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I sincerely thank Oil and Natural Gas Corporation (ONGC) for giving us a valuable opportunity

to work with them. This project report is dedicated to all the people, whom we met, took

guidance and gained knowledge from. We are indebted and whole heartedly thankful for the

assistance r e c e i v e d f r o m various individuals in making this training period a wonderful

experience. I w o u l d l i k e t o e x p r e s s m y g r a t i t u d e t o m y c o l l e g e “Pandit

Deendayal Petroleum University” for giving me the golden opportunity of summer

internship so as to learn the various aspects on practical basis. I am highly thankful and

deeply indebted to Mr. Mohinder Verma Chief Engineer (P) and Mr. B.Seshagiri,

Superintendent Engineer (P), who incessantly guided me till last word of this project report

and provided an estimable guidance.

I am thankful to Shri. Anil Johari, ED, Asset Manager, Ahmedabad Asset for providing us the

opportunity to do a project at Well Services, Ahmedabad Asset.

I would like to express our gratitude to Shri. J. J. Patel, Location Manager, Well Services -

ONGC Ahmedabad, for providing a schedule so that we were able to learn very effectively.I

would like to thank the installation managers Shri T. Bhiksham (IM), Shri V.T. Patel (IM), Shri

R.P. Saini (IM) for the useful field visits.

Very special thanks to Shri T. Bhiksham (IM) for guiding us throughout the project and sparing

his precious time for us.

Acknowledgement

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Table (2.1) Stratigraphy of Ahmedabad Basin

Table (2.2) ONGC fields

List of Tables

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Fig(2.1) Cambay Basin :Major Structural Elements

Fig(3.1) Fishing Tools

Fig(3.2) Milling Tools

Fig(3.3) Gravel Packing

Fig(3.4) Gas Coning

Fig(3.5) Water Coning

Fig(3.6a) Zone Transfer

Fig(3.6b) Zone Transfer

Fig(3.6c) Zone Transfer

List of Figures

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BHP Bottom Hole Pressure

BHT Bottom Hole Temperature

BMT Billion Metric Tonnes

CB Clear Bottom

CBM Coal Bed Methane

EOR Enhanced Oil Recovery

ESP Electric submersible pumps

GGS Group Gathering Station

GLV Gas Lift Valve

GSI Geological Survey Of India

IOR Improved Oil Recovery

IPSHEM Institute of Petroleum Safety, Health and Environment

Management

LPM Litres Per Minute

MMT Million Metric Tonnes

MNRE Ministry of New and Renewable Energy

NELP New Exploration Licensing Policy

O+OEG Oil plus Oil equivalent Gas

OEC ONGC Energy Centre

OGIP Original Gas In Place

ONGC Oil and Natural Gas Co-orporation

OOIP Original Oil In Place

PAA Poly acryl amide

PSU Public Sector Unit

PV Photo-Voltaic

SEC Solar Energy Centre

SRP Sucker Rod Pump

WRG Wireline Rentry Guide

Abbreviations

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CHAPTER I INTRODUCTION

Theory of any subject is important but without its practical knowledge it becomes useless,

particularly for technical students. A technical student cannot become a good engineer without

practical understanding of their branch. Hence summer training provides an opportunity for to

get a better understanding of the working environment. The training helps to understand the

basic concept of the petroleum industry by interacting with experts in industry

Aims & objectives of study :-

– To understand type of jobs in well services.

– To understand the different work over jobs carried out in ONGC.

– To understand well control process, and to analyze the practices carried out in ONGC.

– To understand stimulation jobs, and to analyze the practices carried out in ONGC.

– To know the present scenario and probable future practicability of the different work over

practices.

Being future petroleum engineer it will help in acquiring skills, factual knowledge and

techniques required for doing a better and safe job in the field.

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CHAPTER II (A) AN OVERVIEW ON ONGC

VISION :

"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."

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.

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Dominant Indian Leadership

Retain dominant position in Indian petroleum sector and enhance India's energy availability."

ONGC is bestowed with the honour of "Maharatna" status by Govt. of India. The Govt. has

announced for providing enhanced function and financial autonomy for the Maharatna

companies to enable them to enhance their competitive edge and attain accelerated growth.

Adding value for half a century

ONGC stepped in to its fifty sixth year on 14th August, 2011.Five Decades of ONGC, nearly

coincides with the second half of the 20th

century, The most inventive 100 years that humanity

has seen.

The Journey of ONGC, over these years, has also been a tale of conviction, courage and

commitment, which carried a new independent nation away from efforts to recognize it

economically; a conviction which locked horns with the over-whelming opinion that India has no

trace of oil reserves(except the few in the north-east). The western opinion was so firm , it is

said, a western oil expert challenged that if India can produce oil, he was ready to drink it!

Oil and Gas business is different from other deterministic endeavors. In a broad sense, it

demands exploration and development of the Earth's sub-surface-a region where humankind does

not lives, but feels compelled to explore. But ONGC, led by its visionary leaders, took on the

challenge, to understand the unknown, to produce petroleum, to meet the growing energy of the

developing nation, to strengthen India's economic foundation.

ONGC has established 6 billion tonnes of In-place hydrocarbon reserves with more than 600

discoveries of Oil and gas; in fact, 5 of the producing basins have been discovered by ONGC.

Ultimate reserves are 2.1 Billion Metric Tonnes (BMT) of Oil plus Oil equivalent Gas (O+OEG).

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It has cumulatively produced 660 million metric tonnes (MMT) of crude and 350 Billion Cubic

Meters (BCM) of Natural Gas, from 115 fields.

Even in the New Exploration Licensing (NELP), ushering in competitive regime In the Indian

petroleum industry, ONGC, belying speculation, has established its competitive edge, by

bagging 51 out of 90 blocks, awarded in the four rounds of competitive bidding of NELP so far (

14 out of 24 blocks in the fourth round). In the two CBM rounds also, ONGC has won 7 out of

the 13 blocks awarded (5 out of 8 blocks in CBM- II).The journey has been long and difficult,

but rewarding. From a small petroleum division within the Geological Survey of India (GS I)-to

Asia 's Best Oil & Gas Company, from a small hired laboratory at Nazz building in Dehradun -

to having one of the few virtual reality centers of the world.

