2. Declaration
We declare that the project entitled "DRILLING EQUIPMENTS" have been prepared by us
under the guidance of Mr. Vinod M. Motwani during the winter internship from 7 Dec,
2015 to 1 Jan, 2016.
We also declare that this project is a result of our own effort and that has not been
submitted to any other university any time before, to the best of our knowledge.
Place: Mehsana, Gujarat

3. ACKNOWLEDGEMENT
We are indebted to and would like to extend our sincere gratitude to ONGC officials for
giving us the opportunity to undertake a project titled “DRILLING EQUIPMENTS”. Our
internship at Mehsana Asset, ONGC has helped me to get abreast with the latest in all
aspects of drilling operations, Maintenance, and Health & Safety. The most important
aspect of our internship has been smooth transition from the theory to the working
environment of the real world where we got the feel of working of the equipment’s, and
other drilling tools and all this would not have been possible without the right guidance
given to us by one and all whom we came in contact with during each and every staff
member was cooperative and supportive.
We take this opportunity to thank each and every ONGC personnel; especially we would
like to thank a few personnel without their support this project would have been
impossible to complete. We are indebted Mr. Suchit Singh (Sr. Head HR) and Mr. Rathin
Patel for providing us opportunity to pursue winter internship. We sincerely thank our
mentor Mr. Vinod M. Motwani (DGM Drilling), Mr. S.R. Machi, Mr. S.P. Dewan, Mr. V.K.
Verma, Mr. U Pandey and whole directional drilling staff for providing us a simulating
environment and proper guidance at every step.
Our cordially thanks to those who contributed a lot in giving us important data related to
the ONGC field and its functioning in a lucid and accurate manner which helped us to gain
the necessary points in a very short time of this winter internship.

4. Index
About ONGC 1
1. ONGC Mehsana Asset 2
2. Drilling 3
Introduction 3
Drilling Rig 5
Rig component 9
Power system 9
Hoisting system 10
Rotating Equipment 17
Drilling fluid handling equipment 33
Well-control system 43
3. Casing and cementing 49
Casing 49
Cementing 51
Mechanical Aids 54
4. Fishing Tool 58
Cause of pipe sticking 58
Fishing Tool 59

5. 1
Oil and Natural Gas Corporation
Limited
Vision and Mission
To be global leader in integrated energy business
through sustainable growth, knowledge excellence
and exemplary governance practices.
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.
About ONGC
Oil and Natural Gas Corporation Limited (ONGC) is a
Public Sector Undertaking (PSU) of the Government
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 70% of India's crude oil
(equivalent to around 25% of the country's total
demand) and around 60% of its natural gas. With a
market capitalization of over INR 2 trillion, it is one
of India's most valuable publicly-traded companies.

6. 2
1. ONGC Mehsana Asset
The Mehsana Tectonic Block is a fairly well explored,
productive hydrocarbon block of north Cambay
basin. Exploration activity for hydrocarbons by ONGC
at Mehsana asset commenced in 1960s and
discovered fields are in an advanced state of
exploration. The asset has been endowed with a
number of oil fields with multi-layered pays
belonging to Paleocene to middle Miocene age.
More than twenty-six small to medium size oil and
gas fields have been established in Mehsana area of
Mehsana-Ahmedabad Tectonic Block. Operational
areas of Mehsana Asset include a Mining Lease (ML)
area of 942 sq.km. In this Asset, 2324 wells have
been already drilled. Further, thirty-five production
installations have already been established to
complete the hydrocarbon production, storage and
delivery cycle. The Asset currently produces 6100
TPD of crude oil and 5 lakh cubic meter of Natural
Gas on daily basis.
Major Oil Fields within the Asset have been clubbed
under six different areas:-
1. Becharaji and Lanwa (Area-I)
2. Sathal and Balol (Area-II)
3. Jotana (Area-III)
4. Sobhasan Complex (Area-IV)
5. Nandasan, Linch, Langhanj, Mansa and other
satellite structures (Area-V)
6. North Kadi (Area-VI)
Area I and II constitute the heavy oil fields in
Mehsana Asset. The Mehsana asset in the northern
part of Gujarat state is the highest oil producing
onshore Asset with annual oil production of about
16.2 million bbl. Cambay Basin of Gujarat is a
petroliferous basin of India. The northern part of this
basin is fenced by number of heavy oil fields. These
fields are characterized by high permeability pay
zones in Mehsana Horst structure. Fields in Mehsana
produce both heaviest and one of the lightest crudes
in India with gravity ranging from 13-42 API. Heavy
oil fields discovered in 1970-71 belong to northern
part of Cambay Basin.
ONGC is planning to step-up exploration work at its
Mehsana Asset in western onshore basin and has
sought the environment ministries approval for
digging 29 new exploratory wells. Though the state
run company has sought the clearance for 29
exploratory wells, the actual drilling may be done in
phases from 2016-17 onwards starting with 8-10
wells.
Mehsana in Gujarat is ONGCs largest on land Asset
with 1552 operational oil and gas wells that produce
6000 tons of oil per day and 5.3 lakh cubic meter of
gas a day. According to ONGC,” The hydrocarbon
reserves are already estimated for our matured
fields with above 35 years of production history for
exploratory activities in case of new fields, reserves
will be estimated upon drilling and production
testing”.
The Union Budget 2015-16 stated that the state run
oil firms would invest over Rs.76565 crore on Capex
in 2015-16 up 5% on year. Of this ONGC alone would
invest Rs.36-50 crore as against the target of
Rs.34813 crore in the current fiscal. ONGC states that
Mehsana Asset drills about 70 in field development
wells every year in the mature fields of the Asset for
production augmentation and other 8-10
exploratory wells. Sources states that company may
consider significantly higher number of exploratory
wells in 2016-17 and that is why it has sort approvals
for 29 of them.
The company’s production at western onshore basin,
which is spread across Saurashtra in Gujarat to
Kerala-Konkan coast, would be crucial for it to boost
production in keeping Prime Minister Narendra
Modi’s aim of cutting India’s import dependence on
oil by 10% over the next seven years, from 78% at
present.

7. 3
2. Drilling
Introduction
Oil drilling is the process by which tubing is bored
through the Earth's surface and a well is established.
A pump is connected to the tube and the petroleum
under the surface is forcibly removed from
underground. Oil drilling is a highly-specialized
business that grew into the largest industry on the
planet by the early 21st century.
A well drilled in a proven producing area for the
production of oil or gas. A development well is drilled
to a depth that is likely to be productive, so as to
maximize the chances of success. An exploratory
well, which is one that is drilled to find oil or gas in
an unproved area. As a result, dry or unsuccessful
development wells are rarer than dry exploratory
wells.
The creation and life of a well can be divided up into
five segments:
1. Planning
2. Drilling
3. Completion
4. Production
5. Abandonment
The well is created by drilling a hole 12 cm to 1 meter
(5 in to 40 in) in diameter into the earth with a drilling
rig that rotates a drill string with a bit attached. After
the hole is drilled, sections of steel pipe (casing),
slightly smaller in diameter than the borehole, are
placed in the hole. Cement may be placed between
the outside of the casing and the borehole known as
the annulus. The casing provides structural integrity
to the newly drilled wellbore, in addition to isolating
potentially dangerous high pressure zones from each
other and from the surface. With these zones safely
isolated and the formation protected by the casing,
the well can be drilled deeper (into potentially more-
unstable and violent formations) with a smaller bit,
and also cased with a smaller size casing. Modern
wells often have two to five sets of subsequently
smaller hole sizes drilled inside one another, each
cemented with casing.
After drilling and casing the well, it must be
'completed'. Completion is the process in which the
well is enabled to produce oil or gas. In a cased-hole
completion, small holes called perforations are made
in the portion of the casing which passed through the
production zone, to provide a path for the oil to flow
from the surrounding rock into the production
tubing.
In many wells, the natural pressure of the subsurface
reservoir is high enough for the oil or gas to flow to
the surface. However, this is not always the case,
especially in depleted fields where the pressures
have been lowered by other producing wells, or in
low permeability oil reservoirs. Installing a smaller
diameter tubing may be enough to help the
production, but artificial lift methods may also be
needed.
A well is said to reach an "economic limit" when its
most efficient production rate does not cover the
operating expenses, including taxes When the
economic limit is reached, the well becomes a
liability and is abandoned. In this process, tubing is
removed from the well and sections of well bore are
filled with concrete to isolate the flow path between
gas and water zones from each other, as well as the
surface.
There are various method available for drilling the
oil-well. Some of the important method describe
below.
Cable tool drilling

