture between ONGC Videsh Limited and Mittal
Investments Sarl in the ratio of 49.98% : 48.02% with SBI
Capital holding the remaining 2%. This joint venture aims to
source equity oil and gas from abroad for securing India's
energy independence.
5. ONGC Mittal Energy Services Limited (OMESL) : This is
the joint venture between ONGC Videsh Limited and Mittal
Investments Sarl with the same ownership structure as that of
OMEL. This joint venture will be involved in trading and
shipping of oil and gas (including LNG) sourced by OMEL
from abroad.
6. ONGC Tripura Power Company Pvt.Ltd. (OTPCL) :
ONGC has embarked upon a project for generation of power
with 750 MW gas based closed-cycle power plant. The project
is being developed by a SPV between IL&FS, Government of
Tripura and ONGC with an equity share of 50%, 24% and
26% respectively. The project is estimated to cost around Rs
3800 Crores and is expected to be commissioned during the
first quarter of 2008.
7. Kakinada Refinery & Petrochemicals Limited (KRPL) :
This is a public private joint venture company formed pursuant
to an MOU between MRPL, Kakinada Seaport
Limited(KSPL), IL&FS and AP Government, to set up an
export-oriented refinery of 7.5 MMTPA capacity at Kakinada
in coastal Andhra Pradesh which is envisaged to be integrated
with bio-diesel facility.
8. Kakinada SEZ Limited : In tune with the recent initiatives of
Ministry of Commerce and Industry, Govt.of India, for
declaring Special Economic Zones (SEZs) to boos industrial

growth in the country, ONGC/MRPL has become co-promotor
under public-private partnership to form this joint venture
company and it is envistaged that KRPL and other gas
infrastructure units will be located within the Kakinada SEZ to
liverage financial initiatives and to bolster economic growth.
9. Mangalore SEZ Limited : With a view to providing synergy
with MRPL, large petroleum and petrochemicals based
projects are envisaged to be developed at Mangalore. With
view to optimizing the capital cost during the construction of
the project and subsequently promoting sale of petrochemical
intermediates, a decision was taken to associate with a special
economic zone (SEZ) Contemplated for development at
Mangalore. The SEZ will be an SPV with Karnataka Industrial
Areas Development Board (KIEDB), Karnataka Chambers of
Commerce and Industry (KCCL) and ONGC between them
bringing in 49% equity with ONGC contributing 26%. IL &
FS has offered to take the remaining 51% equity. This SPV is
in the process of being incorporated.
10
.
Dahej SEZ Limited : ONGC participating in the initiative of
Govt. of Gujarat has formed a joint venture company under
public private partnership to establish and develop necessary
infrastructure facilities within a land of 1740 hectares in
cooperation with Gujarat Industrial Development Corporation.
ONGC is currently engaged in implementing its C2-C3
extraction project, which will be located within this SEZ.
11.Rajasthan Refinery Limited (RRL) : With the recent
discovery of waxy oil in Mangla and other adjoining structure
by Cairn Energy India, its PSC partner in Rajashtan Block,
MRPL has been nominated by Govt. of India as its nominee
for buying the crude oil to be produced from this block.
MRPL, in coordination with Cairn Energy, and as per due
facilitation by Rajasthan Govt., has proposed to form a joint
venture company named Rajasthan Refinery Limited (RRL),
which will examine the techno-economic viability of
establishing a well-head refinery of 7.5 MMPPA Capacity and
if found feasible will implement the same at a suitable location
in Rajasthan.

AWARDS AND ACHIEVEMENTS (2012-2014)
• ONGC was ranked as the Most Attractive Employer in the Energy sector in
India, in the
RANDSTAD award 2013
• ONGC was one of 12 winners of the ‘Golden Peacock Award 2014’ for
corporate social and responsibility practices, and one of 24 winners of the
‘Golden Peacock Award 2013’ in the occupational safety and health category.
• In April 2013, it was ranked at 155th place in the Forbes global 2000 for 2012.
• In 2011, ONGC was ranked 39th among the world's 105 largest listed
companies in 'transparency in corporate reporting' by Transparency
International making it the most transparent company in India.
• It was conferred with 'Maharatna' status by the Government of India in
November 2010. The Maharatna status to select PSUs allows more freedom in
decision making.
• In February 2014, FICCI conferred it with Best Company Promoting Sports
Award.
• ONGC wins the "Greentech Excellence Award" for the year 2013 in Platinum
Category
• ONGC was ranked 82nd among India's most trusted brands according to the
Brand Trust Report 2012, a study conducted by Trust Research Advisory. In the
Brand Trust Report 2013, ONGC was ranked 191st among India's most trusted
brands and subsequently, according to the Brand Trust Report 2014, ONGC
was ranked 370th among India's most trusted brand
VISIONS AND MISSIONS OF ONGC
TO BE WORLD CLASS OILAND GAS COMPANY INTEGRATED IN
ENERGY BUSSINESS WITH DOMINANT INDIAN LEADERSHIPAND
GLOBAL PRESENCE
• dedicated to excellence by leveraging competetive advantages in R&D and
technology with involved people
• imbibe high standards of bussiness ethics and organizational values.
• Abiding commitment of safety, health and enviroment to enrich quality of
community life.
• Foster a culture of trust, openness and mutual concern to make working a

simulating and challenging experience for our people.
• Strive for customer delight through quality products and services.
• Focus on domestic and international oil and gas exploration and production
bussiness opportunities.
• Provide value linkages in other sectors of energy bussiness.
• Create growth opportunities and maximize shareholder value.
• Retain dominant position in indian petroleum sector and enhance india's energy
availability.
Keshav Deva Malviya Institute of Petroleum
Exploration
Keshav deva malviya institute of petroleum exploration(KDMIPE) is located at
dehradun in the state of uttrakhand. Founded in 1962 with the objective to provide
geo-scientific back up to the exploratory efforts of india's national oil company
ONGC.
The institute was rechristened as keshav deva malviya institute of petroleum
exploration(KDMIPE) on 19th
december, 1981 by prime minister of india late Mrs.
Indira gandhi in the memory of the father of indian petroleum industry and the first
chairman of ONGC- late Shri kehav deva malaviya. Since its inception the inustitute
is continously providing its geoscientific support towards finding more oil and gas in
various basins within india and globally , wherever ONGC is seeking bussiness.
Presently the institute is the nodal agency for the multidisciplinary synergistic basin
scale and domain specific research in exploration. The institute has strength of around
300 highly experienced scientists and technical officers in the field of geoscientific
research, basin research, resource and acreages Appraisal and E&P data management.
It is equipped with state of the art facilities, soft wares and cutting edge technologies.
The institute caters to the needs of all the basins currently under active exploration
and producing assets, both in india as wall as overseas operation by our sister
company ONGC videsh limited. We also provide consultancy services in areas of
geoscience and exploration to natural and international oil companies.
KDMIPE is an ISO: 9001, 14001 & OHSAS 18001 certified institute. To achieve the
highest standard of quality, health, safety and environment, KDMIPE has strived to

get QHSE certificate and the same was awarded to KDMIPE on 13th
2008.
KDMIPE is the sub unit of public sector oil and natural gas corporation limited.
Various innivatives, problem solving measures, indigeneous resourcing and applied
R&D are carried out totally caters to the requirement of the different assets/basins of
its parent company,ONGC.
The institute has recently taken new initiatives in non conventional energy sources,
and induced synthetic aperture radar(SAR) . Sea bed logging(SBL), Q-Marine and
GX technology and other contempory processing and interpretation softwares on
application tools. Institute with its intellect and state of the art technology continously
strive for improving success ratio in exploration and opening up of new basins and
provinces for overall enegy security of the nation.
VARIOUS LABS AND GROUPS OF KDMIPE
• basin research group
• sedimentary lab
• paleontology lab
• palynology lab
• geochronology lab
• remote sensing
• flow assurance lab
• geophysics group
• geochemistry group
CRUDE OIL
A naturally occurring, unrefined petroleum product composed of hydrocarbon
deposits.Although it is often called "black gold," crude oil has ranging viscosity and
can vary in color to various shades of black and yellow depending on its hydrocarbon
composition.petroleum or crude oil is naturally occuring oily, bitumimous liquid
composed of various organic chemicals. Existing in the gaseous or liquid state in the
narural reservior. It is found in large quantities below the surface of earth and is used
as a fuel and as a raw material in the chemical industry. It is mainly composed of
hydrocarbons although a few sulphur-containing and oxygen containing compounds
are usually present, the sulphur content varies from 0.1 to 5 percent.