Meeting the growing challenge

Compared to the global average per-capita consumption of 927 kg of hydrocarbon, an Indian

consumes only 113 kg (12 percent of world average), which is bound to grow. To meet these

challenge of growing demand vis-à-vis limited reserves (India consumes as much Natural Gas as

China, though it's Reserve are half of China's).ONGC has set for itself, ambitious strategic

objectives in its core E&P business.Technology has been harnessed for exploring new frontiers,

improving the exploration success ratio, augmenting production rate by efforts like

redevelopment, and minimizing waste like flaring.

Moving ahead, ONGC is entering LNG (regasification), Petrochemicals, Power generation as

well as crude & Gas shipping, to have the presence along the entire Hydrocarbon value-chain.

New business-

After successful commissioning of a 50 MW wind farm in Gujarat, ONGC is setting up 102 MW

wind farm in Rajasthan. Further, feasibility of setting up a 10 MW grid-connected Solar Photo

Voltaic (PV) project is being studied. ONGC Energy Centre (OEC) successfully installed the

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three state-of-the-art Solar Thermal Engines at the Solar Energy Centre (SEC), Ministry of New

and Renewable Energy (MNRE) campus at Gurgaon and their performance is under evaluation.

OEC is pursing the following projects:

• Thermo-Chemical Reactor for Hydrogen generation

• Bio Conversion of Coal to methane

• Exploration and exploitation of Uranium Reserves globally

• LED Project

Achievements and awards:-

– ONGC ranked as No.1 E&P Company in World.

– ONGC ranked at 172nd position in Forbes Global 2000 list of the world's biggest

companies for 2011

– Financial Express ranks ONGC as the most valuable PSU

– Business World ranks ONGC as the ‗Most Respected PSU Company‘

– ONGC recognized as the ‗Best Employer to Work For‘ among PSUs

– ONGC Academy gets ISO-9001:2008 accreditation

AWARDS

– Petrofed Oil & Gas Industry Awards 2009 & 2010 to ONGC

– ONGC bags FE-EVI Green Business Leadership Award

– ONGC won the NIPM Best HR Practices Silver Trophy

– ONGC receives the 'Shine.Com HR Leadership Award' for its CSR activities

– ONGC bagged Certificate for excellence in Corporate Governance

– ONGC gets PCRA award for Best Overall performance for energy conservation in

upstream sector

– ONGC bags Safety Innovation Award instituted by IEI

– ONGC bestowed with 'The India Shining Star CSR Award‘

– ONGC bestowed with NDTV 'Greenies Eco Award‘

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– Golden Peacock Award to ONGC

– ICC Sustainability Vision 2011 Award to ONGC ONGC bagged awards for Best

Financial Performance and Corporate Governance

– Golden Peacock Award for Climate Security-10

A Model Corporate Citizen

ONGC is playing an important role in strengthening the fabric of society. This flagship Company

in India's corporate world has a finely tuned sense of moral responsibility towards the

community of people. Local population is the one, which is benefited as a result of the ONGC

operations in the

region. It generates employment & business opportunities, which in turn improves the overall

economy of the region and the living standards of the community.

ONGC operations provide the necessary boost required for the industrial growth of the region.

The requirement of the physical inputs for ONGC's

operations results in setting of ancillary industries and vendors network, generating a lot of

economic potential.

Oil and gas production ushers an era of growth, many core sector industries like power, fertilizer

and transport, thrive as a natural consequence of the oil and gas availability. Apart from this,

grants in-aid help in building schools and hospitals, villages are adopted and several health and

community welfare programs are organized.

Respect & dignity are the key values that underline the relationship that ONGC has with its

human assets. Conscious about its responsibility for the society ONGC has evolved guidelines

for Socio- Economic Development programs in areas around its operations all over the country

in the fields including:

– Education

– Health Care and Family Welfare

– Community Development

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– Promotion of Sports and Culture

– Calamity Relief etc.

– Development of Infrastructure Facilities

– Development of the Socially & Economically Weaker Sections of Society

Safety Conscious:

Everyone who works at ONGC is responsible for protecting the environment, health and safety

of our people and communities worldwide. Its commitment to SHE (safety, health and

environment) performance is an integral part of business, and achieving cost effective solution is

essential for long term success.

The dedication to the causes of environment and safety in ONGC is amply demonstrated by the

fact that a separate institute named ―Institute of Petroleum Safety, Health and Environment

Management (IPSHEM)‖ had been set up way back in 1989 to deal with these issues.

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HISTORY AT A GLANCE

August 1956 Formation of Oil and Natural Gas Commission

April 1957 First well drilled in Jawalamukhi

September 1958 Discovery of oil in Lunej at Cambay

May 1960 Discovery of major oilfield in Ankleshwar

1962 Started Offshore exploration

1965 Formation of Hydrocarbons India Ltd.-OVL precursor

March 1970 First foray into offshore drilling at Aliabet

First offshore drilling rig Sagar Samrat ordered

November 1973 ONGC got a contract to work in Iraq

February 1974 Bombay High discovered

1976 Giant gas field Bassein discovered

March 1984 Giant onshore field Gandhar discovered

1988 HIL rechristened as ONGC Videsh Limited

1992 5 producing fields of ONGC handed over to

multinational companies

June 1993 ONGC incorporated as a company

1998 Phased dismantling of Administered Price Mechanism (APM)

starts

August 2001 Corporate Rejuvenation Campaign (CRC) rolls

January 2003 First commercial production in Vietnam

March 2003 OVL acquired 25% participating Interest in Greater Nile Oil

Project

ONGC acquired stake in Mangalore Refinery & Petrochemicals

August 2003 Launching of Deepwater Exploration Campaign Sagar Samriddhi

March 2004 10% equity of ONGC disinvested ; offer oversubscribed in 11

minutes

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CHAPTER II (B) BACKGROUND OF AHMEDABAD ASSET

ONGC had found out four major basins in Gujarat. They are Ahmedabad, Mehsana, Ankleshwar

and Cambay. There are 2,216 wells in 21 fields are in Ahmedabad asset. ONGC Ahmedabad

Asset is producing since 1961. The first well KALOL#1 was put on 18/04/1961. This Asset has

spread over an area of 6200 sq. Km, Covering 4 districts.