8. 4
Cable tool rigs are a traditional way of drilling water
wells. The majority of large diameter water supply
wells, especially deep wells completed in bedrock
aquifers, were completed using this drilling method.
The impact of the drill bit fractures the rock and in
many shale rock situations increases the water flow
into a well over rotary. Also known as ballistic well
drilling these rigs raise and drop a drill string with a
heavy carbide tipped drilling bit that chisels through
the rock by finely pulverizing the subsurface
materials. The drill string is composed of the upper
drill rods, a set of "jars" and the drill bit. During the
drilling process, the drill string is periodically
removed from the borehole and a bailer is lowered
to collect the drill cuttings. The bailer is a bucket-
like tool with a trapdoor in the base. If the borehole
is dry, water is added so that the drill cuttings will
flow into the bailer. When lifted, the trapdoor
closes and the cuttings are then raised and
removed. Since the drill string must be raised and
lowered to advance the boring, the casing is
typically used to hold back upper soil materials and
stabilize the borehole.
Air core drilling
Air core drilling and related methods use hardened
steel or tungsten blades to bore a hole into
unconsolidated ground. The drill bit has three blades
arranged around the bit head, which cut the
unconsolidated ground. The rods are hollow and
contain an inner tube which sits inside the hollow
outer rod barrel. The drill cuttings are removed by
injection of compressed air into the hole via the
annular area between the inner tube and the drill
rod.
Reverse circulation (RC) drilling
RC drilling is similar to air core drilling, in that the drill
cuttings are returned to surface inside the rods.
Diamond core drilling
Diamond core drilling (exploration diamond drilling)
utilizes an annular diamond-impregnated drill bit
attached to the end of hollow drill rods to cut a
cylindrical core of solid rock.
Direct push rigs
Direct push technology includes several types of
drilling rigs and drilling equipment which advances a
drill string by pushing or hammering without rotating
the drill string. While this does not meet the proper
definition of drilling, it does achieve the same result
a borehole.
Sonic (vibratory) drilling
A sonic drill head works by sending high frequency
resonant vibrations down the drill string to the drill
bit, while the operator controls these frequencies to
suit the specific conditions of the soil/ rock geology.
Auger drilling
Auger drilling is done with a helical screw which is
driven into the ground with rotation; the earth is
lifted up the borehole by the blade of the screw.
Percussion rotary air blast drilling (RAB)
The drill uses a pneumatic reciprocating piston-
driven "hammer" to energetically drive a heavy drill
bit into the rock.
Hydraulic rotary drilling
Oil well drilling utilises tri-cone roller, carbide
embedded, fixed-cutter diamond, or diamond-
impregnated drill bits to wear away at the cutting
face. This is preferred because there is no need to
return intact samples to surface for assay as the
objective is to reach a formation containing oil or
natural gas. Rotating hollow drill pipes carry down

9. 5
bentonite and barite infused drilling muds to
lubricate, cool, and clean the drilling bit, control
downhole pressures, stabilize the wall of the
borehole and remove drill cuttings . The mud travels
back to the surface around the outside of the drill
pipe, called the annulus. Examining rock chips
extracted from the mud is known as mud logging.
Another form of well logging is electronic and is
frequently employed to evaluate the existence of
possible oil and gas deposits in the borehole. This can
take place while the well is being drilled, using
Measurement While Drilling tools, or after drilling,
by lowering measurement tools into the newly
drilled hole.
Drilling rig
Fig. Drilling rig (Onshore)
A drilling rig is a machine that creates holes in the
earth sub-surface. Drilling rigs can be massive
structures housing equipment used to drill water
wells, oil wells, or natural gas extraction wells, or
they can be small enough to be moved manually by
one person.
Drilling for oil has begun for thousands of years. This
evolution has been accompanied with the utilization
of different tools and mechanisms. For example, the
first oil well was drilled in China at about 1600 years
ago. Its final depth was about 250 meters (m) and it
was drilled using bamboo poles with a bit at its end.
This well was followed by an evolution in the number
of wells and the mechanisms used. For instance, by
the end of the 1800s, the invention of the Internal
Combustion Engine (ICE) helped at introducing a new
drilling mechanism called Cable-Tool Drilling (CTD).
In this mechanism, a chisel bit is placed at the end of
a cable that oscillates up and down with the mean of
the ICE in order to make the planned hole.
Furthermore, the first modern oil well was drilled in
mid nineteenth century by the engineer Semyonov
in the north-eastern of Baku. However, the CTD
method was not effective for many reasons and this
led to the introduction of other mechanisms. For
example, the limited depth of this method has led to
the evolution of rotary drilling. The CTD operation
also needs to be paused in order to clean the
cuttings. In addition, drilling operations were not
limited to the land but they have been extended to
the marine locations. For instance, in 1891, the first
marine well was drilled in Grand fresh-water Lake in
Ohio. Then the first well in a salty-water location was
drilled about 120 years ago.
Classification of Rotary Drill Rig
They are classified based on different criteria. To
illustrate, drilling rigs are classified based on the
location they drill at, the maximum load they can
handle and the ultimate depth they reach.

10. 6
Based on location where it is used
1) Onshore rig
2) Offshore rig
Onshore rig
These type of rigs are used for drilling deep holes
under the earth surface in order to extract natural
resources. Onshore land drilling rigs includes
functions like product manufacturing, examination,
assessment of oil gasses and wells of different kinds.
The wells can be vertical or horizontal ranging
between 1200 meters to 5000 meters in depth.
Onshore land drilling services very efficiently
provides for construction of drilling rigs and
workover services. Drilling services relating to
onshore land drilling is very commonly found in parts
of Russia, Uzbekistan, and Kazakhstan. Land drilling
is simpler, for you can easily carry the Drilling tools
from one place to another. Onshore installations can
be easily assembled. You can also easily recover your
invested money through Land drilling.
Land rigs are also classified based on two main
criteria, maximum drilled depth and mobility:
Classification Based on the drilled depth
According to Bommer (2008), land rigs generally look
the same. However, their specific details are totally
different because their sizes depend on the
maximum depth they drill. As a consequence, many
different types on onshore rigs are categorized based
on the ultimate depth they drill. To illustrate, Macini
(2005) says that there are four different depth
categories for land drilling rigs, as shown in table
Rig Type Ultimate Drilling Depth
Light weight 2 km
Medium weight 4 km
Heavy weight 6 km
Ultra-heavy weight Higher Depth
Classification Based on mobility
Another feature of onshore drilling rigs is related to
their transformation way. Based this feature,
Bommer (2008) refers to them as “portable hole
factories”. Furthermore, depending on rigs’ mobility,
land rigs are divided into different categories.
Conventional and mobile drilling rigs.
Conventional land rigs are the most commonly used
in petroleum industry and they cannot be moved to
the drill site as whole units. In contrast, mobile
(movable) rigs refer to those in which the drilling
systems are mounted on wheeled trucks and they
come in two different types, jacknife and portable
mast.
Offshore drilling
These type of rigs are used in order to explore for and
subsequently extract petroleum which lies in rock
formations beneath the seabed. This type of rig used
to drill in marine environment.
This type of rig classified as below

11. 7
Bottom supported unit
This refers to the rigs that are on contact with the
seafloor when they are placed in position. These
types of rigs come in two different categories,
submersible and jack ups.
Submersible
A submersible oil rig can be used in shallow water
where the depth of water is about 80 feet or less.
These rigs are towed to the location of the oil
reserves and submerged in the water until the rigs lie
on the ocean floor. Anchors are sometimes used to
secure the position of the submersible rigs. These
type of rig further classified into four different group
as shown in above charts.
Fig.: Arctic-type submersible rig
Jackups
Jackup refers to those which are supported by three
or five structured columns. Companies use this type
of rigs for different purposes. Jackup rigs for lower
marine depths as well as for the exploration.
Jack-up rigs can operate at different sea depths and
can drill different well depths. For instance, jack ups
are used at marine depths of 120 meters and can drill
to about 9.1 kilometre.
Fig.: Jackup rig
Floating Units
This type of marine rigs refers to those which are
not directly in contact with the sea bottom when
placed in the drilling site. That there are two types
of floating offshore rigs, semi-submersible and
drilling ships.
Semi-submersible rig
These are those which are partially submerged
below the water surface and are anchored to the
seabed.
Fig.: Semi-submersible rig

12. 8
This type of rigs can drill at different water depths
and can drill for different well depths. For example,
Bommer (2008) shows that some semi-submersible
rigs can operate at water depths ranging from 300
meter to 1,000 meter (1 km) and some others can
drill at depths of about 3.7 km. They can also drill
wells reaching depths of 10.7 km.
Drilling Ships
Drilling ships, figure (11), come in different shapes
and structures. They can also drill at different water
depths and can drill wells of different depths.
Fig.: Drilling ship
To illustrate, it is shown that some drill ships can
operate at water environments of depths about
1,000 meters and others can operate at depths of
about 3,000 meters. They can also drill wells of
depths about 9.1 kilometre.
Future Development Related to Drilling Rig
Currently, mainly two development aspect related to
drilling rig and drilling operation are outlined.
Introducing robotics and automation into drilling
operation
Risks and costs of oil related operations is increasing
with the increase of oil usage. Therefore, one of the
developing aspects to overcome this includes
introducing robotics and automation into the drilling
operations.
Fig.: Robotic drilling System
Going Deeper into the Ocean
The use of the offshore drilling rigs is due to the fact
that a large amount of oil comes from the marine
location. About one-third of the global oil supply
comes from offshore deposits. However, because of
the tough environments and the far location of
marine operations, drilling at such locations is highly
challenging. As an example of the risk of these
environments is the BP’s Maconland well explosion
in 2010 which resulted in the death of 11 people,
though the depth of operation was not that high,
only 1.5 km deep. As a result, petroleum industry is
trying to eliminate this challenge by introducing
stronger drilling rigs and systems that will be able to
withstand tougher environment. The British
Petroleum (BP), for example, is about to introduced
what is called 20K which can drill at deeper
environment with higher pressures of about 20,000
pound per square inches (psi) and higher
temperatures. This is a great step because the
current offshore drilling rigs operate at pressures
ranging from 13,000 to 18,000 psi and the deepest
offshore rig in 2010 was the Perdido platform at the
Gulf of Mexico which operates at water depth of 2.4
km.