The various compostion of crude oil are :
Element Weight% Hydrocarbon Weight%
Carbon 83-87 paraffins 30
hydrogen 10-14 napthenes 49
nitrogen 0.1-2 aromatics 15
oxygen 0.1-1.5 asphaltics 6
sulphur 0.5-6
metals <0.1
Petroleum products differ in molecular weight, size and type. So the compounds in
petroleum have different vapor pressure at a temperature or they have different
boiling points. So distillation is most widely used method to separate various
fractions from crude oil. The main fraction of crude oil their carbon, boiling point are
given under:
Name Number of
Carbon Atoms
Boiling Point
(°C)
Uses
Refinery Gas 3 or 4 below 30 Bottled Gas
(propane or
butane).
Petrol 7 to 9 100 to 150 Fuel for car
engines.
Naphtha 6 to 11 70 to 200 Solvents
and used in
petrol.
Kerosene
(paraffin)
11 to 18 200 to 300 Fuel for aircraft
and stoves.
Diesel Oil 11 to 18 200 to 300 Fuel for road
vehicles

and trains.
Lubricating Oil 18 to 25 300 to 400 Lubricant for
engines
and machines.
Fuel Oil 20 to 27 350 to 450 Fuel for ships,
heating
and power
stations.
Greases and
Wax
25 to 30 400 to 500 Lubricants
and candles.
Bitumen above 35 above 500 Road surface
and roofing.
PETROLEUM GEOCHEMISTRY:
petroleum geochemistry is the branch of geochemistry that deals with the
composition and distribution of petroleum and related substances in sedimentary
basins, the aim of petroleum geochemistry is understand the origin, migration,
occurence and alteration of petroleum in sedimentary basins. The information
obtained from petroleum geochemistry is integrated with the information obtained
from petroleum geology and geophysics to arrive at model of occurence of
hydrocarbon which helps in exploration and priorization of hydrocarbon prospects.
ORIGIN OF PETROLEUM :
Petroleum is a naturally occurring substance consisting of organic compounds in the
form of gas, liquid, or semisolid. Organic compounds are carbon molecules that are
bound to hydrogen (e.g., hydrocarbons) and to a lesser extent sulfur, oxygen, or
nitrogen. The simplest of these compounds is methane with one carbon atom bound
to four hydrogen atoms (Figure 1). Asphaltenes are the most complex with more than
136 carbon atoms bound to more than 167 hydrogen atoms, 3 nitrogen atoms, 2
oxygen atoms, and 2 sulfur atoms (Figure 1). Petroleum gas is referred to as natural
gas, which should not be confused with the abbreviated term used to describe the
refined fuel "gasoline". Natural gas consists predominantly of simple hydrocarbons
with only one to five carbon atoms (i.e., methane to pentane, respectively, Figure 1).
Liquid petroleum is referred to as crude oil and consists of a wide range of more
complex hydrocarbons and minor quantities of asphaltenes (Figure 1). Semisolid

petroleum is tar, which is dominated by larger complex hydrocarbons and asphaltenes
(Figure 1).
Figure 1. Some examples of organic compounds in petroleum, from the simplest (methane) to the
most complex (asphaltene).
Petroleum formation takes place in sedimentary basins, which are areas where the
Earth's crust subsides and sediments accumulate within the resulting depression. As
the sedimentary basin continues to subside, sediment accumulations continue to fill
the depression. This results in a thickening sequence of sediment layers in which the
lower sediment layers eventually solidify into sedimentary rocks as they experience
greater pressures and temperatures with burial depth. The sediment layers that
accumulate vary in character because the sources and depositional settings of the
sediments change through geologic time as the sedimentary basin subsides and fills.
It is critical to petroleum formation that at some time during the accumulation of
sediments at least one of the sediment layers contains the remains of deceased plants
or microorganisms. Throughout geologic time, the world oceans have expanded and
receded over the Earth’s land surfaces and contributed sediment layers to subsiding
sedimentary basins. Development of stagnant water conditions in some of the
expanded oceans caused the bottom waters to be depleted in oxygen (anoxic), which
allowed portions of decaying plankton (e.g., algae, copepods, bacteria, and archaea)
that originally lived in the upper oxygen-bearing (oxic) waters to be preserved as a
sediment layer enriched in organic matter (Figure 2). Swamps and marshes may also
develop marginal to oceans overlying subsiding basins. In these depositional settings,

sediment layers enriched in decaying land plants (e.g., trees, shrubs, and grasses) may
occur.
As these organic-rich sediment layers are buried by deposition of overlying sediments
in the subsiding basin, the sediments are compressed and eventually lithified into
rocks referred to as black shale, bituminous limestone, or coal. Methane producing
microorganisms referred to as methanogens may thrive under certain favorable
conditions within the organic-rich sediment layer during its early burial. These
microorganisms consume portions of the organic matter as a food source and generate
methane as a byproduct. This methane, which is typically the main hydrocarbon in
natural gas, has a distinct neutron deficiency in its carbon nuclei (i.e., carbon
isotopes), which allows microbial natural gas (a.k.a., biogenic gas) to be readily
distinguished from methane generated by thermal processes (a.k.a., thermogenic gas)
later in a basin's subsidence history. The microbial methane may remain in the
organic-rich layer or it may bubble up into the overlying sediment layers and escape
into the ocean waters or atmosphere. If impermeable sediment layers, called seals,
hinder the upward migration of microbial gas, the gas may collect in underlying
porous sediments, called reservoirs
(Figure 3).
Figure 2: Formation of organic-rich sediment
layer.
Figure 3: Early burial of sediment layers in
basin.

Economically significant accumulations of microbial natural gas have been estimated
to account for 20 percent of the world’s produced natural gas. Microbial methane
may remain trapped in the organic-rich sediment layer through out its lithificaton and
contribute to economic accumulations referred to as coal-bed methane and shale gas.
Burial of the organic-rich rock layer may continue in some subsiding basins to depths
of 6,000 to 18,000 feet (1830 to 5490 m).At these depths, the organic-rich rock layer
is exposed to temperatures of 150 to 350 ºF (66 to 177 ºC) for a few million to tens of
millions of years. The organic matter within the organic-rich rock layer begins to
cook during this period of heating and portions of it thermally decompose into crude
oil and natural gas (i.e., thermogenic gas) (Figure 4).
This overall process of cooking petroleum out of an organic-rich rock layer involves
the appropriate combination of temperature and time and is referred to as thermal
maturation. If the original source of the organic matter is mostly higher plants (e.g.,
trees, shrubs, and grasses), natural gas will be the dominant petroleum generated with
lesser amounts of crude oil generation. If the original source of the organic matter is
plankton (e.g., algae, copepods, and bacteria), crude oil will be the dominant
petroleum generated with lesser amounts of natural gas generation. Organic-rich rock
layers that have undergone this process of petroleum generation are considered to be
thermally mature and referred to as source rocks.
Organic-rich rocks that have not been thermally matured are referred to as being
thermally immature. These immature organic-rich rocks may be referred to as oil
shale if artificial heating at high temperatures (~1000ºF/~538ºC) in surface or near-
surface reactors (a.k.a., retorts) yield economic quantities of oil. Oil shale retorting
occurred in Scotland between 1860 and 1960 and is currently active in Estonia and
Brazil.
Petroleum has a lower density than the water that occupies pores, voids, and cracks in
the source rock and the overlying rock and sediment layers. This density difference
forces the generated petroleum to migrate upwards by buoyancy until sealed
reservoirs in the proper configurations serve as traps that concentrate and collect the
petroleum. Some of the generated natural gas may not migrate out and away from its
source rock, but instead remains within microscopic pores and dissolved in the
organic matter of its source rock. This retained natural gas has proven to be an
economically significant resource that is referred to as shale gas. The Barnett Shale in
the Fort Worth basin of Texas is a good example of this type of accumulation.
In some basins, petroleum may not encounter a trap and continue migrating upward
into the overlying water or atmosphere as petroleum seeps. Crude oil that migrates to

or near the surface of a basin will lose a considerable amount of its hydrocarbons to
evaporation, water washing, and microbial degradation leaving a residual tar enriched
in large complex hydrocarbons and asphaltenes (Figure 5). Tar deposits range in size
from small local seeps like the La Brea tar pits of California to regionally extensive
occurrences as observed in the Athabasca tar sands of Alberta.
Figure 4: Continued burial of sediment and
rock layers in subsiding basin.
Figure 5: Deeper burial of rock layers in
subsiding basin.
Burial of the source rock may continue to depths greater than 20,000 ft. (6100 m) in
some sedimentary basins. At these depths, temperatures in greater than 350ºF (177ºC)
and pressures greater than 15,000 psi (103 MPa) transform the remaining organic
matter into more natural gas and a residual carbon referred to as char. Oil trapped in
reservoirs that are sometimes buried to these depths also decomposes to natural gas
and char. The char, which is also called pyrobitumen, remains in the original reservoir
while the generated natural gas may migrate upward to shallower traps within the
overlying rock layers of the basin. The Gulf Coast basin that extends into the offshore
of Louisiana and the Anadarko basin of the US mid-continent are good examples of
these deep basins.
Further burial to temperatures and pressures in excess of 600ºF (316ºC) and 60,000
psi (414 MPa), respectively, represent metamorphic conditions in which the residual
char converts to graphite with the emission of molecular hydrogen gas. The resulting
metamorphic rocks are graphitic slate, schist or marble. Thermodynamic
considerations indicate that water remaining in these rocks should react with the
graphite to form either methane or carbon dioxide depending on the amount of
molecular hydrogen present. Currently, the deepest wells in sedimentary basins do
not exceed 32,000 ft (9760 m). Therefore, the significance of natural gas generation
under these extreme conditions remains uncertain.