Ahmedabad

Gandhinagar

Kheda

Mehsana.

Oil Industry Safety Directorate (OISD) has selected Ahmedabad Asset and MRPL for the year

2006-07(as number one in Group-4 category (Oil & Gas Assets) and Second in Group-1

Refinery category respectively.

MAIN OPERATING ACTIVITIES

1. Exploration and Exploitation of hydrocarbon to meet committed target of production and

supply.

2. Reservoir Health Management to Optimize Recovery.

3. Well Servicing and minimizing non flowing wells and improving productivity.

4. Health, Safety and Environment Management.

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GEOLOGY AND STRATIGRAPHY OF AHMEDABAD BASIN

The Cambay Basin in the Northwest part of the Indian Peninsula is a commercial petroleum

producer from Tertiary sediments resting on the basic lava flows known as Deccan Traps. The

basin is further subdivided into four namely :

Ahmedabad Basin.

Mehsana Basin.

Cambay Basin.

Gandhar/ Ankleshvar Basin.

Cretaceous sediments which underlie the Deccan Traps are exposed in the eastern and western

margins of the basin and are also encountered in the subsurface. The Cambay basin, which is a

rift sag tertiary basin includes six tectonic blocks, the Patan, Mehsana, Ahmedabad, Tarapur,

Broach, and Narmada, separated by faults aligned transverse to the general north-south axis of

the rift.

The basin has three main depression trends along the rift axis: the eastern, the axial, and the

western. In the Cambay basin, oil/gas reservoirs and potential source rocks occur mainly in the

Paleocene–middle Eocene sequences of the Olpad, Cambay Shale, and Kalol formations.

Although the Cambay basin has been well explored, the oil source genetic relationship is not

well understood because of the multiplicity of depressions, source rocks, and reservoirs. The

Cambay basin oils are presumed to be sourced by the Cambay Shale Formation sedimentary

rocks deposited in a highly reducing marine environment.

The paleogeographic reconstruction of the Cambay Basin suggests that the northern part,

possessing a thin cover of Cretaceous sediments, has meagre petroleum prospects. However, the

southern part of the basin, where more than 1,000 m of Cretaceous sediments were deposited by

two independent drainage systems, may be more lucrative. Suitable facies for generation and

accumulation of petroleum are expected in this part of the basin. The subsurface information

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gathered during exploration for oil and gas in the Cambay basin shows it as a deep graven with 5

km or more of Tertiary and Quaternary sediments resting on the Deccan Trap floor.

The Tarapur Shale Formation, deposited by the end of the early Oligocene (approximately 29

Ma), is the regional seal and overlies the youngest reservoir (the Kalol pays of the Kalol

Formation) in the Cambay basin. Overburden rocks for the Kalol pays were deposited since the

Miocene, after a hiatus of about 4 m.y. following the Tarapur Shale‘s deposition.

THE FIGURE GIVEN ON THE NEXT PAGE SHOWS THE MAJOR STRUCTURAL

ELEMENTS OF CAMBAY BASIN :

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FIG(2.1) CAMBAY BASIN : MAJOR STRUCTURAL ELEMENTS

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TABLE (2.1) STRATIGRAPHY OF AHMEDABAD BASIN.

AGE FORMATION LITHOLOGY

UPPER MIOCENE POST KAND PREDOMINANT SAND

GRANULES, BROKEN SHELL

WITH ALTERNATION OF

MINOR CLAY

MIDDLE MIOCENE KAND DOMINANTLY CLAY/SHALE

WITH ALTERNATION OF

SANDSTONE AND SILTSTONE

LOWER MIOCENE

TO EARLY

OLIGOCENE

BABAGURU SAND AND SHALE

ALTERNATION

OLYGOCENE TO

LOWER MIOCENE

TARKESHVAR DOMINANTLY CLAYSTONE

ALTERNATION WITH SAND

EARLY

OLIGOCENE TO

UPPER EOCENE

KALOL ALTERATION OF THICK SAND

AND SHALE FOSSILIFEROUS

MIDDLE TO

LOWER EOCENE

CAMBAY SHALE SHALE

DECCAN

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KAND FORMATION

This consists of clay, kankar and minor sands. At places thin intra formational conglomerates

are present in the sands. This formation is covered by 5-7 m thick lotoritic sand/gavel bed. Rich

miocene fauna has been recovered from this formation. The gross thickness of this unit varies

from 35 to 85 m.

BABAGURU FORMATION

This formation is composed predominantly of sands with subordinate clay and clay stone beds

and occasional shale‘s. The formation is 125 to 270m thick and contains poor faunal assemblage

of Miocene age. This formation is mainly used for effluent disposal.

TARKESHWAR FORMATION

This formation rest discomformably over dadhar unit and it comprises mottles red and gry

claystones, grey shales and poorly sorted sandstones. At places interformational conglomerates

are present in the sandstones. Its thickness over the field is 230 to 400 m and is generally barren

and corresponds to Oligocene to lower Miocene age. Tarkeswar shale mainly act as cap rock.

KALOL FORMATION

Kalol formation overlies cambay shale group and ranges in age from mid Eocene to upper

Eocene. It consists of thick sequence of sands and shales. it also consists of interbedded sand

stone and bio clastic limestones .the bio clastic lime stone is fairly persistent over the field and is

an excellent electric log marker it also serves as very god seismic reflector. Main producer of oil

in Ahmedabad asset is kalol formation. Oil is also obtained from cambay shell and chattral in

some cases.

CAMBAY SHALE

This is composed of gray shales with thin alternative of silty and carbonaceous shale

occasionally sidestic. Barring some lanticular bodies, the sequence does not contain coarse

clastics. Thickness of this unit varies from 130m to 250m., over the field. It is poor to moderately

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fossiliferrous and ranges in age from lower Eocene to mideocene. In the upper part of this unit,

there occurs a persistant resistive band popularly known as Nose Marker. It carries a high

correlative value.