13. 9
Rig Components
The equipment associated with a rig to some extent
dependent on the type of rig but typically includes at
least some of the items listed below.
Basically, the rig component divide into major five
groups according to their performance. This group
are describe as below.
1. Power system
2. Hosting system
3. Rotating equipment
4. Mud circulation system
5. Well control system
Power system
Most drilling rigs are required to operate in remote
locations where a power supply is not available. The
power systems of a rig are the main source of power
for running all equipment which include the
following components:
1. Electric Generators – generators that are powered
through diesel engines in order to provide electrical
power to the rig. Mainly AC power produced by
generator.
2. Diesel Engines – very large engines that burn diesel
fuel in order to provide the main source of power on
the rig. Mainly 4-stroke diesel engine used to run
generator.
Power is transferred to the different rig systems by
belts, chains, and drive shafts on a mechanical rig or
by generated DC drill collar electrical power on an
electric rig .Power is distributed to the rotary table
and mud pumps while drilling and to the draw-works
when tripping.
Figure shows the typical diagram of the power
system which include 4-stroke diesel engine,
alternator.
Fig.: Power system
Electric generators
The majority of new rigs today are AC/DC electric rigs
with SCR controls, which use multiple diesel-electric
generator sets running in parallel to produce the two
to four megawatts of power needed at the drill site,
including the power needed for camp loads such as
lighting, heating and air-conditioning for crew
quarters.
Fig.: Electric generator
Diesel engine
Oil Rig uses the Diesel Engines that are manufactured
in the twin versions of the 2 stroke and the 4 stroke.
Originally, the Rig was used as an efficient means for
replacing the stationary engines. Oil Rig operates on
a variety of fuels or Oil on the basis of the

14. 10
configuration. The fuel that is derived from crude Oil
is used, although the Diesel fuel is more commonly
used.
Fig.: Diesel Engine
Generators selecting criteria
1. Base frame stiffness, durability
A prerequisite for any electric drill generator set is
rugged construction. The stiffness of the generator
set base is critical to its longevity because any
distortion could affect the alignment of the coupling
between the engine and alternator, resulting in
severe vibration and damage.
2. Ratings and performance characteristics
Rig generator sets are designed for continuous
operation and therefore are conservatively rated in
terms of their kW output. A typical rig generator set
has a nameplate rating of about1, 100 kW, although
larger and smaller units are available.
3. Overload capacity
Due to the severity of operating conditions in the
field, generator sets are often called on to deliver
maximum output— and then some. Generator sets
should have at least a 10% overload capability
beyond their nameplate rating.
4. Fuel consumption
Since rig generator sets operate continuously, fuel
consumption accounts for the largest operational
cost. Just a few percentage points of better fuel
economy can add significantly to the bottom line.
Diesel engines tend to be most fuel-efficient in
proportion to their output when operated at100% of
their rated load.
Hoisting system
Hosting equipment is device used for lifting or
lowering a load by means of the drum or lift wheel
around which rope or chain wraps. It may be
manually operated and electrically or pneumatically
driven.
The equipment includes
 the hoisting tower structure,
 the draw works and its accessories,
 the drilling line,
 The control panel.
Derrick
A "derrick" is an apparatus consisting of a mast held
at the head by braces. A derrick may or may not have
a boom and is used with a hoisting mechanism and
operating ropes. Derricks do not swivel at the base.
The end of the mast or boom is controlled by cables,
providing great strength and stability but only a
limited range of motion.
Objective
To provide vertical clearance to raising and lowering
of the drill string into and out of the hole during
drilling operations. It also supports the hoisting
equipment and rack the tubulars while tripping.
The number of joints in a stand that the rig can pull
is dependent on the height of the derrick.

15. 11
A. Single- has the capacity of pulling 30’stands
of pipe (one 30-ft joint)
B. Double- has the capacity of pulling 60’ stands
of pipe
C. Triple- has the capacity of pulling 90’ stands
of pipe
Fig.: Derrick
This structure withstands two types of loading:
A. Compressive loading
It is the summation of the strengths of all
legs
B. Wind loading
For drill pipe to stand vertically stable during
trip, the top of the stand must lean outward
against the fingers at the pipe racking
platform. This results in the overturning
moment applied to derrick at a point. If the
wind blowing is perpendicular to setback a
further overturning moment is applied. So
there will be a loading condition due to wind.
Early derricks consisted of a framework which was
designed to hold a large pole used for percussive
drilling, which is accomplished by repeatedly beating
the earth to make a hole. A modern oil derrick
typically uses a drill bit which is capable of biting
through the substrate, and cooled with a constant
slurry of mud to prevent it from getting too hot.
Typically, as the drill bit sinks in, the hole is lined to
prevent a cave in. Once the drill reaches the oil, it is
withdrawn so that pumps and pipes can be inserted
into the hole to extract it. A large derrick requires an
extensive crew to run properly, and is often located
in a field of similar derricks, all of which operate on a
constant basis. The oil derrick crew typically includes
geologists, engineers, mechanics, and safety
inspectors to ensure that the workplace is well
maintained.
Derricks are generally two different types
1. Standard derrick
2. Portable Derricks
Standard Derrick
That cannot be raised to working position as a unit.
It is a bolted construction that must be assembled
part by part and be disassembled while
transportation
Standard derrick is preferred where the lay down
room is not available and where portability and quick
rig up time are not primary considerations.
Deep wells requires more floor space for racking pipe
and at hard and deep areas where trip time saving by
using a tall derrick may more than moving costs.

16. 12
Portable Derricks
It is capable of being erected as a single unit. The
telescoping derrick is raised and lowered in an
extending and collapsing fashion and lowered in one
piece, but may be disassembled to some degree
after being lowered.
It is selected over standard derrick due to saving in
erection, tear down time and transportation costs
Mast
Fig.: Mast
The mast is a structure shaped like a very pointed A.
It has the particular feature of being rotary jointed at
the base so that it can be assembled or dismantled
horizontally and then pulled to an upright position
using the draw works and a special hoisting cable.
This type of drilling tower is well suited to onshore
drilling rigs requiring good deal of mobility. The
racking board is in a cantilever position and lengths
of pipe are racked on a floor, called the setback that
is separate from the mast structure.
Fig.: Erection of a mast
Technical specifications are identical to those for
derricks
Maximum hook load given the reeving system, free
height available in the mast, width at the base,
resistance to wind with and without racked drill
string.

17. 13
There are other less common types of masts that
meet installation requirements on an offshore
development platform where a conventional mast
cannot be placed in a horizontal position due to lack
of room. The solution is to use a folding mast or a
telescoping mast. The telescoping mast has two
sections that fit together and are dismantled and
laid down horizontally, taking up only half as much
room.
Substructures
These structures serve to raise the rig floor to leave
room for wellhead assemblies and BOP stacks. They
can be separate from the hoisting mast. Here they
consist of box-like structures piled up on either side
of the wellhead. The rig floor is assembled on top of
the boxes and the hoisting mast sits directly on the
box substructure. Most intermediate capacity masts
are an integral part of a hoisting assembly with an
elevating substructure where the draw works and
racking floors are folded at ground level by girders
articulated in the shape of a parallelogram. Once the
mast has been erected by the draw works, the floor
is pulled into an unfolded position using the drilling
line.
Fig.: folding substructure
Drilling line reeving system
The drilling line reeving system is made of the
following components
1. Deadline
2. Crown block
3. Travelling block and hook
4. Drilling line
5. Fast line
Fig.: reeving the drilling line
Deadline
The drilling line is secured to a specific deadline
anchor which measures the tension on that end of
the line. It also allows new lengths of line to be run
into the system in order to relieve the worn parts of
the line by moving them from critical wear points on
the pulleys of the crown block or the traveling block.
Slipping the line, then cutting it off helps lengthen
the lifetime of the drilling line.
Crown Block
Crown block is a pulley situated at the top of an oil
rig or derrick. It sits on the crown platform, which is
a steel platform located along the upper portion of
the rig. The crown block works in conjunction with a
similar component, the traveling block, which is
positioned just below the crown platform. Together,
these two systems are known as the block and tackle.
While the block and tackle system appears relatively

18. 14
simple to outsiders, it actually represents a critical
component of the oil drilling process.
Fig.: Crown block
Crown block is a pulley that has a wire-rope drilling
line running between it. While the crown block is
fixed, the traveling block moves up and down
between the crown block and the rig floor. The use
of a crown block and block greatly enhances the
power of the oil derrick. The position of the pulleys
allows the cables to withstand tremendous levels of
force, and helps workers drill deeper and extract
more oil. Without a crown block, the oil derrick
would require much thicker and stronger cables. It
would also require a more powerful and substantial
pumping system to operate successfully. The use of
the block and tackle system provides a high degree
of leverage to lift and lower the hoisting drum in
order to maximize productivity and efficiency.
Depending on the size of the derrick and the depth it
must drill to, an oil rig may use either a single or
double crown block. While a single block utilizes only
one set of pulleys, the double deck model includes
two sets. These pulleys are situated at a right angle
to one another to generate extra force and power.
The traveling block and hook
A traveling block is the freely moving section of the
block and tackle that contains a set of pulleys or
sheaves through which the drill line is threaded or
reeved. The combination of the traveling block,
crown block and wire rope drill line gives the ability
to lift weights in the hundreds of thousands of
pounds.
The hook has a shock absorber to lessen stresses
when the load is picked up and make screwing
connections easier. The elevator bails are connected
to two side hooks.
Fig.: Travelling block with hook
The drilling line
Drilling line has a metal core with six steel wire
strands braided, or cabled around it. The lay of the
wires made into strands is the opposite of the lay of
the strands on the core of the wire rope (normal or
regular lay). This makes the drilling line stiffer but
somewhat less prone to rotate. The steel may be of
three grades: PS (plow steel), IPS (improved plow
steel) and EIPS (extra improved plow steel).
Diameters vary widely depending on the type of rig,
but generally do not exceed 1.5 inches.