Sedimentary basins vary considerably in size, shape, and depth all over the Earth’s crust (Figure 6).
Figure 6: General outline of major sedimentary basins.
A large number of variables and different combinations of these variables determine
whether a sedimentary basin contains microbial methane, natural gas, crude oil, tars,
or no petroleum. Not all basins have organic-rich sediment layers deposited during
their subsidence history. As a result, these basins will contain no appreciable
quantities of petroleum regardless of how deep the basin subsides. Other basins that
do have an organic-rich rock layer may not have been buried to sufficient depths to
generate natural gas or crude oil through thermal maturation, but may contain
microbial methane accumulations. An organic-rich rock layer in some basins may
thermally mature to generate mostly natural gas because of the dominance of higher
plant debris contributing to its organic matter. Conversely, an organic-rich rock layer
in other basins may thermally mature to generate mostly crude oil because of the
dominance of lower plant debris contributing to its organic matter. More than one
organic-rich rock layer may be deposited in the burial history of some basins with all,
one, or none subsiding deep enough to thermally mature to generate petroleum. In
other basins that have an organic-rich rock layer and sufficient burial to generate
petroleum, the lack or scarcity of seals and reservoirs to collect generated petroleum
may result in natural gas losses to the atmosphere or large degraded oil and tar
deposits at or near the basin surface.
Research on these variables is critical to understanding the occurrences of known
petroleum accumulations from which predictions can be made as to where
undiscovered petroleum still resides within the Earth's crust. Research depends
heavily on data collected from rock outcrops around and subsurface drilling in
sedimentary basins. This geological data is essential to understanding of the
development of sediment and rock layers (i.e., stratigraphy) within a basin and the
history of their subsidence and trap development (i.e., tectonics). However, the

vastness of sedimentary basins, limited well data, and migration of petroleum away
from its source also requires research to 1. establish fingerprinting methods to
determine genetic correlations among different petroleum types and their source and
2. conduct laboratory experiments to simulate petroleum generation and alteration to
predict types, amounts, and extent of petroleum generated under varying subsurface
conditions. Collectively, this understanding of genetically related petroleum, source
rock identification, levels of thermal maturation, migration distances, and degrees of
near-surface degradation allows construction of computer models of petroleum
generation, migration, and accumulation through time within an evolving
sedimentary basin.
FORMS OF PETROLEUM:
based on the physical state of mixture of hydrocarbons, petroleum is classified into
three forms:
• crude oil-liquid form of petroleum
• condensate-gaseous in subsurface and liquid at surface
• gas-does not condensate at STP
MOLECULAR TYPES VARIATION IN HYDROCARBON:
NORMALALKANES:
normal alkanes are the hydrocarbons in which carbon atoms join together to form a
straight chain,with single bonds between carbon atoms. These compounds are also
called open chain compounds. These are represented by genral formula CnH2n+2
where, n is any number between 1to 60.
ISO ALKANES:
Iso alkanesare the hydrocarbons in which carbon atoms are joined to form chain with
some branching, with single bonds between carbon atoms. The smallest iso alkane in
which branching is possible is the hydrocarbon containing 4 carbon atoms.the
isobutane is the smallest iso alkane and by adding a CH2 the next iso alkane(iso-
pentane) ans similarly the complete homogeneous series can be obtained.

ALKANES IN OIL:
In principal zone of oil formation substantial amount of new alkanes are generated
but at greater depths where cracking becomes imporatant distribution curves are more
or more dominant by lighter molecules in all type of sediments
ISOPRENOIDS:
Isoprenoids are special class of iso alkanes with specific orientation of carbon atoms
in the chain. These consist of straight chains of carbon with one methyl group branch
at every fourth carbon atom in the chain. The smallest isoprenoid found in oil is
C9H20 and the largest isoprenoids is C25H52. The most abundant isoprenoids are
pristane C19H40 and phytane C20H42.
ISOPRENOIDS IN OIL:
These molecules of biogenic origin are mostly present in young sediments as fully
saturated, unsaturated and partly aromatized hydrocarbon or as related structure such
as acid or alcohol. During principal stage of hydrocarbon formation the abundance of
polycyclic decreases either by dilution with newly generated hydrocarbon or by
degradation.
CYCLOALKANES:
Cycloalkanes are the hydrocarbons that are formed by joining the carbon atoms in a
ring. With single bonds between carbon atoms. The smallest cycloalkane is
cyclopentane in which five carbon atoms join to form a ring . The necxt and most
common cycloalkanes is cyclohexane in which six carbon atoms form a ring. Higher
cycloalkanes are formed by the condensation of mainly cyclohexane rings.
Cycloalkanes are thus classified based on the number of condensed rings as
monocyclic(1 ring), bicyclic(2 rings), tricyclic(3 rings) , tetracyclic(4 rings ) and
pentacyclic(5 rings).
AROMATICS:
Aromatics are the hydrocarbons that are composed of at least one benzene ring. In
benzene ring six carbon atoms join together to form a ring with alternate single and
double bonds between carbon atoms. The smallest aromatic hydrocarbon is benzene,

higher aromatics are formed by the condensation of benzene rings. Thus aromatics
are also classified based on the number of benzene rings in the molecules as
monocyclic(1 ring) through pentacyclic(5 rings).
CYCLOALKANO-AROMATICS:
Cycloalkano-aromatics are the hydrocarbons that consist of condensed cycloalkanes
and aromatics . The cycloalkane and aromatics molecules share two carbon atoms
with a single bond in common. The cycloalkane part is characterised by carbon atoms
joined with single bonds while aromatics part is characterised by alternates singe and
double bond.
AROMATIC HYDROCARBONS IN OIL:
Ratio of aromatic hydrocarbons to organic carbon increases with depth but than does
the ratio of total hydrocarbon to organic carbon.
NON HYDROCARBONS:
The compounds containing atoms of nitrogen, sulphur or oxygen in the molecule are
called non hydrocarbons. These elements are present in compund in small quantities
but their amount effect the oil nature.
SULPHUR COMPOUNDS :
In the low and medium molecular weight range (upto C25) sulphur is associated only
with carbon and hydrogen. In the heavier fractions of crude oil.it is frequently
incorporated inlarge polycyclic molecules comprising NSOs. Sulphur compounds
identified in the light and medium raction of crude oils belong to four main classes of
compound. These are
1. thiols or merceptans
2. sulphides
3. disulphide and thiophenes

NITROGEN COMPOUNDS:
Nitrogen content is usually lower than sulphur content in crude oil. The main part of
nitrogen is found in high molecular weight and high boiling point fractions.
OXYGEN COMPOUNS:
Saturated fatty acids (C1 to C20) and naphthenic acids occur in immature oils. The
most ubiquitous group of oxygen compounds in crude oils is probably the group of
pentacyclic acids with a hopane skeleton. Several phenois, such as cresols and ketons,
fluorenones and dibenzofurans are found.
STAGES OF ORGANIC MATTER MATURATION
The transformation process of organic matter involves three stages. These are
DIAGENESIS:
Diagenesis occurs in the shallow subsurface and begins during initial deposition and
burial. It takes place at depths from shallow to perhaps as deep as 1,000 meters and at
temperature ranging from near normal to less than 60oC. Biogenic decay aided by
bacteria (such asThiobacillus) and non-biogenic reactions are the principal processes
at work producing primarily CH4 (Methane), CO2 (Carbon Dioxide), H2O (Water),
kerogen, a precursor to the creation of the petroleum, and bitumen. Temperature plays
an important role in the process. Ambient temperatures increase with depth of burial
which decreases the role of bacteria in the biogenic reactions because they die out.
However, much of the initial methane production begins to decline because it is the
bacteria that produces the methane as a by-product during diagenesis. Simultaneous
to the death of the bacteria however, the increased temperatures accelerate organic
reactions.
Kerogen: the name given to insoluble, disseminated organic (carbonaceous) matter
in sediments.
Bitumen: the name given to soluble, disseminated organic (carbonaceous) matter in
sediments.
CATAGENESIS:
The Catagenesis (meaning thermodynamic, nonbiogenic process) phase becomes

dominant in the deeper subsurface as burial (1,000 - 6,000 m), heating (60 - 175oC),
and deposition continues. The transformation of kerogen into petroleum is brought
about by a rate controlled, thermocatalytic process where the dominant agents are
temperature and pressure. The critical temperature is about 60o C which is called the
critical jump temperature; this is the beginning of oil formation which is referred to
as the liquid window. The temperatures are of non-biological origin; heat is derived
from the burial process and the geothermal gradient that exists within the earth's
crust. The catalysts are various surfactant materials in clays and sulfur. Above 200o
C, the catagenesis process is destructive and all hydrocarbons are converted to
methane and graphite. And at 300o C, hydrocarbon molecules become unstable. Thus
thermal energy (temperature) is a critical factor, but it is not the only factor The time
factor is also critical because it provides stable conditions over long periods of time
that allows the kerogen sufficient cooking time - exposure time of kerogen to
catagenesis. Thus the Catagenesis phase involves the maturation of the kerogen;
petroleum is the first to be released from the kerogen followed by gas, CO2 and H2O.
METAGENESIS:
The third phase is referred to as Metagensis. It occurs at very high temperatures and
pressures which border on low grade metamorphism. The last hydrocarbons released
from the kerogen is generally only methane. The H:C ratio declines until the residue
remaining is comprised mostly of C (carbon) in the form of graphite.
CRUDE OILANALYSIS LAB:
The crude oil analysis lab performs various test and analyzes the crude oil as obtained
during drilling. This lab gives the quality or properties of crude oil.
The oil mainly brought to the oil analysis lab is tested for various parameters such as:
1. pour point
2. API gravity
3. wax content
4. asphathlene content