OPERATING FIELDS

Total fields - 29

Fields with ONGC - 20

Table (2.2) ONGC fields:-

AREA-I AREA-II AREA-III AREA-IV

KALOL NAWAGAM JHALORA LIMBODRA

WADU AHMEDABAD SANAND GAMIJ

PALIYAD NANDEJ SOUTH_KADI HALISA

MOTERA WASNA VIRAJ

WAMAJ SADRA SOUTH_VIRAJ

ASMALI

ISOLATED

RESOURCES FACILITIES

• DRILLING RIGS : 8

• WORK-OVER RIGS : 12

– ONGC : 7

– HIRED : 5

• INSTALLATIONS : 63

Central Tank Farms : 3 (Kalol, N‘gam, S. Kadi)

Group Gathering Stations : 28

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Gas Collection Station : 1 (Kalol)

Gas Compression Plants : 3 (Kalol, N‘gam, Sanand)

Early Production Systems : 08

Water Injection Plants : 12 (mainly part of GGS)

Desalter Plant, Nawagam : 1

( Before Despatch to Refinery)

RESOURCES WELLS:

TOTAL WELLS DRILLED : 2110

EXPLORATORY WELLS : 784

DEVELOPMENT WELLS : 1326

• OIL WELLS : 1303

• GAS WELLS : 45

• INJ WELLS : 277

• EFF. DISP. WELLS : 67

• ABND : 325

• OTHERS : 93

CONTRIBUTION TO TOTAL PRODUCTION

• SELF-FLOWING WELLS : 13 %

• WELLS ON ARTIFICIAL LIFT : 87 %

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CHAPTER III WORKOVER

The profitability of a well as an investment venture depends on how long it is on stream and on

how much it produces. Its lifetime and output are naturally due to the reservoir's initial

characteristics.

However, they are also dependent on keeping the well maintained in good working order and

adapting completion properly to the constantly varying conditions prevailing in the reservoir and

around the wellbore.

Well servicing covers all of the operations that can be performed on the well itself with either of

two objectives:

• finding out how the status of the well itself or the reservoir is evolving

• maintaining or adapting the well to keep the best possible operating conditions.

By "the well itself' we mean the connection between the borehole and the pay zone, its

immediate vicinity and everything that is located in the well up to and including the wellhead.

In addition, it should be remembered that the operations that can or must be done over the field's

lifetime to keep the wells in good working order and profitable are largely influenced by how

well the completion system was chosen.

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MAIN TYPES OF OPERATIONS

The operations that may have to be carried out on a well are numerous and can be broken down

into:

– measurements,

– maintenance and

– workover.

Measurements may involve the

– status of equipment,

– the quality of the pay zone-borehole connection or

– the status of the reservoir in the vicinity of the well.

Maintenance and workover operations mainly affect equipment or

the pay zone-borehole connection.

Maintenance is the relatively simple operations that can be done with the well still producing,i.e.

under pressure, with lightweight means such as wireline units.

In contrast, workover operations entail using heavier means. They may sometimes be caried out

with well under pressure (using a coiled tubing or a snubbing unit for example) but usually

require the well to be "killed" (i.e. placing a control fluid in the well whose hydrostatic pressure

is greater than the reservoir pressure).

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Servicing operations may be decided because of:

• operating considerations such as an abnormal drop in production, or prematurely worn or

obsolete equipment

• reservoir considerations such as knowing how the reservoir is evolving or how to best adapt to

its behavior

• trouble that has cropped up when operations were carried out for the above-mentioned reasons,

for example to retrieve a "fish" (any tool, piece of equipment or other item lost or accidentally

stuck in the well)

Workover operations are carried out for mainly two reasons such as :-

– Mechanical problems

– Reservoir related problems

Mechanical Problems includes

a) Repair/Replace of damaged equipment

b) Capital repairs of well

c) Replace artificial lift equipments

d) Fishing

There are also some other jobs such as:

servicing of wells

repair of cement behind casing

transfer of zones

putting well on dual completion

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removal, replacement of defective downhole equipment &

fishing operations.

removal of bottom hole deposits and perforations, cleaning

of wellbore blockage/ damages

changes of tubulars.

a) Repair/Replace Damaged Equipment

Adverse Downhole environments (e.g., erosion, chemical reactions, temperature extremes) can

damage equipment during the life of a well. The following types of equipment may require

repair:

• Tubing packers

• Gravel pack equipment

• Gas-lift mandrels and valves

• Subsurface safety valves

• Production tubing

• Electric submersible pumps (ESPs) and rod pumps

b) Capital Repairs of wells

These are the most complicated and time consuming operations. They include:

Drilling and milling of packers, bridge plugs, etc.

Detection & blocking of channeling behind casing & recompletion

Detection & repair of casing damages & recompletion

Fishing & removal of stuck tubings, packers & other downhole tools & objects and

testing of different objects (pay zones) & recompletions

c) Fishing Jobs

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Oil production is an expensive affair, hence losing equipments in the bore well increases the cost

further as the retrieval of such an equipment takes time and consequently loses time of the

production, thus other operations come to a halt such as workover operations, production

commencement until the tool {fish} is recovered. The well can become hard to control with

essential tools out of reach, increasing the risk of a blowout.

The key elements of a fishing operation include:-

Understanding of the dimension of the fish

Nature of the fish to be removed

The well bore conditions

The tools and techniques employed

Pipes, broken pipes, drill collars, bits, bit cones, dropped hand tool, stuck pipe, stuck, packers, or

other junk in the hole are called fish. Some of the tools and techniques employed for retrieval of

such fish are overshot runs, spear runs, wire line fishing etc.

WHAT IS A FISH?

The literal meaning of the fish is any down hole equipment (manometer, packer, logging tools )

which are expensive in and can be re-used in the future Operations, such as:-

Drill pipes, broken drill pipes, tubings, packers.

Logging tools such as {perforation gun and pressure setting tools}

Drill collars etc.

WHAT IS JUNK?

The simple meaning is just the smaller fish, which are not that expensive and cannot be re-used

in the future operations, such as:-

Bit cones, bearings, or other parts lost when a bit breaks.

Broken reamers or stabilizers part.

Metal fragment lost in a twist-off

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Metal fragment produced by milling the top of a fish to aid in its retrieval.

Pieces of hard, crystal or abrasive minerals such as iron pyrites.

FISHING:- Fishing may be described as to the application of special tools for retrieval of

foreign objects inside the well or any undesirable tool, equipment, or other object found in a

cased or uncased well bore that stops or retards operational progress. It can be the result of

Stuck pipe / back off operations.