19. 15
Fast line
The segment of drilling line from the draw-works to
the crown block is called the fast line.
Draw works
The draw works is the heart of the drilling rig. A
draw-works is the primary hoisting machinery that is
a component of a rotary drilling rig. Its main function
is to provide a means of raising and lowering the
traveling blocks. The wire-rope drilling line winds on
the draw works drum and extends to the crown block
and traveling blocks, allowing the drill string to be
moved up and down as the drum turns. It is the
capacity of the draw works that characterizes a rig
and indicates the depth rating for the boreholes that
can be drilled. A grooved drum where the drilling line
will be reeled up.
Fig.: Draw works
The different mechanical parts are:
1. Drum
2. Motor
3. Reduction gear
4. Brakes
5. Auxiliary brakes
There are brake rims on the edges of the drum where
the brake bands are mounted. The brake controls the
lowering speed of the load hanging from the hook.
The system is highly reliable but does not have
enough capacity to absorb all the energy produced
by a string of casing lowered to great depths.
A gearbox behind the draw works enables the driller
to select from two or three gear ratios. Two ratios
are sufficient when the draw works is electrically
driven. Here regulating the variation in rotation
speed is well controlled. Two parallel shafts are
connected by pairs of sprockets and chains. There is
the same number of pairs as gear ratios. One of the
sprockets in each pair can rotate freely around the
shaft when the dog clutch system is disengaged.
Engaging a gear means mechanically moving the dog
clutch system so that it blocks the rotation of the
sprocket in relation to its shaft. The secondary shaft
then rotates at the speed corresponding to the
selected reduction ratio. The secondary shaft also
causes the draw works drum to rotate by means of
two pairs of sprockets and chains located on either
side of the gearbox housing. These two extra ratios
(low and high drum drives) are engaged by Air flex-
type air clutches.
Auxiliary Brakes
The draw works generally have two braking systems;
the band-type brakes on the draw works drum, and
the auxiliary brakes. The auxiliary brakes are used
only when going in the hole on a trip. These are used
to prevent burning the band type brakes.
The braking capacity of the band system is not
dynamically adequate when heavier loads are
lowered into the well. This is why there is an added
slowdown brake incorporated in the draw works
drum axis on all rigs.
The auxiliary brakes are of two types:
1. Hydro-dynamic
2. Electromagnetic.

20. 16
Hydrodynamic brake
The operating principle is to convert the mechanical
energy produced by lowering a load into heat by
means of a rotor that is made to rotate by the draw
works drum. The amount of mechanical energy that
can be absorbed depends on the rotation speed and
on the volume of water circulating in the working
chamber. In order to adapt the deceleration to the
load, the driller regulates the level of water in a small
tall surge tank located in the water cooling circuit.
The tank adjusts the amount of fluid in the brake and
varies the braking torque.
Fig.: Hydrodynamic brake
The system is reliable and requires very little
maintenance, but it has major drawbacks: it provides
little braking at slow speeds and regulation is too
inflexible. As a result, its use is confined to
lightweight drilling rigs.
Electromagnetic Brake
The eddy-current brake which includes a driven
element (rotor) and a stationary member which
provides a controllable and adjustable magnetic
field. The magnitude of the magnetic fields is
dependent on the speed of rotation and the amount
of external excitation current supplied. The rotor
cuts the lines of the magnetic field. The
electromagnetic forces induced in the rotor tend to
oppose the rotary movement. The eddy currents
produced in the rotor generate heat by Joule effect.
The heat is dissipated by a water circulation system.
The amount of braking torque is related to the
intensity of the magnetic field produced by soils and
as a result this type of brake very flexible to operate.
In both types of auxiliary braking systems, the heat
development must be dissipated using a liquid
cooling system.
Monkey board
Fig.: Monkey board
Platform on which the derrick man works during the
time a trip is being made. Also referred to as the
tubing board or racking board on well servicing rigs.
Drill floor
The Drill Floor is the heart of any drilling rig. This is
the area where the drill string begins its trip into the
earth. It is traditionally where joints of pipe are

21. 17
assembled, as well as the BHA (bottom hole
assembly), drilling bit, and various other tools. This is
the primary work location for roughnecks and the
driller. The drill floor is located directly under the
derrick.
Fig.: Drill floor
The floor is a relatively small work area in which the
rig crew conducts operations, usually adding or
removing drill-pipe to or from the drill-string.
Drill string connections are made or broken on the
drill floor, and the driller’s console for controlling the
major components of the rig are located there.
Casing head (Well Head)
The lowest part of the wellhead that is almost always
connected to the surface casing string, and provides
a means of suspending and packing off the next
casing string.
Fig.: Drilling head
Providing attachment to the surface casing string
through the type of bottom connection (Slip-on-
weld, threaded, Slipslop), the casing head is typically
qualified to withstand up to 10,000 psi working
pressure. It suspends the casing and packs off the
next casing string while providing annular outlets, as
well as supporting the BOP while drilling the
remaining stages.
Rotating equipment
Rotating equipment is essentially a piece of
equipment that interprets the power transmitted
from the prime mover and puts it into action,
rotating the bit. In turn, a swivel which is attach to
the hosting equipment provides support for the
weight of drill string in a way that enables it to rotate
uninterrupted. Some of the rotating equipment
describe below.
Swivel
A Swivel is a mechanical device used on a drilling rig
that hangs directly under the traveling block and
directly above the kelly drive, that provides the
ability for the kelly (and subsequently the drill string)
to rotate while allowing the traveling block to remain
in a stationary rotational position (yet allow vertical
movement up and down the derrick) while

22. 18
simultaneously allowing the introduction of drilling
fluid into the drill string
It also supports the drill stem and acts as a pressure-
sealed passage way for the drilling mud that is
pumped into the drill stem.
Fig.: Swivel
1-bails; 2- gooseneck; 3- joints; 4- packing boxes; 5-
pressure cap; 6- mud packing; 7- red tube; packing
boxes 8-, 9- pressure cap; 10 – mud umbrella; 11-
bush; 12- oil packing; 13-shelters; 14- dipstick; 15-
righting bearings; 16-anti-skip bearing; 17- bails pin;
18- central tube;19 - main bearings; 20- shell; 21- oil
packing boxes; 23- protect joints
Kelly drive
A Kelly drive refers to a type of well drilling device on
an oil or gas drilling rig that employs a section of pipe
with a polygonal(three-, four-, six-, or eight-sided) or
splined outer surface, which passes through the
matching polygonal or splined Kelly (mating)bushing
and rotary table.
This bushing is rotated via the rotary table and thus
the pipe and the attached drill string turn while the
polygonal pipe is free to slide vertically in the bushing
as the bit digs the well deeper. When drilling, the drill
bit is attached at the end of the drill string and thus
the kelly drive provides the means to turn the bit.
Fig.: Kelly drive
Parts of Kelly
1) Kelly
2) Kelly bushing

23. 19
3) kelly bypass
4) Kelly cock
5) Kelly driver
6) Kelly saver sub
7) Kelly spinner
Kelly
The heavy square or hexagonal steel member
suspended from the swivel through the rotary table
and connected to the top most joint of drill pipe to
turn the drill stem as the rotary table turns.
Kelly bushing
A device fitted to the rotary table through which the
kelly passes and the means by which the torque of
the rotary table is transmitted to the kelly and to the
drill stem. Also called the drive bushing.
Kelly bypass
A system of valves and piping that allows drilling fluid
to be circulated without the use of the kelly.
Kelly cock
A valve installed at one or both ends of the kelly.
When a high-pressure backflow occurs inside the
drill stem, the valve is closed to keep pressure off the
swivel and rotary hose.
Kelly driver
A device that fits inside the head and inside of which
the kelly fits. The kelly driver rotates with the kelly.
Kelly saver sub
A heavy and relatively short length of pipe that fits in
the drill stem between the kelly and the drill pipe.
The threads of the drill pipe mate with those of the
sub, minimizing wear on the kelly.
Kelly spinner
A pneumatically operated device mounted on top of
the kelly that, when actuated, causes the kelly to
turn or spin.
Rotary Table
The revolving or spinning section of the drill floor
that provides power to turn the drill-string in a
clockwise direction (as viewed from above). The
rotary motion and power are transmitted through
the kelly bushing and the kelly to the drill-string.
When the drill-string is rotating, the drilling crew
commonly describes the operation as simply,
"rotating to the right," "turning to the right," or
"rotating on bottom."
Fig.: Rotary Table
Almost all rigs today have a rotary table, either as
primary or backup system for rotating the drill-string.
Top drive technology which allows continuous
rotation of the drill-string, has replaced the rotary
table in certain operations. A few rigs are being built
today with top drive systems only, and lack the
traditional kelly system.

24. 20
Components
Chain
Most rotary tables are chain driven. These chains
resemble very large bicycle chains. The chains
require constant oiling to prevent burning and
seizing.
Rotary lock
Virtually all rotary tables are equipped with a rotary
lock'. Engaging the lock can either prevent the rotary
from turning in one particular direction, or from
turning at all. This is commonly used by crews in lieu
of using a second pair of tongs to makeup or break
out pipe.
Rotary Bushing
The rotary bushings are located at the centre of the
rotary table. These can generally be removed in two
separate pieces to facilitate large items, i.e. drill bits,
to pass through the rotary table.
Bowl
The large gap in the centre of the rotary bushings is
referred to as the "bowl" due to its appearance. The
bowl is where the slips are set to hold up the drill
string during connections and pipe trips as well as
the point the drill string passes through the floor into
the wellbore
Tong
The large wrenches used for turning when tubing
making up or breaking out drill pipe, casing, tubing,
or other pipe; variously called casing tongs, rotary
tongs, and so forth according to the specific use.
Power tongs or power wrenches are pneumatically
or hydraulically operated tools.
Type of tongs
Mainly three types of tong used in drilling well
practise.
1. Manual Tong
2. Casing Tong
3. Sad manual Tong
Manual Tong
Manual tongs are cast from high quality alloy steel,
heat-treated and MPI tested, and toque test for
manual tongs are always 1.5 times of the rating
torque, manual tongs can be assembled by removing
the hanger and turning the complete tong.
Fig.: Manual Tong
Casing Tong
Casing tongs are widely applied for making-up and
breaking-out of casings or pipes in the drill tool up
and down operation. And the handling size of the
tong can be altered by replacing hinge jaws and
handling shoulders of latch lug jaws.
SDD manual tong
SDD Manual Tongs is used to fasten or remove the
screws of drill tool and casing in well drilling
operation. The handing size of this type tong can be
adjusted by changing latch lug jaws.2.Q4-17/140
SDD Manual Tongs KNm is 140.