POUR POINT
DEFINITION AND PRINCIPLE:
The pour point of crude oil is the lowest temperature at which a sample of
petroleum product will continue to flow when it is cooled under specified conditions .
In crude oil a high pour point is generally associated with a high paraffin content.
After preminary heating, the sample is cooled at a specified rate and exmined at
intervals of 3°C for flow characteristics. The lowest temperature at which movement
of the sample is observed is recorded as the pour point.
DESCRIPTION OF THE APPARATUS:
TEST JAR: A test jar of clear glass, flat bottom, approx 30-35mm inner diameter
and 115-125 mm in height.
THERMOMETER:Two thermometers having range -38 to 50 and -80 to 20°C are
used.
CORK:A cork is required to fit the test jar, bored centrally to take the test
thermometer.
JACKET:A watertight cylindrical jacket of glass or metal or glass with a flat
bottom.
DISK:A disk of cork of the same diameter as the inside of the jacket.
GASKET:A gasket made of cork or other suitable material, elastic enough to cling
the test jar and the hard enough to hold its shape. It prevent test jar from touching the
jacket.
BATH:A cooling bath of a type suitable for required temperature for determination of
pour point below 10°C , two or more baths are needed.
PROCEDURE
The ice bath is filled with crushed ice. After preliminary heating of the sample it is
cooled at a specified rate and examined at intervals of 3°C for flow characteristics.
For obtaining the freezing point temperature some crystals of sodium chloride are
also added along with the ice. For further reduction in temperature below 10°C
crystals of calcium chloride are also addes which absorbs the melted ice. Some pour
point depressant(ppd ) are also added

SIGNIFICANCE OF POUR POINT DETERMINATION:
• Indicates the relative amount of wax present in crude oil
• it is the temperature below which pumping and transport problems may be
encountered
• along with viscosity, is used in pumping and designing calculation
API GRAVITY(HYDROMETER METHOD )
The American petroleum institute gravity, or API gravity, is a measure of how heavy
or light a petroleum liquid is compared to water: if its API gravity is greater than 10,
it is lighter and floats on water; if less than 10, it is heavier and sinks.
API gravity is thus an inverse measure of a petroleum liquid's density relative to that
of water (also known as specific gravity). It is used to compare densities of petroleum
liquids. For example, if one petroleum liquid is less dense than another, it has a
greater API gravity. Although mathematically, API gravity is a dimensionless
quantity, see the formula below, it is referred to as being in 'degrees'. API gravity is
gradated in degrees on a hygrometer instrument. API gravity values of most
petroleum liquids fall between 10 and 70 degrees.
API gravity formulas
The formula to calculate API gravity from specific gravity (SG) is:

API GRAVITY=(141.5/SG)-131.5
Conversely, the specific gravity of petroleum liquids can be derived from their API
gravity value as
SG at 60°C=141.5/(API+131.5)
Thus, a heavy oil with a specific gravity of 1.0 (i.e., with the same density as pure
water at 60 °F) has an API gravity of:
141.5/1.0 -131.5=10° API
Classifications or grades
Generally speaking, oil with an API gravity between 40 and 45° commands the
highest prices. Above 45°, the molecular chains become shorter and less valuable to
refineries.
Crude oil is classified as light, medium, or heavy according to its measured API
gravity.
• Light crude oil: has an API gravity higher than 31.1° (i.e., less than 870 kg/m3)
• Medium oil: has an API gravity between 22.3 and 31.1° (i.e., 870 to 920
kg/m3)
• heavy crude oil: has an API gravity below 22.3° (i.e., 920 to 1000 kg/m3)
• Extra heavy oil has an API gravity below 10.0° (i.e., greater than 1000 kg/m3)
However, not all parties use the same grading. The united states geological survey
uses slightly different ranges.
Crude oil with API gravity less than 10° is referred to as extra heavy oil or bitumen.
Bitumen derived from oil sands deposits in Alberta, Canada, has an API gravity of
around 8°. It can be diluted with lighter hydrocarbons to produce diluted bitumen,
which has an API gravity of less than 22.3°, or further "upgraded" to an API gravity
of 31 to 33° as synthetic crude.

PROCEDURE
Taken a relative densityn bottled and weighted it with distilled water poured in it.
After that the crude sample was taken in the bottle and heated in water bath at 40°C
for half an hour. Then it was taken out and weighted again. Density at 40°C can be
obtained.
The std form of the density of oil is mentioned as API GRAVITY .
WAX CONTENT
Wax (paraffin) content is an important characteristic affecting the physical properties
of petroleum crude oils, in particular their viscosity. Thus, measuring wax content has
become a routine analytical requirement for product quality control. In addition, wax
in oils can deposit in downhole pipes, surface equipment and pipelines, and cause
blockages, especially at low temperatures. The precise monitoring of the wax content
in oils helps to predict and avoid wax blockage so that equipment can be maintained
for high quality standards during oil processing.normal paraffins above C16 at
somewhat ambient temperature. These hydrocarbons are calles wax. These
hydrocarbons affect the flow behaviour of crude. The wax content can be calculated
by following formula

%OF WAX CONTENT=WT OF WAX*WT OF OILY FRACTION*100/WT OF OILY FRACTION
FOR WAX PPT*WT OF OIL
PROCEDURE
1. 5-10 gm of crude oil is taken in the beaker.
2. It is dissolved in the petroleum ether (40-50°C) and transferred in to separating
funnel. The whole volume is made up to 9200cc.
3. 15-20cc of conc. Sulfuric acid is then added to it. The whole mixture is
shakenn vigorously and kept for some time. The sludgy material is separated
from it.
4. Step 3 is repeated till color free top layer is obtained.
5. Washing with sodium carbonate and sodium carbonate solution is done and
finally distilled water is used for washing. This is repeated till acid free oil
portion is obtained.
6. Now fused calcium carbonate is added to absorb remaining water. Then it is
removed and sample is washed with petroleum ether.
7. 2-3 gm activated charcoal is used to treat it. Then the container is put on a
water bath for 15-20 min and filteration is done to concentrate oily portion at
50-60°C.
8. Weight at interval of two hours in the beginning and at 1 & 1/2 hrs to get
constant weight up to three decimal place.
9. 0.5-0.6 gm of oily portion is taken in along beaker. It is dissolved in 15cc of
methyl ethyl ketone 15cc of alcohol is used for precipitation and it is
maintained at -20°C.
10.Now a mixture of alcohol and methyl ethyl ketone(1:1)is made(v/v) the
mixture is kept and the wax is precipitated in this bathh for 30min. Filter it in a
buncker funnel and use the mixture.
11.The filtrate is collected and again put in the bath for 1/2 hrs and the wax is
precipitated and reported as weight%.

ASPHALTENES
Asphaltenes are molecular substances that are found in crude oil, along with
resins,aromatics, hydrocarbons and saturates (i.e. saturated hydrocarbons such as
alkanes ). It is the weight % of wax free material insoluble in heptane, but soluble in
hot bemzene. Asphaltenes are polynuclear condensed aromatic HC having high
molecular weight. They are insoluble in heptane and soluble in benzene. Asphaltenes
indicates the presence of heavy HC in crude oi.
A sample is dissolved in heptane and the insoluble material consisting of asphaltenes
and waxy substances is separated under hot reflux with heptane. The asphaltenes are
isolated by extraction with toluene.Asphaltenes in the form of asphalt or bitumen
products from oil refineries are used as paving materials on roads, shingles for roofs,
and waterproof coatings on building foundations.Asphaltenes impart high viscosity to
crude oils, negatively impacting production, also the variable asphaltene
concentration in crude oils within individual reservoirs creates a myriad of production
problems.
PROCEDURE
1. Topping of crude oil sample is done upto 210°C at atmospheric pressure.
Residue is dilluted with 40 volume of petroleum ether to precipitate out
asphaltenes.
2. The mixture is refluxed for 1hr on a water bath and is kept over night
3. The precipitation is filtered and take the filter with the precipitate for solvent
extraction with petroleum ether
4. the asphaltene are then eluted with CHCl3. This extract is concentrated and
transferred to a pre weighted sample tube, dried in a vaccum oven at 40-5°C
till weights is constant and asphaltene % is then computed.
Further analysis of asphaltenes is done by ftir spectrometer.