Mechanical failure i.e. twist offs. (Fishing for pipe {fish}).

Any other item left in the well bore. Such as drilling bit, tooth of the drill bit etc. (fishing

for junk).

Falling of logging or scrapping tool during operation due to snapping, etc.

Fishing requires special equipments and expertise and good trained operators from fishing

equipment/ services companies are brought to the well site for many fishing jobs, particularly

ones that are expected to be troublesome. Each fishing job is unique: the tool and techniques

needed to fish a string of stuck pipe from one well may not work at another well or under other

conditions at the same well. The figure given below shows the various fishing tools used in

Petroleum Industry: Fig (3.1) Fishing Tools

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The following figure shows diagram of various milling tools used in petroleum industry:

Fig (3.2) Milling Tools

Reservoir Problems includes

a) Repair natural damage within the well

b) Zone Transfer

c) Stimulation

d) Convert well from production to injection

a) Repair Natural Damage within the Well

The term natural damage refers to damage in the reservoir rock or the fluids within it. Examples

of this natural damage include near-wellbore formation damage, sand production, excessive gas

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production, and excessive water production. These types of damage and their causes are

described in the following sections.

This can be further categorized into:

(i) Near-Wellbore Formation Damage

(ii) Sand Production

(iii) Excessive Gas Production

(iv) Excess Water Production (Coning) water shut off by various methods.

(i) Near-Wellbore Formation Damage

During the producing life of a well, the permeability of the producing formation near the

wellbore is reduced, affecting production rates. One reason for this near wellbore damage is that

components of the reservoir rock react with the well fluid. Examples of formation damage

include:

• Swelling of fine formation clays within the reservoir rock pore spaces.

• Blocked pore throats due to the migration of fine particles through the formation

toward the wellbore.

• Emulsion blockage caused by the mixing of two normally separate (immiscible)

fluids such as completion brine and crude oil. The result is a highly viscous

mixture that reduces the relative permeability of the producing formation.

• Reduction of pore throat size due to the precipitation of scale—such as calcium

carbonate or calcium sulfate—from reservoir fluids as a result of temperature or pressure

reduction.

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(ii) Sand Production

Since many oil reservoirs are located in sand beds, sand production is a naturally occurring

problem. As sand moves through the reservoir and the production string, it may plug

perforations, safety valves, tubing, and surface equipment. It may also erode Christmas tree

components. The rate of sand production can further increase due to formation breakdown, poor

production practices, poor completions, and equipment failure. A common industry technique for

controlling sand production is called gravel packing.

Sized gravel particles are packed in the annulus outside a specially designed gravel-pack screen

or slotted liner. Formation sand is then restricted from entering the completion. Gravel packing

can be done in a cased hole or an open hole.(as shown in the fig. below) Various screen types are

used for these procedures: pre-packed screens, gravel-pack screens, or simply screen assemblies.

Fig(3.3) Gravel packing

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(iii) Excessive Gas Production

In certain reservoirs, the gas associated with the oil serves as a major driving energy for oil

production. The most common types of gas drives are solution-gas drives and gas-cap drives. In

solution-gas drives, dissolved gas in the oil helps propel the oil to the surface. Eventually, some

of this gas separates out of solution and becomes trapped above the oil, forming a gas cap. The

energy in the gas cap then assists in propelling the oil. In some wells, the gas cap is already

present when the well is completed. In either case, the gas in the cap may ―cone‖ downward

toward the perforations and be produced along with the oil. Coning robs the reservoir of drive

energy and lowers production rates.

To control this separation during the early stages of production, the crew controls the pressure at

which the well fluids are produced from the reservoir. Maintaining a certain pressure on the well

helps keep the gas in solution with the oil. As the well fluids are produced, however, this

separation is more and more difficult to maintain and a remedial workover may become

necessary. This type of workover involves cementing the existing perforations and perforating a

different zone to allow oil from below the oil-gas contact point to flow to the surface.

Fig(3.4) Gas Coning

Excessive gas production in oil wells

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(iv) Excess Water Production (Coning)

In waterdrive reservoirs, the energy propelling the oil or gas comes from the expansion of vast

quantities of water. Water is generally considered incompressible, but it will compress and

expand somewhat. Considering the enormous quantities of water present in a producing

formation, this small expansion represents a significant amount of energy, which aids in driving

the fluids through the reservoir to the surface. In this type of drive, the water tends to be drawn

upward in the shape of a cone and eventually will reach the perforations (as shown in the fig.

below).

As a result, water is produced, bypassing a portion of the oil reserves. Typically the first attempt

to control coning involves reducing the production rate, but when this fails, a remedial workover

may be needed to plug the perforations below the oil water contact zone and produce from above

the watered-out zone. In many cases, however, the water eventually covers the entire producing

interval and a workover is performed to totally abandon that zone and, if possible, produce from

another zone. Fig(3.5) Water coning

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Now, if a well is producing water more than expected rate, then the possible sources of

undesirable water have to be identified. The following are the primary reasons for water

contribution:

perforation in aquifer- there are often water bearing zones near gas or oil bearing zones

and if some perforation are made into a water zone, then this may contribute to water

production.

Water coning

Encroaching oil/water contact: in a producing zone with time the water moves upward to

displace the oil towards the completed well bore.

Channel behind casing can be caused due to poor or damaged cementation behind casing.

Water may flow from one zone to another through these channels behind casing.

Water shutoff by cement squeezing: In this, the present producing interval is squeezed and

plugged off by cement. The hole is then cleared to the desired oil zone interval by drilling and

perforated. Subsequently the well is activated and re-completed.

Water shutoff by polymer: Poly acryl amide polymers are injected at the oil-water interface

zone which absorb on to the rock matrix and remain there as a ―film‖ that attracts water.

Therefore, all water than passes near this ―film‖ is slowed by attraction to the polymer. However

oil and gas is repulsed by the polymer and flow through the centre of the pores. In a sense, the

polymer film creates a frictional force for the water to overcome, but it tends to lubricate the

flow of oil and gas through the pores of formation. The procedure is as follows:

Subdue well by workover fluid and pull out production string.

Internal wire catcher trip and scrapper trip for hole cleaning.