25. 21
Drill Pipe
A Drill Pipe is a tube shaped conduit made of steel
that is fitted with specially made threaded ends that
are known as tool joints. Drill that is fitted with a Pipe
provides effective connection to the rig surface
equipment or application with the bit and the
bottom hole assembly for the purpose of pumping
the Drill fluid to the bit. Pipe also helps in connecting
the rig surface equipment for raising, rotating as well
as lowering the bottom hole bit and assembly.
Fig.: Drill pipe
Pipe for drilling provides for the drilling of a well bore
and is available in a number of sizes. Drill pipes also
provide strength and weight and hollow in nature as
it helps the fluid to pass through the Pipe, down the
hole and back up to the annulus. Drill that is case
hardened is helpful in supporting its own weight for
a miscellany of lengths often surpassing a mile down
the earth’s surface and are also expensive.
Drill Pipe helps to make an effective transition to the
drilling collars and pipes by providing flexible
transition. Drill pipes reduce the fatigue failures of
the BHA and add additional weight to the Drill bit.
The drilling pipes comprise a majority of the drilling
strings and measures 15000 foot in length for oil or
gas wells drilled vertically onshore.
Non-magnetic drill pipe is used to isolate
measurement while drilling (MWD) and logging
while drilling (LWD) tools from the drill string. This
minimizes associated electromagnetic interference
and increases the accuracy of the directional surveys.
Hard banding is incorporated on the tool joints and
centre wear pad of the drill pipe in order to increase
the abrasion resistance. Spiral grooves on the
external surface of the drill pipe reduce differential
sticking and improve flow characteristics of the
drilling mud.
Drill pipe is classed as new (N class), becoming
premium (P-class) and finally down to C (C 1 to 3) as
the body outside diameter is worn down by usage.
Eventually the drill pipe will be graded a scrap and
marked with a red band.
Standard drill pipes are long tubular sections of pipe
that make up the majority of the drill string. They are
typically a 31 foot long section of tubular pipe.
Drill pipe comes in a variety of sizes, strengths, and
weights but are typically 27 to 32 feet in length.
Longer lengths, up to 45 feet, exist.

26. 22
Heavy Weight Drill Pipe (HWDP)
Heavy Weight Drill Pipe (HWDP) looks like a normal
drill pipe except for an upset cantered along the tube
which helps to prevent excessive buckling.
HWDP is used as a transitional stiffness section,
typically between the stiff and rigid drill collars and
the relatively light and flexible drill pipe joints to
reduce fatigue failures directly above the bottom
hole assembly.
Its wall thickness is up to 3 times that of a similar-
sized normal drill pipe to add additional weight to
the bit.
Fig.: Heavy weight drill pipe
HWDP is used most commonly in directional drilling
because it bends more easily and helps to control
torque and fatigue in high-angle operations. The
centre upset or wear pad helps in reducing the sticks
in directional drilling.
The HWDP may be directly above the collars in the
angled section of the well, or the HWDP may be
found before the kick off point in a shallower section
of the well.
Conventional Heavy Weight Drill Pipes come in two
configurations.
1. Welded
2. Integral.
The welded configuration is manufactured by friction
welding of extra-long tool joints to a thick well tube.
The integral configuration is machined from a solid
bar of AISI4145H alloy steel.
An additional option is the Heavyweight Spiral Drill
Pipe, which has spiral grooves cut into the external
surface for reduced differential sticking and
improved hole-cleaning.
DRILL COLLARS
Drill collar forms the lowest element of a drill string,
which encompasses all the elements of a down-hole
process from the surface to the rock bit. Drill collars
meant to provide weight for drilling purposes.
The drill Collars are thick walled tube like pieces that
are machined from solid steel bars, although they are
often made from plain carbon steel or the non-
magnetic alloy of copper and steel or other premium
alloys that are non-magnetic in nature. Drill collar
has bars of solid steel that are drilled from one end
to the other to provide a passage for pumping the
drilling fluids through the collar.
These devices are typically 31 feet (about 9.45 m)
long and threaded at both ends, male at one end and
female at the other, to allow multiple drill collars to
be joined above the bit assembly. The number of drill
collars attached to a drill string will depend upon the
material composition of the strata at the drill site and
the likely depth of the well. A relatively shallow well
with less dense geologic structure through which the
bit must pass will require fewer drill collars than a
deep shaft through dense material.
The pressure applied to the drill bit assembly by the
collar and other elements of the drill string must be
carefully regulated for effective drilling. The weight
of the drill string is monitored at the surface, and the
operator slowly lowers the drill string into the hole
until the registered weight changes. If the bit is
resting on the bottom of the hole and the monitor
shows a reduction of 10,000 pounds (4,540 kg), there

27. 23
should be a corresponding increase in pressure on
the drill bit assembly. Typically, drill collars will be
consistent in length but may vary in diameter, and
their outside configuration may be slick or spiral. The
outside diameter may vary from about 3 inches (7.62
cm) to 11 inches (27.9 cm) and greater.
Collars those are available for drilling have an
external diameter that is made of steel and can be
slightly machine perfected for making sure of the
roundedness. The reference to slick or spiral outer
configuration refers to the machining of the outside
surface of the collar.
Fig.: slick surface collar and spiral collar
A slick surface simply refers to a collar machined to a
uniform cylindrical shape.
A spiral collar is machined to have a helical pattern
incised into its outer surface. In directional drilling,
spiral drill collars are preferable. The spiral grooves
machined in the collar reduce the wall contact area
by 40% for a reduction in weight of only 4%, thus
reducing the chances of differential sticking. The
Spiral drill collars usually have slip and elevator
recesses. Stress-relief groove pins and bore back
boxes are optional.
Equipment used in conjunction with drill collars in oil
well drilling includes drill collar slips, drill collar
clamps, and die collars.
The drill collar slip is a device used to handle drill
collars while attaching new sections, and is
adjustable to a variety of diameters.
Drill collar clamps are also used while handling drill
collars to prevent their being dropped into a well
shaft.
In the event a drill string is broken and a drill collar
and bit are at the bottom of the shaft, the die collar
is lowered and with a self-tapping bit, threads an
attaching connection into the drill collar, allowing its
retrieval.
SHORT DRILL COLLARS
Short Drill Collars (SDC's) are also called a pony
collar. It is simply a shortened version of a steel drill
collar. Short drill collars may be manufactured or a
steel drill collar may be cut to make two or more
short collars. For a Directional Driller, the SDC and
the short non-magnetic drill collar (SNMDC) have
their widest application in the make-up of locked
BHAs. SDCs of various lengths (e.g. 5’, 10’, and 15’)
are normally used.
NON-MAGNETIC DRILL COLLARS (NMDC)
Non-magnetic drill collars are usually flush (non-
spiral). They are manufactured from high-quality,
corrosion-resistant, austenitic stainless steel.
Magnetic survey instruments run in the hole need to
be located in a non-magnetic drill collar of sufficient
length to allow the measurement of the earth’s
magnetic field without magnetic interference.
Survey instruments are isolated from magnetic
disturbance caused by steel components in the BHA
and drill pipe.
SHORT NON-MAGNETIC DRILL COLLARS (SNMDC)
They are often made by cutting a full-length NMDC.
The SNMDC may be used between a mud motor and

28. 24
an MWD collar to counteract magnetic interference
from below. It is also used in locked BHAs,
particularly where the borehole's inclination and
direction give rise to high magnetic interference.
Finally, BHAs for horizontal wells often use a SNMDC.
BENDING OF DRILL COLLAR
The amount of bending a drill collar can undergo will
depend on the material and the dimensions of the
collar.
The stiffness of the collar is the product of the collar's
moment of inertia (I) and the modulus of elasticity
for that material (E).
Stiffness= Moment of inertia × Modulus of elasticity
The moment of inertia (I) for a hollow cylindrical pipe
is given by:
𝐼 =
π (D ⁴ – d ⁴)
64
Where,
I = Moment of Inertia (in inch4
)
D = Outside diameter (in inches)
d = Inside diameter (in inches)
The modulus of elasticity for various materials can be
obtained from manufacturer's specifications.
E.g.
For steel E = 29 X 106
psi;
For aluminium E = 11 X 106
psi;
For Monel E = 26 X 106
psi.
Thus, an aluminium drill collar will be more flexible
than a steel drill collar of similar dimensions.
DRILL STABILIZER
Stabilizers are special thick walled drill collar subs
that are placed in the bottom-hole assembly to force
the drill collars to rotate at or near the centre of the
borehole. By keeping the drill collars at or near the
centre of the borehole the drill bit will drill on a
nearly straight course projected by the centre axis of
the rigid BHA.
Stabilizers also prevent differential sticking of the
drill string by stabilizing the BHA and keeping drill
collars and drill pipe away from the borehole wall.
This reduces vibration, drill pipe whirl, and wellbore
tortuosity; moreover, the stabilization maintains
drilling trajectory whether drilling straight,
horizontal, or directional wells.
Stabilizers are also used to ream out doglegs and key
seats.
TYPES OF STABILIZERS
Fig.: Types of stabilizers

29. 25
1) Smooth Body: standard stabilizer with no
blades.
2) Straight Blade: feature welded straight
blades on the body.
3) Spiral Blade: spiral blades provide constant
wall contact to assist in cutting removal.
4) Straight-Spiral Blade: designed to provide
the benefits of the spiral blade stabilizer at a
reduced cost.
5) Flow Through: allows cuttings to pass
between the inner and outer barrel.
INTEGRAL BLADE STABILIZERS
Integral blade stabilizers are made from high-
strength alloy steel as a single piece tool. They are
rolled and machined to provide the blades. The
unitized construction features three spiralled ribs
designed to minimize down hole torque, reduce
damage to the hole wall and ensure maximum fluid
circulation. It is well suited for use in most
formations from soft and sticky to hard and abrasive.
Fig.: Integral blade stabilizers
They can have either three or four blades. I.B.
stabilizers normally have tungsten carbide inserts
(TCIs). The blades are an integral part of the tool
body, eliminating the risk of leaving components or
pieces in the hole Available in both open and full
wrap designs, providing optimum-hole wall contact
while ensuring maximum fluid bypass area.
WELDED BLADE STABILIZERS:
The Welded Blade Stabilizers used in the B.H.A for
drilling soft to medium hard formation holes are
available in three types (straight, straight-offset or
spiral design).They are best suited to large hole sizes
where the formation is softer because they allow
maximum flow rates to be used.
Fig.: Welded blade stabilizers
Mid steel blades are welded onto the body using
strictly controlled pre-heating, post weld heat
treatment and weld application techniques. All areas
affected by the process of welding are subject to full
non-destructive examination to assure the
mechanical integrity of the joint. Standard Welded
Blade Stabilizers are available in 3 or 4 blade
configuration with the spiral type available with
open or tight spiral.
IBS are more expensive than welded blade type
stabilizers, since they are machined from one piece
of metal.