DRILLING FLUIDS:
Drilling fluid is used to aid the drilling of boreholes into the earth. Often used while
drilling oil and natural gas wells and on exploration drilling rigs , drilling fluids are
also used for much simpler boreholes, such as water wells. Liquid drilling fluid is
often called drilling mud. The three main categories of drilling fluids are water-
based muds (which can be dispersed and non-dispersed), non-aqueous muds, usually
called oil-based mud, and gaseous drilling fluid, in which a wide range of gases can
be used.
The main functions of drilling fluids include providing hydrostatic pressure to
prevent formation fluid from entering into the well bore, keeping the drill bit cool
and clean during drilling, carrying out drill cuttings, and suspending the drill cuttings
while drilling is paused and when the drilling assembly is brought in and out of the
hole. The drilling fluid used for a particular job is selected to avoid formation damage
and to limit corrosion.
Classification of drilling fluids
World Oil’s annual classification of fluid systems lists nine distinct categories of
drilling fluids, including:
• Freshwater systems
• Saltwater systems
• Oil- or synthetic-based systems
• Pneumatic (air, mist, foam, gas) “fluid” systems
Three key factors usually determine the type of fluid selected for a specific well:
• Cost
• Technical performance
• Environmental impact
Water-based fluids (WBFs) are the most widely used systems, and are considered less
expensive than oil-based fluids (OBFs) or synthetic-based fluids (SBFs). The OBFs
and SBFs—also known as invert-emulsion systems—have an oil or synthetic base
fluid as the continuous(or external) phase, and brine as the internal phase. Invert-
emulsion systems have a higher cost per unit than most water-based fluids, so they
often are selected when well conditions call for reliable shale inhibition and/or
excellent lubricity. Water-based systems and invert-emulsion systems can be

formulated to tolerate relatively high downhole temperatures. Pneumatic systems
most commonly are implemented in areas where formation pressures are relatively
low and the risk of lost circulation or formation damage is relatively high. The use of
these systems requires specialized pressure-management equipment to help prevent
the development of hazardous conditions when hydrocarbons are encountered.
Water-based fluids
Water-based fluids (WBFs) are used to drill approximately 80% of all wells. The base
fluid may be fresh water, seawater, brine, saturated brine, or a formate brine. The type
of fluid selected depends on anticipated well conditions or on the specific interval of
the well being drilled. For example, the surface interval typically is drilled with a
low-density water- or seawater-based mud that contains few commercial additives.
These systems incorporate natural clays in the course of the drilling operation. Some
commercial bentonite or attapulgite also may be added to aid in fluid-loss control and
to enhance hole cleaning effectiveness. After surface casing is set and cemented, the
operator often continues drilling with a WBF unless well conditions require
displacing to an oil- or synthetic-based system.
WBFs fall into two broad categories: nondispersed and dispersed.
Non-dispersed sytems
Simple gel-and-water systems used for tophole drilling are nondispersed, as are many
of the advanced polymer systems that contain little or no bentonite. The natural clays
that are incorporated into nondispersed systems are managed through dilution,
encapsulation, and/or flocculation. A properly designed solid-control system can be
used to remove fine solids from the mud system and help maintain drilling efficiency.
The low-solids, nondispersed (LSND) polymer systems rely on high- and low-
molecular-weight long-chain polymers to provide viscosity and fluid-loss control.
Low-colloidal solids are encapsulated and flocculated for more efficient removal at
the surface, which in turn decreases dilution requirements. Specially developed high-
temperature polymers are available to help overcome gelation issues that might occur
on high-pressure, high-temperature (HP/HT) wells. With proper treatment, some
LSND systems can be weighted to 17.0 to 18.0 ppg and run at 350°F and higher.
Dispersed systems
Dispersed systems are treated with chemical dispersants that are designed to
deflocculate clay particles to allow improved rheology control in higher-density
muds. Widely used dispersants include lignosulfonates, lignitic additives, and tannins.
Dispersed systems typically require additions of caustic soda (NaOH) to maintain a

pH level of 10.0 to 11.0. Dispersing a system can increase its tolerance for solids,
making it possible to weight up to 20.0 ppg. The commonly used lignosulfonate
system relies on relatively inexpensive additives and is familiar to most operator and
rig personnel. Additional commonly used dispersed muds include lime and other
cationic systems. A solids-laden dispersed system also can decrease the rate of
penetration significantly and contribute to hole erosion.
Saltwater drilling fluids
Saltwater drilling fluids often are used for shale inhibition and for drilling salt
formations. They also are known to inhibit the formation of ice-like hydrates that can
accumulate around subsea wellheads and well-control equipment, blocking lines and
impeding critical operations. Solids-free and low-solids systems can be formulated
with high-density brines, such as:
• Calcium chloride
• Calcium bromide
• Zinc bromide
• Potassium and cesium formate
Polymer drilling fluids
Polymer drilling fluids are used to drill reactive formations where the requirement for
shale inihbition is significant. Shale inhibitors frequently used are salts, glycols and
amines, all of which are incompatible with the use of bentonite. These systems
typically derive their viscosity profile from polymers such as xanthan gum and fluid
loss control from starch or cellulose derivatives. Potassium chloride is an inexpensive
and highly effective shale inhibitor which is widely used as the base brine for
polymer drilling fluids in many parts of the world. Glycol and amine-based inhibitors
can be added to further enhance the inhibitive properties of these fluids.
Drill-in fluids
Drilling into a pay zone with a conventional fluid can introduce a host of previously
undefined risks, all of which diminish reservoir connectivity with the wellbore or
reduce formation permeability. This is particularly true in horizontal wells, where the
pay zone can be exposed to the drilling fluid over a long interval. Selecting the most
suitable fluid system for drilling into the pay zone requires a thorough understanding
of the reservoir. Using data generated by lab testing on core plugs from carefully
selected pay zone cores, a reservoir-fluid-sensitivity study should be conducted to
determine the morphological and mineralogical composition of the reservoir rock.

Natural reservoir fluids should be analyzed to establish their chemical makeup. The
degree of damage that could be caused by anticipated problems can be modeled, as
can the effectiveness of possible solutions for mitigating the risks.
A drill-in fluid (DIF) is a clean fluid that is designed to cause little or no loss of the
natural permeability of the pay zone, and to provide superior hole cleaning and easy
cleanup. DIFs can be:
• Water-based
• Brine-based
• Oil-based
• Synthetic-based
In addition to being safe and economical for the application, a DIF should be
compatible with the reservoir’s native fluids to avoid causing precipitation of salts or
production of emulsions. A suitable nondamaging fluid should establish a filter cake
on the face of the formation, but should not penetrate too far into the formation pore
pattern. The fluid filtrate should inhibit or prevent swelling of reactive clay particles
within the pore throats.
Formation damage commonly is caused by:
• Pay zone invasion and plugging by fine particles
• Formation clay swelling
• Commingling of incompatible fluids
• Movement of dislodged formation pore-filling particles
• Changes in reservoir-rock wettability
• Formation of emulsions or water blocks
Once a damage mechanism has diminished the permeability of a reservoir, it seldom
is possible to restore the reservoir to its original condition.
Oil-based fluids
Oil-based systems were developed and introduced in the 1960s to help address
several drilling problems:
• Formation clays that react, swell, or slough after exposure to WBFs
• Increasing downhole temperatures
• Contaminants
• Stuck pipe and torque and drag
Oil-based fluids (OBFs) in use today are formulated with diesel, mineral oil, or low-