Squeeze off the producing interval by cement

Cement drill and clear hole and scrap hole and perforate interval in oil-water interface

zone.

Pump in polymer and seal the interval by cement squeezing.

Drill cement and clear hole till the hole producing interval, scrap and perforate

Activate the well and carry out reservoir study

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Complete the well by running in completion string.

In case of bio-polymer water shut-off job, polymer is pumped into the producing interval

followed by crude oil for well bore saturation.

b) Zone Transfer

One of the most common reasons for a workover is to recomplete a well from one zone to

another. Recompletion involves changing the zone from which the hydrocarbons are produced.

Many wells are drilled to intentionally penetrate many zones, but only one zone at a time is

produced. In some wells, lower zones are produced first. When depleted, they are recompleted

(isolated) so that another zone farther up can be produced. As shown in the figure below:

Fig (3.6a) Zone Transfer

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In some cases, higher zones are produced first and then recompleted to shift production to lower

zones; as shown in the figure below:

Fig (3.6b) Zone Transfer

In some recompletions from a lower zone to a higher zone, the workover crew places a cement

plug, bridge plug, or Wireline set plug to isolate the abandoned zone. This helps ensure that the

old perforation is adequately sealed. In a recompletion from a higher to a lower zone where a

plug is not used to isolate the zone, several squeeze cement jobs may be required to isolate the

upper zones and seal the old perforations

The schematic diagram for the same is given on the next page :

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Fig (3.6c) Zone Transfer

Zonal isolation

In most wells, an extra rat hole (a space below the perforations) is drilled below the lowest

production zone. A rat hole provides clearance to run logging tools, collect produced formation

material, or allow tubing-conveyed perforating guns (TCPs) to fall below the perforations. In

some cases, bridge plugs or Wireline plugs cannot be recovered from the wellbore, so the rathole

provides a space for disposing of these plugs below the lowest-producing level where they will

not affect production.

c) Stimilation

Production in a damaged or low-producing zone can be increased by one or more techniques.

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The name of some known techniques that are used in the petroleum industry are as follow:

(i) Acid Stimulation

(ii) Hydraulic Fracturing

(iii) Steam Injection

(iv) Water Injection

(v) CO2 Injection

(i) Acid or Solvent Stimulation

Matrix acidizing is a stimulation technique involving injection of acid into the formation rock at

pressures below the level at which the rock will fracture. This technique dissolves away damage

caused by drilling, completion, and workover or well-killing fluids as well as by precipitation of

deposits from produced water. It is also used to etch new channels or pathways for hydrocarbons

near the wellbore.

Hydrochloric acid (HCl) is used to treat limestone, dolomite, and other carbonate type rocks,

while hydrofluoric acid (HFl) is used in sandstone reservoirs. A mixture of HCl and HFl called

―mud acid‖ is used to dissolve damaging clay deposits. Damage from waxes or asphaltenes in

produced oil can be treated with organic solvents.

(ii) Hydraulic Fracturing

In some wells it is necessary to intentionally fracture a formation to provide a deeper flow path

for oil and gas into the wellbore. Fracture (―frac‖) fluids include oil, water, acid, emulsions,

foams, or combinations of these. The frac fluids are pumped down hole under high pressure at a

high rate of flow to fracture the formation. These frac fluids include finely grained particles

called prop pants. Proppants are made from sand particles of a controlled size or sintered bauxite

(aluminum ore). The proppant remains in the fracture to help hold the fracture open after pump

pressure is bled off. An acid fracture job (often called ―acid frac‖) involves pumping a gelled

acid at a pressure above the formation fracture limit. The gel creates a fracture, and the acid

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etches the rock surfaces, creating an irregular pattern. No proppant is used in an acid frac. When

the earth‘s forces cause the fracture to close, the uneven surface of the frac faces will not match

and a new conduit for oil and gas is formed.

(iii) Steam Injection

Steam is one type of stimulation technique for increasing production in zones of high-viscosity

oil. Steam is injected into the formation to improve the oil‘s flow properties. High-temperature

equipment and appropriate workover procedures are required when steam injection is used to

stimulate production.

(iv) Waterflood Injection and CO2 Injection

Waterflood injection and CO2 injection fall into the category of secondary recovery or Enhanced

oil recovery (EOR). Waterflood is a method used to increase production from an existing

reservoir by injecting water into the reservoir to displace the oil. Generally, reservoirs that are

geologically bounded on at least three sides are better candidates for water flooding, since the

water is trapped in place and not free to migrate out. The water generally used is produced

formation water from a nearby source. CO2 injection (or ―CO2 flood‖) is a process by which

carbon dioxide gas is injected\ into the reservoir to replenish drive energy and recover additional

oil that would have otherwise been left in the reservoir. CO2 is often present in certain gas

reservoirs in conjunction with hydrocarbon gas. Gas processing plants separate the CO2 from the

hydrocarbon gas and send it to pipelines for transport to the field for injection. CO2 injection has

been used for years in certain mature oilfields such as the Permian Basin in the southern United

States.

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d) Convert well from production to injection

Workovers are done to convert producing wells

to injection wells. In this type of workover

CO2 or water can be injected, as previously

discussed. Waste fluids or drilled cuttings can

also be injected, which achieves the added

objective of efficient disposal.

For example, such a workover might involve

converting a producing well configured for

continuous or intermittent gas lift. As shown in

the figure given on the right hand side.

Fig(3.7) Converting a producing well configured for a continuous gas lift

Using wireline tools, the gas-lift valves are retrieved from their receptacles, or side-pocket

mandrels, in the completion and replaced with special regulators that control the amount of gas

injected into a particular zone in the reservoir. Typical injected gases include carbon dioxide

(CO2) and produced field gas.

Another example of a well conversion workover would be to reconfigure a well to inject

produced water down the tubing and into the formation. Special regulators are installed in the

completion string with wireline that control the volume of water injected to pre engineered

limits.