30. 26
VARIABLE BLADE STABILIZER
The Variable Blade Stabilizer ensures smooth and
efficient pipe cutting operations, reducing the shock
load on cutting knives, arms and the entire fishing
string by centralizing the milling equipment in the
hole.
This tool is designed to stabilize pipe cutters in large
bore cutting operations, and its replaceable blades
make dressing for different sizes of casing a quick
and easy process. Stabilizer blades are readily
replaced by removing two locking pins.
Reduces shock load on cutting knives, arms and
fishing String Stabilizer blades change quickly to
dress for different casing sizes
Fig.: Variable blade stabilizer
Large bore cutting operations where work string
shock load must be controlled Cutting multiple
eccentric strings, requiring an interrupted cutting
strings of varying inside diameter.
SLEEVE TYPE STABILIZERS
These consist of replaceable sleeves that are
mounted on the stabilizer body. They offer the
advantage of changing out a sleeve with worn blades
or replacing it with one of another gauge size. The
blades can be dressed with tungsten carbide inserts
for abrasive formations.
There are two main designs of sleeve-type stabilizer
as shown in figure: Two-piece stabilizer (mandrel and
sleeve):
The sleeve is screwed onto the coarse threads on the
outside of the mandrel and torqued up to the
recommended value. Sleeve makeup torque is low.
There is no pressure seal at the sleeve. It is
convenient to change sleeves on the drill floor. It is
in wide use today.
Fig.: Sleeve type stabilizers
Three-piece stabilizer (mandrel, sleeve and saver
sub):
The sleeve is screwed onto the mandrel first, by
hand. The saver sub is then screwed into the mandrel
and this connection is torqued up to the
recommended value.
Great care must be taken otherwise downhole
washouts etc. will result. It can be quite difficult and
time-consuming to change/service the sleeve. For
these reasons, this design of sleeve-type stabilizer is
not as widely used today.

31. 27
NON- ROTATING STABILIZER
These stabilizers are used to centralize the drill
collars, but the rubber sleeve allows the string to
rotate while the sleeve remains stationary. The wear
on the blades is therefore much less than in other
stabilizers and so they can be used in harder
formations.
Stabilizers can be installed just above the bit or at
any point within the BHA (string stabilizers).
Fig.: Non rotating stabilizer
NON MAGNETIC STABILIZERS
Non-magnetic Stainless steel drills Stabilizers that
are especially designed to amplify speed and pace of
penetration thereby controlling the deviation are
rather cost-effective. These help in reducing the
drilling costs per foot. There are also alloy stabilizer
kinds available in the market that is customized to
heat-treated steel for variety of configurations and
sizes of holes that can be drilled.
DOWN HOLE MUD MOTORS
There are two major types of downhole motors
powered by mud flow:
1) The turbine, which is basically a centrifugal
or axial pump
2) The positive displacement mud motor
(PDM).
Fig.: Axial pump
The principles of operation are shown in Figure and
the design of the tool are totally different. Turbines
were in wide use a number of years ago and are
seeing some increased use lately but the PDM is the
main workhorse for directional drilling
Fig.: Positive displacement pump
Components
All drilling motors consist of five major assemblies:
1) Dump Sub Assembly
2) Power Section
3) Drive Assembly
4) Adjustable Assembly
5) Sealed or Mud Lubricated Bearing Section.

32. 28
Dump Sub Assembly
As a result of the power section (described below),
the drilling motor will seal off the drill string ID from
the annulus. In order to prevent wet trips and
pressure problems, a dump sub assembly is utilized.
The dump sub assembly is a hydraulically actuated
valve located at the top of the drilling motor that
allows the drill string to fill when running in hole, and
drain when tripping out of hole. When the pumps are
engaged, the valve automatically closes and directs
all drilling fluid flow through the motor. In the event
that the dump sub assembly is not required, such as
in underbalanced drilling using nitrogen gas or air,
it’s effect can be negated by simply replacing the
discharge plugs with blank plugs. This allows the
motor to be adjusted as necessary, even in the field.
Fig.: Down hole mud motor
Power Section
The drilling motor power section is an adaptation of
the Moniteau type positive displacement hydraulic
pump in a reversed application. It essentially
converts hydraulic power from the drilling fluid into
mechanical power to drive the bit.
The power section is comprised of two components;
the stator and the rotor. The stator consists of a steel
tube that contains a bonded elastomer insert with a
lobed, helical pattern bore through the centre. The
rotor is a lobed, helical steel rod.
Drive Assembly
Due to the design nature of the power section, there
is an eccentric rotation of the rotor inside of the
stator. To compensate for this eccentric motion and
convert it to a purely concentric rotation drilling
motors utilize a high strength jointed drive assembly.
The drive assembly consists of a drive shaft with a
sealed and lubricated drive joint located at each end.
The drive joints are designed to withstand the high
torque values delivered by the power section while
creating minimal stress through the drive assembly
components for extended life and increased
reliability.
The drive assembly also provides a point in the drive
line that will compensate for the bend in the drilling
motor required for directional control.
Adjustable Assembly
The adjustable assembly can be set from zero to
three degrees in varying increments in the field. This
durable design results in wide range of potential
build rates used in directional, horizontal and re-
entry wells. Also, to minimize the wear to the
adjustable components, wear pads are normally

33. 29
located directly above and below the adjustable
bend.
Sealed or Mud Lubricated Bearing Section
The bearing section contains the radial and thrust
bearings and bushings. With a sealed assembly the
bearings are not subjected to drilling fluid and should
provide extended, reliable operation with minimal
wear. As no drilling fluid is used to lubricate the
drilling motor bearings, all fluid can be directed to
the bit for maximized hydraulic efficiency. This
provides for improved bottom-hole cleaning,
resulting in increased penetration rates and longer
bit life. The mud lubricated designs typically use
tungsten carbide- coated sleeves to provide the
radial support. Usually 4% to 10% of the drilling fluid
is diverted pass this assembly to cool and lubricate
the shaft, radial and thrust bearings.
Bearing housings are also available with two
stabilization styles, integral blade and screw-on. The
integral blade style is built directly onto the bearing
housing and thus cannot be removed in the field. The
screw-on style provides the option of installing a
threaded stabilizer sleeve onto the drilling motor on
the rig floor in a matter of minutes. The drilling
motor has a thread on the bottom end that is
covered with a thread protector sleeve when not
required. Both of these styles are optional to a
standard bladed bearing housing.
Drilling Motor Operation
In order to get the best performance and optimum
life of drilling motors, the following standard
procedures should be followed during operation.
Slight variations may be required with changes in
drilling conditions and drilling equipment, but
attempts should be made to follow these procedures
as closely as possible.
Rotary Steerable System (RSS)
RSS is a new form of drilling technology used in
directional drilling. It employs the use of specialized
downhole equipment to replace conventional
directional tools such as mud motors. They are
generally programmed by the MWD engineer or
directional driller who transmits commands using
surface equipment, which the tool understands and
gradually steers into the desired direction.
Fig.: Rotary steerable system
To initiate a change in the wellbore trajectory with
steerable motors, the drilling rotation is halted in
such a position that the bend in the motor points in
the direction of the new trajectory. This mode,
known as the sliding mode, typically creates higher
frictional forces on the drill-string. In extreme
extended reach drilling (ERD), the frictional force
builds to the point at which no axial weight is
available to overcome the drag of the drill-string
against the wellbore, and, thus, further drilling is not
possible.
To overcome this limitation in steerable motor
assemblies, the RSS was developed. RSS allow
continuous rotation of the drill-string while steering
the bit. Thus, they have better penetration rate, in
general, than the conventional steerable motor
assemblies. Other benefits include better hole
cleaning, lower torque and drag, and better hole
quality. RSSs are much more complex mechanically
and electronically and are, therefore, more
expensive to run compared to conventional
steerable motor systems. This economic penalty
tends to limit their use to highly demanding

34. 30
extended-reach wells or the very complex profiles
associated with designer wells.
There are two steering concepts in the RSS
1. Point the bit
2. Push the bit
The point-the-bit system uses the same principle
employed in the bent-housing motor systems. In
RSSs, the bent housing is contained inside the collar,
so it can be oriented to the desired direction during
drill-string rotation. Point-the-bit systems claim to
allow the use of a long-gauge bit to reduce hole
spiralling and drill a straighter wellbore.
The push-the-bit system uses the principle of
applying side force to the bit, pushing it against the
borehole wall to achieve the desired trajectory. The
force can be hydraulic pressure or in the form of
mechanical forces.
In general, either a point-the-bit or a push-the-bit
RSS allows the operator to expect a maximum build
rate of approximately 6 to 8°/100 foot for the 8½-in.-
hole-sized tool.
Substitutes
Subs are generally part of most drill strings and have
two main functions
 To cross-over connections
 As a disposable component or/and to extend
the life of a more expensive drill stem
member.
This means that subs have to be manufactured from
selected bars of alloy steel, heat-treated to provide
the strength and toughness required to carry the
entire weight of the drill-string or to withstand high
torque differentials.
Types of rotary sub
Fig.: Types of subs
Bit Subs or Crossover Subs
They are used to connect the drill bit to the first
piece of BHA equipment or to cross-over
connections in the drill string, Drill bits are
manufactured with a pin making make-up impossible
without a bit sub. It is used just above the bit and
serves as crossover between the drill collar
connection and the bit connection.
Lift Subs or Handling Subs
They are used to lift BHA components from the
catwalk to the rig floor