toxicity linear olefins and paraffins. The olefins and paraffins are often referred to as
"synthetics" although some are derived from distillation of crude oil and some are
chemically synthesised from smaller molecules. The electrical stability of the internal
brine or water phase is monitored to help ensure that the strength of the emulsion is
maintained at or near a predetermined value. The emulsion should be stable enough
to incorporate additional water volume if a downhole water flow is encountered.
Barite is used to increase system density, and specially-treated organophilic bentonite
is the primary viscosifier in most oil-based systems. The emulsified water phase also
contributes to fluid viscosity. Organophilic lignitic, asphaltic and polymeric materials
are added to help control HP/HT(High pressure/High temperature) fluid loss. Oil-
wetting is essential for ensuring that particulate materials remain in suspension. The
surfactants used for oil-wetting also can work as thinners. Oil-based systems usually
contain lime to maintain an elevated pH, resist adverse effects of hydrogen sulfide
(H2S) and carbon dioxide (CO2) gases, and enhance emulsion stability.
Shale inhibition is one of the key benefits of using an oil-based system. The high-
salinity water phase helps to prevent shales from hydrating, swelling, and sloughing
into the wellbore. Most conventional oil-based mud (OBM) systems are formulated
with calcium chloride brine, which appears to offer the best inhibition properties for
most shales.
The ratio of the oil percentage to the water percentage in the liquid phase of an oil-
based system is called its oil/water ratio. Oil-based systems generally function well
with an oil/water ratio in the range from 65/35 to 95/5, but the most commonly
observed range is from 70/30 to 90/10.
The discharge of whole fluid or cuttings generated with OBFs is not permitted in
most offshore-drilling areas. All such drilled cuttings and waste fluids are processed,
and shipped to shore for disposal. Whereas many land wells continue to be drilled
with diesel-based fluids, the development of synthetic-based fluids (SBFs) in the late
1980s provided new options to offshore operators who depend on the drilling
performance of oil-based systems to help hold down overall drilling costs but require
more environmentally-friendly fluids. In some areas of the world such as the North
Sea, even these fluids are prohibited for offshore discharge.
Synthetic-based drilling fluids
Synthetic-based fluids were developed out of an increasing desire to reduce the
environmental impact of offshore drilling operations, but without sacrificing the cost-
effectiveness of oil-based systems.

Like traditional OBFs, SBFs can be used to:
• Maximize rate of penetrations (ROPs)
• Increase lubricity in directional and horizontal wells
• Minimize wellbore-stability problems, such as those caused by reactive shales
Field data gathered since the early 1990s confirm that SBFs provide exceptional
drilling performance, easily equaling that of diesel- and mineral-oil-based fluids.
In many offshore areas, regulations that prohibit the discharge of cuttings drilled with
OBFs do not apply to some of the synthetic-based systems. SBFs’ cost per barrel can
be higher, but they have proved economical in many offshore applications for the
same reasons that traditional OBFs have: fast penetration rates and less mud-related
nonproductive time (NPT). SBFs that are formulated with linear alphaolefins (LAO)
and isomerized olefins (IO) exhibit the lower kinematic viscosities that are required
in response to the increasing importance of viscosity issues as operators move into
deeper waters. Early ester-based systems exhibited high kinematic viscosity, a
condition that is magnified in the cold temperatures encountered in deepwater risers.
However, a shorter-chain-length (C8), low-viscosity ester that was developed in 2000
exhibits viscosity similar to or lower than that of the other base fluids, specifically the
heavily used IO systems. Because of their high biodegradability and low toxicity,
esters are universally recognized as the best base fluid for environmental
performance.
By the end of 2001, deepwater wells were providing 59%; of the oil being produced
in the Gulf of Mexico. Until operators began drilling in these deepwater locations,
where the pore pressure/fracture gradient (PP/FG) margin is very narrow and mile-
long risers are not uncommon, the standard synthetic formulations provided
satisfactory performance. However, the issues that arose because of deepwater
drilling and changing environmental regulations prompted a closer examination of
several seemingly essential additives.
When cold temperatures are encountered, conventional SBFs might develop
undesirably high viscosities as a result of the organophilic clay and lignitic additives
in the system. The introduction of SBFs formulated with zero or minimal additions of
organophilic clay and lignitic products allowed rheological and fluid-loss properties
to be controlled through the fluid-emulsion characteristics. The performance
advantages of these systems include:
• High, flat gel strengths that break with minimal initiation pressure
• Significantly lower equivalent circulating densities (ECDs)

• Reduced mud losses while drilling, running casing, and cementing
All-oil fluids
Normally, the high-salinity water phase of an invert-emulsion fluid helps to stabilize
reactive shale and prevent swelling. However, drilling fluids that are formulated with
diesel- or synthetic-based oil and no water phase are used to drill long shale intervals
where the salinity of the formation water is highly variable. By eliminating the water
phase, the all-oil drilling fluid can preserve shale stability throughout the interval.
Pneumatic-drilling fluids
Compressed air or gas can be used in place of drilling fluid to circulate cuttings out of
the wellbore. Pneumatic fluids fall into one of three categories:
• Air or gas only
• Aerated fluid
• Foam
Pneumatic-drilling operations require specialized equipment to help ensure safe
management of the cuttings and formation fluids that return to surface, as well as
tanks, compressors, lines, and valves associated with the gas used for drilling or
aerating the drilling fluid or foam.
Except when drilling through high-pressure hydrocarbon- or fluid-laden formations
that demand a high-density fluid to prevent well-control issues, using pneumatic
fluids offers several advantages:
• Little or no formation damage
• Rapid evaluation of cuttings for the presence of hydrocarbons
• Prevention of lost circulation
• Significantly higher penetration rates in hard-rock formations
Specialty products
Drilling-fluid service companies provide a wide range of additives that are designed
to prevent or mitigate costly well-construction delays. Examples of these products
include:
• Lost-circulation materials (LCM) that help to prevent or stop downhole mud
losses into weak or depleted formations.
• Spotting fluids that help to free stuck pipe

• Lubricants for WBFs that ease torque and drag and facilitate drilling in high-
angle environments.
• Protective chemicals (e.g., scale and corrosion inhibitors, biocides, and H2S
scavengers) that prevent damage to tubulars and personnel.
Lost-circulation materials
Many types of LCM are available to address loss situations:
• Sized calcium carbonate
• Mica
• Fibrous material
• Cellophane
• Crushed walnut shells
The development of deformable graphitic materials that can continuously seal off
fractures under changing pressure conditions has allowed operators to cure some
types of losses more consistently. The application of these and similar materials to
prevent or slow down the physical destabilisation of the wellbore has proved
successful. Hydratable and rapid-set lost-circulation pills also are effective for curing
severe and total losses. Some of these fast-acting pills can be mixed and pumped with
standard rig equipment, while others require special mixing and pumping equipment.
Spotting fluids
Most spotting fluids are designed to penetrate and break up the wall cake around the
drillstring. A soak period usually is required to achieve results. Spotting fluids
typically are formulated with a base fluid and additives that can be incorporated into
the active mud system with no adverse effects after the pipe is freed and/or
circulation resumes.
Lubricants
Lubricants might contain hydrocarbon-based materials, or can be formulated
specifically for use in areas where environmental regulations prohibit the use of an
oil-based additive. Tiny glass or polymer beads also can be added to the drilling fluid
to increase lubricity. Lubricants are designed to reduce friction in metal-to-metal
contact, and to provide lubricity to the drillstring in the open hole, especially in
deviated wells, where the drillstring is likely to have continuous contact with the
wellbore.
Corrosion, inhibitors, biocides, and scavengers

Corrosion causes the majority of drillpipe loss and damages casing, mud pumps, bits,
and downhole tools. As downhole temperatures increase, corrosion also increases at a
corresponding rate, if the drillstring is not protected by chemical treatment. Abrasive
materials in the drilling fluid can accelerate corrosion by scouring away protective
films. Corrosion, typically, is caused by one or more factors that include:
• Exposure to oxygen, H2S, and/or CO2
• Bacterial activity in the drilling fluid
• High-temperature environments
• Contact with sulfur-containing materials
Drillstring coupons can be inserted between joints of drillpipe as the pipe is tripped in
the hole. When the pipe next is tripped out of the hole, the coupon can be examined
for signs of pitting and corrosion to determine whether the drillstring components are
undergoing similar damage.
H2S and CO2 frequently are present in the same formation. Scavenger and inhibitor
treatments should be designed to counteract both gases if an influx occurs because of
underbalanced drilling conditions. Maintaining a high pH helps control H2S and CO2,
and prevents bacteria from souring the drilling fluid. Bacteria also can be controlled
using a microbiocide additive.

FUNCTIONS OF DRILLING FLUIDS
Remove cuttings from well
Drilling fluid carries the rock excavated by the drill bit up to the surface. Its ability to
do so depends on cutting size, shape, and density, and speed of fluid traveling up the
well (annular velocity). These considerations are analogous to the ability of a stream
to carry sediment; large sand grains in a slow-moving stream settle to the stream bed,
while small sand grains in a fast-moving stream are carried along with the water. The
mud viscosity is another important property, as cuttings will settle to the bottom of
the well if the viscosity is too low.
Other properties include:
• Most drilling muds are thixotropic (viscosity increase during static conditions).
This characteristic keeps the cuttings suspended when the mud is not flowing
during, for example, maintenance.
• Fluids that have shear thinning and elevated viscosities are efficient for hole
cleaning.