Replace Artificial-Lift Equipment

When a reservoir does not have, or cannot maintain, sufficient drive energy to produce at an

economical rate, assistance through artificial lift is required. There are four basic types of

artificial lift: rod pump, hydraulic pump, electric submersible pump (ESP), and gas lift. The

schematic diagram for Sucker Rod Pump is given on the next page:

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Fig (3.8) Sucker Rod Pump

Workover tasks for wells with artificial-lift operations may include:

• For rod pump: Repair or replace the pump on the end of the sucker rod string. Damage may

result from wear, fouling with sand, or pressure locking. This workover would involve using a

rod pulling unit to retrieve the rod string from inside the production tubing. In some cases, the

reciprocating motion of the rods abrades and eventually cuts through the production tubing. In

this situation you must pull both the rod string and the production string.

•For hydraulic pump: Retrieve the pump through the tubing for repairs or replacement. In some

instances, the tubing must be cleaned out first as scale or paraffin buildup may prevent the

pump from passing through it.

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• For ESP: Retrieve and repair or replace faulty ESPs and associated motor electrical cable.

Fig (3.9) Electrical Submersible Pump

• For gas lift: Using Wireline, retrieve and repair or replace gas-lift valves that have lost their

functionality. (Damaged gas-lift valves may allow gas to pass straight through the valve with

no restriction because the internal precharge has been lost or because the elastic parts, called

bellows, have lost their resilience.)

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CHAPTER IV GENERAL PROCEDURE OF A WORKOVER

OPERATION

The phases and sequencing of an operation vary of course from one job to another. They mainly

depend on the equipment already installed in the well and the condition it is in. on what needs to

be done and how the operation is going to proceed in practical terms. However the detailed steps

are generally involved.

Preparing the well (before the servicing or workover unit arrives)

This mainly means:

• checking the status of the well by wireline techniques (checking the tubing, tag sediment), and

sometimes

• checking well integrity (pressure testing, etc.)

• opening a circulating device downhole

Preparing the wellsite (before the servicing or workover unit arrives)

• Check if the site is accessible to the workover rig

• Carry out necessary civil work required for proper landing of workover rig

Putting the well under safe conditions (before rigging up the servicing or workover unit)

This safety operation in fact also involves all the nearby wells (particularly if the well is in a

cluster) that might be hit when the servicing unit is getting set up. II consists in selling plugs in

the tubing in order to install the servicing unit on the wellhead under optimum safe conditions.

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There are three basic ways of doing this:

• using plugs run by wire line and locked in landing nipples in the tubing (generally at the

bottom of the well , near the packer)

• closing the subsurface safety valve if there is one

• setting a back pressure valve in the tubing hanger.

At least two of these safety barriers are normally used.

The various lines connected to the wellhead on the surface (flowlines, etc,) also have to be

isolated and dismantled and nearby equipment that might be damaged has to be bled off.

Installing the servicing or workover unit

Once the well has been placed under safety conditions, the rig and all its equipment (tank,pumps,

workshop, etc,) can be set up in accordance with safety distances, rules and regulations.

However, the Christmas tree is not yet removed to be replaced by the BOPs.

Killing the well

A well is considered to be perfectly killed when tile workover fluid, whose specific gravity is

appropriate for the reservoir pressure, totally fill s up the well (i.e. the inside of the tubing, the

tubing-casing annulus and the space under the packer).

The workover fluid is prepared in sufficient amounts (three times the total volume of the well).

In actual fact the workover fluid is just a completion fluid, since the same properties are required

of it, mainly:

• to keep the well under control by its hydrostatic pressure

• to carry up cuttings if drilling out or milling is planned

• not to damage the formation

• no fluid loss in the formation.

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After the plugs that were set in the tubing to allow the rig to be installed on the wellhead have

been retrieved, the workover fluid is displaced into the well either by circulating or by squeezing.

Then the well's stability is observed. In some cases killing is carried out before the rig is

installed.

Replacing the Christmas tree with the BOPs

Since the workover fluid is keeping the well stable, only one mechanical safety barrier is deemed

necessary (preferably the downhole plug and/or the SCSSV and/of the SPV).

The Christmas tree can then be dismantled at the tubing-head spool and replaced by BOPs which

will be tested. This operation should be completed as quickly as possible. As a result, the

personnel must be mobilized, all the equipment ready, appropriate handling and hoisting

equipment available the wellhead bolts checked, etc.

Removing completion equipment

Pulling Out the downhole equipment can then start, after the SPV (or other plugs that may have

been set in the well) has been retrieved. If there is a kick while tripping, it is necessary to be able

to close quickly not only the annulus (with the BOP tubing rams) but also the tubing itself. The

corresponding safety device (gray valve, etc.) must be on the workover rig floor ready for use

(thread compatible with tubing thread, etc.).

The procedure as such for removing the downhole equipment depends on the type of equipment

and its condition. Particularly important is the type of packer, retrievable or permanent, and if

permanent, the type of connection between the tubing and the packer (seal alone or seal plus

anchor). With a retrievable packer. and especially if there are any doubts as to the condition of

the tubing, it is better not to attempt to unseat the packer by pulling directly on the tubing.

Instead, it is often wise to cut off the tubing a few meters above the packer (by

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means of an explosive charge run on an electric cable), then to run in drill pipe equipped with an

overshot to unseat the packer.

Furthermore, whatever the killing method, there is always a volume of oil and/or gas trapped

under the packer. It is important to circulate it out as soon as possible (for example after

unseating the retrievable packer or after disconnecting the tubing-packer seal if the packer is

permanent).

Whenever tripping out, care must be taken to avoid swabbing (particularly when the packer is

pulled out) and to keep the well full (offset the volume of tubing steel by an equal volume of

workover fluid), Likewise. the well's stability must frequently be checked.

Downhole operations, recompletion, replacing BOPs by the Christmas tree and start up

The techniques are the same as those used when the well was originally completed and so they

will not be developed here. Note, however, that the bottomhole is usually checked beforehand by

running in a drill string equipped with a drill bit and a scraper.

Moving out the servicing or workover unit

In the same way as for initial completion, the rig can be moved out before or after the well is

brought back on stream. The same safety rules and regulations are complied with (especially

setting plugs).