35. 31
Top Drive Subs or Saver Subs
They serve as the sacrificial element between the
drill string and the top drive, reducing repair and
maintenance costs
Workover Subs or Circulating Subs
They are used to limit the allowable fluid-circulation
rates
Float Sub
A float sub has a body which contains a float valve
which is basically a one way fluid valve that allows
drilling fluids to pass out of the drill string and into
the bit, but doesn't allow those fluids to back flow
into the drill string.
Directional Bent sub
The Directional Bend Sub is a mainly deflecting tool
with a down hole drilling motor. The down hole
drilling motor bring to bear side force on bit with the
directional bend sub action. The bit lateral cut
borehole wall side continuously. The well track will
be a curve.
The Shock Sub
It impact and vibration reduction sub is a drill string
component that absorbs and dampens the variable
axial dynamic loads produced by the drill bit during
routine drilling and milling operations. It is most
beneficial when drilling in hard rock, broken
formations, and intermittent hard and soft streaks.
DRILL BIT
In the oil and gas industry, a Drill bit is a tool designed
to produce a generally cylindrical hole (wellbore) in
the earth’s crust by the rotary drilling method for the
discovery and extraction of hydrocarbons such as
crude oil and natural gas.
A drilling bit is the cutting tool which is made up on
the end of the drill string. This type of tool is
alternately referred to as a rock bit, or simply a bit.
The hole diameter produced by drill bits is quite
small compared to the depth of the hole produced.
The bit drills through the rock by scraping, chipping,
gouging or grinding the rock at the bottom of the
hole. Drilling fluid is circulated through passageways
in the bit to remove the drilled cuttings.
Types of Drill Bits
There are however many variations in the design of
drill bits and the bit selected for a particular
application will depend on the type of formation to
be drilled.
Drill bits are broadly classified into two main types
according to their primary cutting mechanism.
1. Drag bit
2. Roller Cone bit (Rock bit)
3. Diamond bit
Drag bit
Drag bits were the first bits used in rotary drilling, but
are no longer in common use. A drag bit consists of
rigid steel blades shaped like a fish-tail which rotate
as a single unit.
Roller cutter bit
Roller cutter bit also known as Rolling cutter bits drill
largely by fracturing or crushing the formation with
“tooth” shaped cutting elements on two or more
cone-shaped elements that roll across the face of the
bore hole as the bit is rotated.
The first commercially successful rolling cutter drill
bit design was disclosed in U.S. patents granted to
Howard R. Hughes, Sr. on August 10, 1909.

36. 32
Fig.: Rotary cutter bit
Modern commercial rolling cutter bits usually
employ three cones to contain the cutting elements,
although two cone or (rarely) four cone
arrangements are sometimes seen.
This type of bit mainly fall into two class
1. Milled steel teeth
2. Tungsten carbide inserts
Milled steel tooth cutters are an integral part of the
bit cone. Soft formation bits have long, relatively thin
teeth that are spaced widely apart on the cone. This
configuration promotes a gouging/scraping action
that results in high penetration rates with minimal
weight on bit. Unfortunately, these long teeth are
especially susceptible to breakage in harder rock.
Tungsten carbide inserts, as their name implies, are
not part of the cone material. Rather, they are
separate elements, pressed into specially machined
holes in the cone. They can be placed either as gauge
inserts (along the outside of the cone) or inner row
inserts.
Fixed cutter bits employ a set of blades with very
hard cutting elements, most commonly natural or
synthetic diamond, to remove material by scraping
or grinding action as the bit is rotated.
Working
As the bit comes into contact with the bottom of
hole, its crush the rock and the high-velocity fluid jet
strikes the crushed rock chips to remove them from
the bottom of the hole. As this occurs, another tooth
makes contact with the bottom of the hole and
creates new rock chips. Thus, the process of chipping
the rock and removing the small rock chips with the
fluid jets is continuous.
The cones rotate on roller or journal bearings that
are usually sealed from the hostile down-hole drilling
fluid environment by different arrangements of O-
ring or metal face seals. These bits usually also have
pressure compensated grease lubrication systems
for the bearings.
Diamond bit
Diamond bit also known as fixed cutter bits employ a
set of blades with very hard cutting elements, most
commonly natural or synthetic diamond, to remove
material by scraping or grinding action as the bit is
rotated.
Fig.: Diamond bits

37. 33
They are mechanically much simpler than rolling
cutter bits. The cutting elements do not move
relative to the bit; there is no need for bearings or
lubrication.
The most common cutting element in use today is
the polycrystalline diamond cutter (PDC), a sintered
tungsten carbide cylinder with one flat surface
coated with a synthetic diamond material.
Other fixed cutter bits may employ natural
industrial-grade diamonds or thermal stable
polycrystalline diamond (TSP) cutting elements.
There is also currently available, a “hybrid” type of
bit that combines both rolling cutter and fixed cutter
elements.
Parameters considered while designing of drill bits
Regardless of type, drill bits must satisfy two primary
design goals:
1. To maximize the rate of penetration (ROP) of
the formation
2. To provide a long service life.
If the bit fails or wears out, it must be recovered and
replaced by removing the perhaps several miles of
the drill pipe to which it is attached. During this time,
known as a “trip”, the depth of the hole is not
advanced, but much of the operating costs are still
incurred. For this reason, the effectiveness of a bit is
often measured in drilling cost (in dollars) per foot of
hole drilled, where a lower number indicates a
higher performing bit.
The ability of a bit design to satisfy the two primary
goals is constrained by a number of factors
1. Most importantly the wellbore
diameter.
2. Formation type (hardness, plasticity,
abrasiveness) to be drilled
3. Operating environment at depth
(temperature, pressure, corrosiveness)
4. The capabilities of the equipment used
to drive the bit (rotating speed, available
weigh on bit)
5. The direction of the wellbore (vertical,
directional, horizontal).
Most rolling cutter and fixed cutter drill bits have
internal passages to direct drilling fluid, conveyed by
the drill pipe from surface pumps, through hydraulic
nozzles directed at the bottom of the wellbore to
produce high velocity fluid jets that assist in cleaning
of the borehole. Placement of the nozzles,
particularly in rolling cutter bits, is also often done to
assist in keeping the cutting elements free of cutting
build-up in certain kinds of clay and shale formations.
Drilling fluid (mud) handling Equipment
Drilling fluid (mud)
Fig.: Circulation system
Function of drilling fluid
 Remove cuttings from well bore
 Keep cuttings in suspension
 Control formation Pressure
 Maintain Well bore stability
 Seal permeable formation
 Minimize formation damage

38. 34
 Cool, lubricate & support bit and Drilling
assembly
 Control corrosion
Equipment used or circulating and operator the
mud system
1. Mud tanks
2. Supercharger
3. Mud pump
4. Bell nipple
5. shale shaker
6. Desander
7. Desilter
8. Degasser ……ETC
Mud Tanks
A mud tank is an open-top container, typically made
of square steel tube and steel plate, to store drilling
fluid on a drilling rig. They are also called mud pits,
because they used to be nothing more than pits dug
out of the earth. Based on functions, mud tank
includes metering tank, circulating tank, chemical
tank, aggravating tank, precipitating tank, storing
tank, etc.
Fig.: Mud Tank
• Metering tank is used for perfusion fluid
metering.
• Circulating tank is used in store normal
operation of circulating drilling fluid during
drilling process. Normally the shale shaker
and vacuum degasser and desander are
mounted together on the same circulating
tank, while desilter and centrifuge on the
second circulating tank.
• Chemical tank's roof is mounted with shear
pump. Chemical tanks are used for adding
chemicals into drilling fluid.
• Aggravating tank is used to configure
weighted drilling fluid.
• Reserve tank used for storing drilling fluid
The mud tank surface and the passage are made of
the slipping resistant steel plate. The mud tanks are
made of the side steel pipe, all of the structure can
be folded without barrier and pegged reliably. The
surface of tank is equipped with water pipe line for
cleaning the surface. The ladder is made of the
channel steel to take responsibility the body, the foot
board is made of the linearity netted steel plate. The
two-sided guard rail are installed the safe suspension
hook. The mud tank is designed the standard shanty
to prevent the sand and the rain.
Mud tank cleaning
Mud tank cleaning is mandatory to avoid cross-
contamination when displacing one fluid with
another. There are commonly two method be used.
1. Labour-intensive process:
Historically, the cleaning of mud tanks and pits
typically involved labourers equipped with hoses,
pressure washers, shovels, and squeegees – a
process some liken to an archaic bucket brigade.
2. Automated mud cleaning
Portable automatic tank cleaning (ATC) units are
equipped with pumps, tanks, cones and