• Higher annular velocity improves cutting transport. Transport ratio (transport
velocity / lowest annular velocity) should be at least 50%.
• High density fluids may clean hole adequately even with lower annular
velocities (by increasing the buoyancy force acting on cuttings). But may have
a negative impact if mud weight is in excess of that needed to balance the
pressure of surrounding rock (formation pressure), so mud weight is not
usually increased for hole cleaning purposes.
• Higher rotary drill-string speeds introduce a circular component to annular
flow path. This helical flow around the drill-string causes drill cuttings near the
wall, where poor hole cleaning conditions occur, to move into higher transport
regions of the annulus. Increased rotation is the one of the best methods for
increasing hole cleaning in high angle and horizontal wells.
Suspend and release cuttings
• Must suspend drill cuttings, weight materials and additives under a wide range
of conditions.
• Drill cuttings that settle can causes bridges and fill, which can cause stuck-pipe
and lost circulation.
• Weight material that settles is referred to as sag, this causes a wide variation in
the density of well fluid, this more frequently occurs in high angle and hot
wells.
• High concentrations of drill solids are detrimental to:
• Drilling efficiency (it causes increased mud weight and viscosity, which
in turn increases maintenance costs and increased dilution)
• Rate of Penetration (ROP) (increases horsepower required to circulate)
• Mud properties that are suspended must be balanced with properties in
cutting removal by solids control equipment.
• For effective solids controls, drill solids must be removed from mud on the 1st
circulation from the well. If re-circulated, cuttings break into smaller pieces
and are more difficult to remove.
• Conduct a test to compare the sand content of mud at flow line and suction pit
(to determine whether cuttings are being removed).
Control formation pressures
• If formation pressure increases, mud density should also be increased to
balance pressure and keep the wellbore stable. The most common weighting
material is barite. Unbalanced formation pressures will cause an unexpected

influx (also known as a kick) of formation fluids in the wellbore possibly
leading to a blowout from pressured formation fluids.
• Hydrostatic pressure = density of drilling fluid * true vertical depth *
acceleration of gravity. If hydrostatic pressure is greater than or equal to
formation pressure, formation fluid will not flow into the wellbore.
• Well control means no uncontrollable flow of formation fluids into the
wellbore.
• Hydrostatic pressure also controls the stresses caused by tectonic forces, these
may make wellbores unstable even when formation fluid pressure is balanced.
• If formation pressure is subnormal, air, gas, mist, stiff foam, or low density
mud (oil base) can be used.
• In practice, mud density should be limited to the minimum necessary for well
control and wellbore stability. If too great it may fracture the formation.
Seal permeable formations
• Mud column pressure must exceed formation pressure, in this condition mud
filtrate invades the formation, and a filter cake of mud is deposited on the
wellbore wall.
• Mud is designed to deposit thin, low permeability filter cake to limit the
invasion.
• Problems occur if a thick filter cake is formed; tight hole conditions, poor log
quality, stuck pipe, lost circulation and formation damage.
• In highly permeable formations with large bore throats, whole mud may invade
the formation, depending on mud solids size;
• Use bridging agents to block large opening, then mud solids can form
seal.
• For effectiveness, bridging agents must be over the half size of pore
spaces / fractures.
• Bridging agents (e.g. calcium carbonate , ground cellulose).
• Depending on the mud system in use, a number of additives can improve the
filter cake (e.g. bentonite, natural & synthetic polymer, asphalt and gilsonite).
Maintain wellbore stability
• Chemical composition and mud properties must combine to provide a stable
wellbore. Weight of the mud must be within the necessary range to balance the
mechanical forces.
• Wellbore instability = sloughing formations, which can cause tight hole

conditions, bridges and fill on trips (same symptoms indicate hole cleaning
problems).
• Wellbore stability = hole maintains size and cylindrical shape.
• If the hole is enlarged, it becomes weak and difficult to stabilize, resulting in
problems such as low annular velocities, poor hole cleaning, solids loading and
poor formation evaluation
• In sand and sandstones formations, hole enlargement can be accomplished by
mechanical actions (hydraulic forces & nozzles velocities). Formation damage
is reduced by conservative hydraulics system. A good quality filter cake
containing bentonite is known to limit bore hole enlargement.
• In shales, mud weight is usually sufficient to balance formation stress, as these
wells are usually stable. With water base mud, chemical differences can cause
interactions between mud & shale that lead to softening of the native rock.
Highly fractured, dry, brittle shales can be extremely unstable (leading to
mechanical problems).
• Various chemical inhibitors can control mud / shale interactions (calcium,
potassium, salt, polymers, asphalt, glycols and oil – best for water sensitive
formations)
• Oil (and synthetic oil) based drilling fluids are used to drill most water
sensitive shales in areas with difficult drilling conditions.
• To add inhibition, emulsified brine phase (calcium chloride) drilling fluids are
used to reduce water activity and creates osmotic forces to prevent adsorption
of water by shales .
Minimizing formation damage
• Skin damage or any reduction in natural formation porosity and permeability
(washout) constitutes formation damage
• skin damage is the accumulation of residuals on the perforations and that
causes a pressure drop through them .
• Most common damage;
• Mud or drill solids invade the formation matrix, reducing porosity and
causing skin effect
• Swelling of formation clays within the reservoir, reduced permeability
• Precipitation of solids due to mixing of mud filtrate and formations
fluids resulting in the precipitation of insoluble salts
• Mud filtrate and formation fluids form an emulsion, reducing reservoir
porosity

• Specially designed drill-in fluids or workover and completion fluids, minimize
formation damage.
Cool, lubricate, and support the bit and drilling assembly
• Heat is generated from mechanical and hydraulic forces at the bit and when the
drill string rotates and rubs against casing and wellbore.
• Cool and transfer heat away from source and lower to temperature than bottom
hole.
• If not, the bit, drill string and mud motors would fail more rapidly.
• Lubrication based on the coefficient of friction. Oil- and synthetic-based mud
generally lubricate better than water-based mud (but the latter can be improved
by the addition of lubricants).
• Amount of lubrication provided by drilling fluid depends on type & quantity of
drill solids and weight materials + chemical composition of system.
• Poor lubrication causes high torque and drag, heat checking of the drill string,
but these problems are also caused by key seating, poor hole cleaning and
incorrect bottom hole assemblies design.
• Drilling fluids also support portion of drill-string or casing through buoyancy.
Suspend in drilling fluid, buoyed by force equal to weight (or density) of mud,
so reducing hook load at derrick.
• Weight that derrick can support limited by mechanical capacity, increase depth
so weight of drill-string and casing increase.
• When running long, heavy string or casing, buoyancy possible to run casing
strings whose weight exceed a rig's hook load capacity.
Transmit hydraulic energy to tools and bit
• Hydraulic energy provides power to mud motor for bit rotation and for MWD
(measurement while drilling) and LWD (logging while drilling) tools.
Hydraulic programs base on bit nozzles sizing for available mud pump
horsepower to optimize jet impact at bottom well.
• Limited to:
• Pump horsepower
• Pressure loss inside drillstring
• Maximum allowable surface pressure
• Optimum flow rate
• Drill string pressure loses higher in fluids higher densities, plastic
viscosities and solids.

• Low solids, shear thinning drilling fluids such as polymer fluids, more efficient
in transmit hydraulic energy.
• Depth can be extended by controlling mud properties.
• Transfer information from MWD & LWD to surface by pressure pulse.
Ensure adequate formation evaluation
• Chemical and physical mud properties and wellbore conditions after drilling
affect formation evaluation.
• Mud loggers examine cuttings for mineral composition, visual sign of
hydrocarbons and recorded mud logs of lithology, ROP, gas detection or
geological parameters.
• Wireline logging measure – electrical, sonic, nuclear and magnetic resonance.
• Potential productive zone are isolated and performed formation testing and drill
stem testing.
• Mud helps not to disperse of cuttings and also improve cutting transport for
mud loggers determine the depth of the cuttings originated.
• Oil-based mud, lubricants, asphalts will mask hydrocarbon indications.
• So mud for drilling core selected base on type of evaluation to be performed
(many coring operations specify a blend mud with minimum of additives).
Control corrosion (in acceptable level)
• Drill-string and casing in continuous contact with drilling fluid may cause a
form of corrosion .
• Dissolved gases (oxygen, carbon dioxide, hydrogen sulphide ) cause serious
corrosion problems;
• Cause rapid, catastrophic failure
• May be deadly to humans after a short period of time
• Low pH (acidic) aggravates corrosion, so use corrosion coupons to monitor
corrosion type, rates and to tell correct chemical inhibitor is used in correct
amount.
• Mud aeration, foaming and other O2 trapped conditions cause corrosion
damage in short period time.
• When drilling in high H2S, elevated the pH fluids + sulfide scavenging
chemical (zinc).
Facilitate cementing and completion
• Cementing is critical to effective zone and well completion.