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CHAPTER V CASE STUDY OF SAN-105 WELL

WELL DATA:

Well No : SAN-105

Field : Sanand

Rig Name : VR-32

GGS : EPS

Well Type : Development

Date of Spudding : 24/2/1990

Date of Completion : 16/3/1990

Ground Level : 45.022 m

Kelly Bushing : 48.562 m

Drilled Depth : 1400 m

Production Casing Shoe : 1344.9 m

Float Collar : 1233.38 m

Casing Policy : 2-CP

Conductor Casing(9 5/8‖) : 290.49m

Production Casing(5 ½‖) : 1344.9m (slotted casing: 1257.8m to 1333.29m)

PRESENT COMPLETION DETAILS:

Sand : K-III

Open Interval : 1172-1174 m & 1177-1179 m

Category : Oil (Specific Gravity – 0.9)

BHT : 850

C

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Schematic of Well Profile of SAN-105

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OBJECTIVE OF WORKOVER OPERATION:

―To solve the poor influx problem‖

After the well was completed and released on 23rd

March, 1990, it started producing at 25.91 m3.

After that few mechanical problems related to SRP was encountered and workover jobs for that

were carried out subsequently. But after the last workover job carried out on 17th

May, 2009, due

to some problem the well stopped producing. So, the workover plan to solve the problem was

designed and workover rig VR-32 was deployed on 18th

June, 2012.

SEQUENCE OF OPERATIONS:

1. Subdue the well with brine of 1.02 Sp. Gr.

2. Pull out SRP system and check for the sand.

3. CB up to 1297 m and SCR up to 1240 m.

4. Set R3 packer at 1200 m.

5. Activate lower zone and test thoroughly.

6. Dump sand up to 1190 m.

7. Activate and test upper zone.

8. Carry out BHS and lower ISRP based on results.

9. Test SRP and handover the well to GGS.

THE WORKOVER OPERATION:

After the pulling out of sucker rod and tubing, no mechanical problem was found. So a reservoir

problem was suspected.

As mentioned earlier, the well was producing from two different intervals. So, to know the root

of the problem it was necessary to check in which zone the problem is. Now there were several

possibilities for that particular case. Maybe both of the reservoirs have been depleted, may be

reservoir pressure was declined further to produce any H/C, maybe production from one zone

was going into another zone.

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To identify the cause, both the zones had to be tested individually. Since both the zones were

producing from the same tubing, to isolate them an R3 packer was installed at 1195.89 m.

And for the communication between tubing and annulus 5 Gas Lift Valves were installed.

GLV1 at 290.32 m, GLV 2 at 503.49 m, GLV3 at 688.42 m, GLV 4 at 846.24 m and GLV5

at 985.53 m.

After the installation of packer and GLVs, injectivities of both the zone were checked and

were found 170 LPM (liters per minute) at 1000 psi for lower zone and 140 LPM at 1500 psi

for the upper zone.

Then compressor was applied through GLVs at 40 ksc (kgs per cm2), but no flow was

observed after waiting for 12 hours.

Again compressor was applied at 37 ksc, but no flow was observed. But at 38 ksc water flow

was observed. And applying compressor at 36 ksc again, presence of air was observed. After

stopping the compressor well was subdued with brine (Sp. Gr. – 1.09).

Then X-mas tree was removed and packer was released. GLVs and packer were pulled out.

As the lower zone was tested by isolating upper zone with packer, now to test the upper zone

and isolate the lower zone, a sand plug was injected. And packers and GLVs were installed

again. Yet no traces of oil were been observed.

Compressor was applied again. Up to 24 ksc no flow was observed. Between 24-37 ksc water

flow was observed and at 31 ksc air was observed.

After the application of 2nd

and 3rd

compressor also, no activity was observed.

Well was subdued by 1.02 Sp. Gr. brine.

Now that no oil traces were found by the application of compressor for several times, it was

decided to reperforate the upper zone and check whether oil starts producing or not.

Reperforation job was done in the interval of 1166-1171 m and 1177-1179 m.

Now after the application of the compressor, up to 75 ksc water flow was observed, but at

75-100 ksc oil traces were observed. Again compressor was applied and same results were

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observed.So, the reperforation job was successful and completion of both the zones was

carried out and SRP was installed and flow was resumed.

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References

Paper in a Journal

Walker, G., Dotco Fishing Tools : "Fishing"

Hilts, R.L., Otis Engineering Corp.; Fowler Jr., S.H., Halliburton Manufacturing and Services

Ltd.; Pleasants, C.W., Otis Engineering Corp.:"Fishing With Coiled Tubing"

Thomas Lamb, Maryland Shipbuilding & Drydbck Co."Fishing Trawler Economic Study and

Trawler Design"

E. John Northwood, Northwood and Associates, Inc.:"The Generation And Measurement of

Electrical Fields By Fish: Can We Learn From Them?"

Tomas Elander Solli, DNV:"Workover/Well Intervention and Regulatory Challenges"

Liu He, SPE, PetroChina Daqing Oilfield Company Limited; Xiao Dan-feng, SPE, Daqing

Petroleum Institute; and Fan Ke-ming, Jin Li-feng, Pei Tao, and Zhang Shilin, PetroChina

Daqing Oilfield Company Limited:"Successful Acid Stimulation in Acid-sensitive Reservoirs"

Arihara, N., Waseda University; Abbaszadeh, M., Japan National Oil Corporation; Wright, C.A.,

Pinnacle Technologies; Hyodo, M., Geothermal Energy Research and Development Co.,

Ltd.:"Integration of Fracturing Dynamics and Pressure Transient Analysis for Hydraulic Fracture

Evaluation"

Dilip Kumar Sarma*, SPE; Y R L Rao, SPE; B Mandal, SPE; P K Bhargava, SPE ONGC,

Mumbai, India:"Application of Self-Diverting Acid System for Stimulation of Multilayered

Wells in Carbonate Reservoir: A Case Study"

Referred Book

Production Enhancement with Acid Stimulation by Leonard Kalfayan Publisher: Workover Well

Control by Neal Adams, 2nd

edition.

ONGC-Workover Operations Onshore Standard Operating Procedures Manual (January 2012)

Well Control for Completion and Workover by Well Control School;ISBN 0-88698-155-7. 1992,

416 pp.

Blowout and Well Control Handbook by Robert D. Grace,Elsevier, 25-Aug-2003 - 469 pages

Material from Web Site

"Workovers" on http://www.lloydminsterheavyoil.com/workover.htm

Well Kill topic on http://en.wikipedia.org/wiki/Well_kill

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