• During casing run, mud must remain fluid and minimize pressure surges so
fracture induced lost circulation does not occur.
• Mud should have thin, slick filter cake, wellbore with no cuttings, cavings or
bridges.
• To cement and completion operation properly, mud displace by flushes and
cement.For effectiveness;
• Hole near gauges
• Mud low viscosity
• Mud non progressive gel strength
Minimize impact on environment
Mud is, in varying degrees, toxic. It is also difficult and expensive to dispose of it in
an environmentally friendly manner. A vanity fair article described the conditions at
Lago Agrio, a large oil field in Ecuador where drillers were effectively unregulated
COMPOSITION OF DRILLING FLUIDS
• Water-based drilling mud most commonly consists of bentonite clay (gel) with
additives such as barium sulphate (barite), calcium carbonate (chalk) or
hemetite.
• Various thickeners are used to influence the viscosity of the fluid, e.g. xanthan
gum, guar gum, glycol, carboxymethylcellulose, polyanionic cellulose (PAC),
or starch. In turn, deflocculants are used to reduce viscosity of clay-based
muds; anionic polyelectrolye (e.g. acrylates,polyphosphate,lignosulphonates
(Lig) or tannic acid derivates such as quebracho) are frequently used
• Red mud was the name for a - quebracho based mixture, named after the
color of the red tannic acid salts; it was commonly used in 1940s to 1950s, then
was made obsolete when lignosulfonates became available.
• A weighting agent such as barite is added to increase the overall density of the
drilling fluid so that sufficient bottom hole pressure can be maintained thereby
preventing an unwanted (and often dangerous) influx of formation fluids.
Basic Classification of Additives used in drilling fluid

Typically, a particular compound of drilling fluid or drilling mud would have myriads
of additives in them. This is quite unlike foam or air based drilling fluids that may not
be containing too many drilling fluids because most of these additives are either
available in solid or in liquid form. Therefore, they would not mix well with foam
based or an air based substance. Some of the significant compounds that work well as
additives have been detailed out below:
1. Weighting Compounds —Primarily, weighting materials or compounds are
used for increasing the mud density. Common examples would be barium
sulfate or barite. The density of the mud needs to be increased because it is
important to equilibrate the wellbore pressure and the formation pressure,
especially when the challenge is to drill through zones that are heavily
pressurized. In case of oil based drilling fluids or mud, Hematite which is an
iron compound is also considered to be an excellent weighting additive.
2. Corrosion Inhibitors —Since drilling would involve the installation and
usage of several metallic components, it would be essential to introduce
corrosion inhibitors through the drilling fluids that are being used for the
process. Considering that the metallic parts would encounter a slew of acidic
compounds during the course of the drilling process, corrosion maybe rampant.
Popular anti corrosives that are used as additives would include aluminum
bisulfate, iron oxides, protect- pipes of zinc chromate, zinc carbonate and so
on.
3. Dispersants —During the drilling process, it is essential to introduce agents
that can help in breaking up solid clusters in smaller particles that can be easily
carried by the drilling fluid from one place to the another, without causing any
unnecessary obstructions. This is specifically what dispersants do. Examples
include iron lignosulfonates.
4. Flocculants —Flocculants are nothing but acrylic polymer compounds that
help in the cluster formation of suspended particles, so that they can be
grouped together and removed from the resultant fluid when they reach the
surface.
5. Surfactants —Surfactants are nothing but compounds like soaps and fatty
acids that would emulsify and defoam the drilling mud or fluid.
6. Biocides —The drilling mud or fluid compound would be a fertile ground of
breeding bacteria that could lead to complete souring of the compound. In
order to reduce the sourness and thwart the growth of bacteria, biocides would

have to be introduced in the form of cholorophenols, formaldehydes or organic
amines.
7. Reducers of Fluid Loss — Drilling may often involve working with highly
permeable formations that might also be under pressurized. Typically, one has
to introduce fluid loss reducing compounds like organic polymers and starches.
8. Fluid Viscosifiers/Rheology modifiers — Viscosifiers help in controlling the
rhelogy of the fluid.
SOME EXAMPLES OF ADDITIVES ARE:
(water based mud additives)
• viscisifiers and filtration loss reducers:bentonite, attapulgite clays, asbestos, X-
C polymer, carboxyl methylcellulose(cmc), poly anionic cellulose(PAC), Pre-
gelatinised starch
• weighting material: calcium carbonate(sp. gr.-5) barytes(sp. gr-4.25),
hematite(sp. gr-5), galena(sp. gr-6.7 to 7)
• salts:NaCl, Kcl, CaCl2
• thinners:chrome lignosulphonate, cutch, modified tannins
• chemicals for ph control: caustic soda(NaOH), Lime(Ca(OH)2), soda ash
(Na2CO3), Sodium bicarbonate(NaHCO3)
• other chemicals:PHPA,sulphonated asphalt, drilling detergent, EP, lube, Piplex
Table1
Composition of a typical bentonite gel water based mud ,density 1300kg/m3.
Components added to 1 barrel of water : (bbl=barrel, ppb=pounds per barrel); CMC :
(carboxymethylcellulose)
component quantity Mass(kg) Volume(L) %mass %volume
Water 1 bbl 159 1588,99 65,33 84,92
Bentonite 20 ppb 9,1 9,07 3,73 4,85
Caustic soda 0,5 ppb 0,23 0,22 0,9 0,12
Soda ash 0,5 ppb 0,23 0,10 0,9 0,5
High
viscosity cmc
1,5 ppb 0,68 0,47 0,28 0,25
Low viscosity
cmc
3,5 ppb 1,59 1,09 0,65 0,58

barite 160 ppb 72,58 17,28 29,82 9,23
Table 2
Composition of a typical oil based mud density 1318 kg/m3 , salinity 22.5%, oil to
water ratio 65:35. components combine to give a total volume of one barrel.(bbl:
barrel; ppb:pounds per barrel; gpb: gallons per barrel)
quantity Mass(kg) volume(L) %mass %volume
Base fluid 0,5 bbl 64,63 83,31 30,37 52,40
viscosifier 5 ppb 2,26 1,40 1,08 0,88
Emulsifier
1
0,8 ppb 2,89 3,02 1,38 1,90
Emulsifier
2
0,4 ppb 1,49 1,51 0,71 0,95
Lime 5 ppb 2,26 1,00 1,08 0,63
water 0,30 ppb 47,15 47,22 22,50 29,70
Clca2 30,2 ppb 13,70 3,35 6,54 2,11
barite 167,9 ppb 76,15 18,16 36,34 11,42
PROPERTIES OF DRILLING FLUIDS
A) DENSITY (SPECIFIC GRAVITY)
Density is defined as weight per unit volume. It is expressed either in ppg (lbs
gallons) or pound per cubic feet (lb/ft3) OR kg/M^3 or gm/cm^3 or compared to the
weight of an equal volume of water as specific gravity. Density is measured with a
mud balance. One of the main functions of drilling fluid is to confine formation fluids
to their native formations or beds
B)GEL STRENGHTH

The gel strength is the shear stress of drilling mud that is measured at low shear rate
after the drilling mud is static for a certain period of time. The gel strength is one of
the important drilling fluid properties because it demonstrates the ability of the
drilling mud to suspend drill solid and weighting material when circulation is ceased.
We use the 3-rpm reading which will be recorded after stirring the drilling fluid at
600 rpm from a rheometer. Normally, the first reading is noted after the mud is in a
static condition for 10 second. The second reading and the third reading will be 10
minuets and 30 minutes, respectively. You may wonder why we need to record the 3-
rpm reading after 30 minutes.
The reason is that the 30 minute-reading will tell us whether the mud will greatly
form the gel during an extensive static period or not. If the mud has the high gel
strength, it will create high pump pressure in order to break circulation after the mud
is static for long time. Furthermore, increasing in a trend of 30-minute gel strength
indicates a build up of ultra fine solid. Therefore, the mud must be treated by adding
chemicals or diluting with fresh base fluid.
C)VISCOSITY
It is defined as the internal resistance to fluid flow. There are two types of viscosity
which are funnel viscosity and plastic viscosity
FUNNEL VISCOSITY
It is the time in seconds for one quart of mud to flow through a marsh funnel which
has a capacity of 946 cubic centimeter. A quart of water exits the funnel in 26 sec.
This is not a true viscosity, but serves as a quantitative measure of how thick the mud
sample is. The funnel viscosity is useful only for relative comparisons
PLASTIC VISCOSITY (PV):
Plastic Viscosity (PV) is the resistance of fluid to flow. In the field, we can get the PV
from a viscometer. Typically, the viscometer is utilized to measure shear rates at 600,
300, 200, 100, 6, and 3 revolutions per minute (rpm).
We can calculate the plastic viscosity from the difference between the 600 and 300
rpm reading.
The formula looks like this:
Plastic Viscosity (PV) = Reading at 600 rpm – Reading at 300 rpm
The unit of PV is Centi Poise (CP).

Summer Training Report on Crude Oil and Drilling Fluids

Summer Training Report on Crude Oil and Drilling Fluids

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Summer Training Report on Crude Oil and Drilling Fluids