39. 35
programmable logic controllers (PLCs) that supply
wash solution to the tank cleaning machines (TCMs),
which actually are specialized nozzles. Usually,
multiple cleaning machines are placed permanently
inside the tanks with the precise number and
placement dependent on the cleaning pattern and
the geometry of the particular tank.
When cleaning is to take place, a portable ATC unit is
brought on board where the cleaning machines are
connected to the ATC skid containing pumps that
send a mixture of surfactant and water to the
individual cleaning machines. The automated
technology uses specialized chemicals that prevent
the formation of emulsions and provide easy
separation of the wash water for recycling.
During the operation, powerful water jets follow a
specially programmed cleaning pattern to clean
every surface inside the tank. The programmed
pattern can be regulated according to the tank
design and cleaning needs.
Liquid is directed back to the cleaning machines to
be reused as cleaning fluid until it becomes too
contaminated with fine solids. At the end of the
operation, the cleaning fluid and solid waste,
predominantly comprising barite weight material are
safely removed from the installation or reused in a
new drilling fluid.
Mud pump
A mud pump is a reciprocating piston/plunger device
designed to circulate drilling fluid under high
pressure (up to 7,500 psi (52,000 kPa)) down the drill
string and backup the annulus.
Parts of mud pump
1. Housing it self
2. liner with packing
3. Cover plus packing
4. Piston and piston rod
5. Suction valve and discharge valve with
their seats
6. Stuffing box (only in double-acting
pumps)
7. Gland (only in double-acting pumps)
8. Pulsation dampener.
Fig.: Mud pump
Classification of mud pump
 According to action type
1) Single Action type:
In single acting pump, there is one suction valve and
one delivery valve. On the backward stroke of the
piston, the suction valve opens and mud enters into
the cylinder space. On the forward stroke, the
suction valve close sand delivery valve opens, the
mud is forced through the delivery pipe.
2) Double Acton type:
In the double acting pump, there are two suction
valves and two delivery vales one in the front and
one in the rear. When the piston moves backward,
the suction valve in the front opens and delivery

40. 36
valve in the rear opens and mud is forced through it.
When the piston moves forward, the suction valve in
the rear opens and delivery valve in the front opens
and mud is forced through it.
 According to quantity of liners
1. Duplex pump
The duplex pumps have two cylinders with double
acting. It means that pistons move back and take in
drilling mud through open intake valve and other
sides of the same pistons, the pistons push mud out
through the discharge valves.
Fig.: Duplex pump
1. Duplex pump
When the piston rod is moved forward, one of intake
valves is lift to allow fluid to come in and one of the
discharge valve is pushed up therefore the drilling
mud is pumped out of the pump. On the other hand,
when the piston rod is moved backward drilling fluid
is still pumped. The other intake and discharge valve
will be opened.
2. Triplex pump
The triplex pumps have three cylinders with single
acting. The pistons are moved back and pull in drilling
mud through open intake valves. When the pistons
are moved forward and the drilling fluid is pushed
out through open discharge valves.
Fig.: Triplex pump
One cylinder of triplex pump (there are three such
cylinder in triplex pump)
When the piston rods are moved forward, the intake
valves are in close position and the discharge valves
are in open position allowing fluid to discharge. On
the contrary when the piston rods are moved
backward, the intake valve are opened allowing
drilling fluid coming into the pump.
Performance parameters
There are two main parameters to measure the
performance of a Mud Pump:

41. 37
 Displacement
Displacement is calculated as discharged in litres per
minute, it is related with the drilling-hole diameter
and the return speed of drilling fluid from the bottom
of the hole, i.e. the larger the diameter of drilling
hole, the larger the desired displacement. The return
speed of drilling fluid should reach the requirement
that can wash away the debris and rock powder cut
by the drill from the bottom of the hole in a timely
manner, and reliably carry them to the earth surface.
When drilling geological core, the speed is generally
in range of 0.4 to1.0 m^3/min.
• Pressure
The pressure size of the pump depends on the depth
of the drilling-hole, the resistance of flushing fluid
(drilling fluid) through the channel, as well as the
nature of the conveying drilling fluid. The deeper the
drilling hole and the greater the pipeline resistance,
the higher the pressure needed.
With the changes of drilling-hole diameter and
depth, it requires that the displacement of the pump
can be adjusted accordingly. In the Mud Pump
mechanism, the gearbox or hydraulic motor is
equipped to adjust its speed and displacement. In
order to accurately grasp the changes in pressure
and displacement, a flowmeter and pressure gauge
are installed in the Mud Pump.
Standpipe
Rig stand pipe is a solid metal pipe attached to the
side of a drilling rig's derrick that is a part of its
drilling mud system. It is used to conduct drilling
fluid from the mud pumps to the kelly hose.
It must be pressure-tested to the working pressure
of the BOP’s.
Fig.: Stand pipe
Components
Bull plugs
Fig.: Bull plug

42. 38
Pressure transducer:
Fig.: Pressure transducer
Valves
Fig.: Valves
Standpipe manifold
This manifold is at upstream side of the mud pups.
Its purpose is to divert the flow of mud in desired
path towards the drill line or toward the drill string
it also has the connection ports where pressure the
temperature sensor are connected.
Fig.: Standpipe manifold
Bell nipple
Fig.: Bell nipple

43. 39
A Bell nipple is a section of large diameter pipe fitted
to the top of the blowout preventers that the flow
line attaches to via aside outlet, to allow the drilling
fluid to flow back over the shale shakers to the mud
tanks.
Every conventional land drilling rig uses some form
of bell nipple flange connected at the top of the
blowout preventer (BOP) stack. This flange does not
hold well pressure, but acts as a fastening device to
connect a vertical pipe, referred to as a bell nipple,
to the top of the BOP stack.
Shale shaker
Fig.: Shale shaker
The shale shaker is a vibrating machine using a very
fine mesh that separates the cuttings from the fluid.
The mesh is often divided into six or eight sections,
each mounted on a frame, called shaker screens.
Shale shakers are components of drilling equipment
used in many industries, such as coal cleaning,
mining, oil and gas drilling. They are the first phase
of a solids control system on a drilling rig, and are
used to remove large solids cuttings from the drilling
fluid.
After returning to the surface of the well the used
drilling fluid flows directly to the shale shakers where
it begins to be processed. Once processed by the
shale shakers the drilling fluid is deposited into the
mud tanks where other solid control equipment
begin to remove the finer solids from it. The solids
removed by the shale shaker are discharged out of
the discharge port into a separate holding tank
where they await further treatment or disposal.
Shale shakers consist of the following parts:
1. Hopper
2. Feeder
3. Shaker Base
4. Screen Basket
5. Basket Angling Mechanism
6. Vibrator
7. Locking device
8. Shock Spring
9. Shaker Screen
Shale shaker may be classified by the type of motion
produced by machine as below:
A) Elliptical Unbalanced design
B) Circular Balanced design
C) Linear straight-line design
Elliptical Unbalanced design
The unbalanced, elliptical motion machines have a
downward slope and shown in the diagram above, A.
This slope is required to properly transport cuttings
across the screen and off the discharge end.
However, the downward slope reduces fluid
retention time and limits the capacity of this design.

44. 40
Optimum screening with these types of shakers is
usually in the 30-40 mesh (400-600 micron) range.
Fig.: types of shale shaker
Circular Balanced design
The next generation of machine, introduced into the
oilfield in the late 1960s and early 1970s, produces a
balanced or circular motion. The consistent, circular
vibration allows adequate solids transport with the
basket in a float horizontal orientation, as shown in
the diagram above, B. This design often incorporates
multiple decks to split the solids load and to allow
finer mesh screens, such as 80-100 square mesh
(150-180 micron) screens.
Linear straight-line design
The newest technology produces linear, or straight-
line, motion, C in the diagram above. This motion is
developed by a pair of eccentric shafts rotating in
opposite directions; linear motion provides superior
cuttings conveyance and is able to operate at an
uphill slope to provide improved liquid retention.
Better conveyance and longer fluid retention allow
the use of 200 square mesh (74 micron) screens.
Desander
Desander Hydro-cyclones are used to provide
efficient and reliable separation of sand and solids
from Produced Water, Condensate and/or Gas
streams. They have proven to be a valuable part of
many Oil and Gas production facilities, by providing:
 High Efficiency Solids Removal
 Compact, small footprint
 Cost effective protection against erosion
damage
 No moving parts and minimal maintenance
 Highly consistent performance.
Fig.: Desander

45. 41
Operating Principle
Desander Cyclones are pressure-driven separators
that require a pressure drop across the unit to cause
separation of the solids from the bulk phase (water,
oil or gas, etc).
The inlet stream (containing solids) enters the
cyclone through a tangential Inlet Section under
pressure, where it is forced into a spiral motion by
the cyclone’s internal profile. The internal cone
shape causes the spinning to accelerate, which
generates high centrifugal forces, causing the denser
solid particles to move to the outer wall of the
Cyclone, while the Water/Oil/Gas is displaced to the
central core.
Fig.: mechanism diagram of Desander
Solids continue to spiral down along the outer wall of
the conical section inside the Cyclone to the Outlet
or Underflow, where they exit. It is typical to collect
the solids in a closed underflow container or vessel,
and periodically dump these solids.
De-sanded Water/Oil/Gas in the central core section
reverses direction and is forced out through the
central Vortex Finder at the top of the Cyclone as the
Overflow.
Factors involved in the selection of Desander Cyclone
are
 Desired particle size removal (in micron)
 Temperature/Viscosity of the Water/Liquid
 Liquid density
 Solids density
 Volume to be treated,
 Available pressure/pressure drop to drive
cyclone
Particle Size Removal
The rule in selecting a Desander cyclone size is that
smaller cyclones remove smaller particles.
Temperature/Viscosity
Temperature of the water/liquids is very important,
as higher temperature reduces liquid viscosity, which
improves separation by reducing the drag forces on
the particles.
Liquid Density
Water Density is ~1.0, although it varies slightly
according to temperature, salt concentrations, etc.
Oil can vary from 0.6 - 0.99 S.G.
Solids Density
The solids density seen in production fluids has a
typical density ~2.2 - 2.65 S.G. This density directly
effects separation potential, with higher density
solids being more easily separated. There can be a
range of different types of solids with a range of
densities, although there is typically one major
component.
Pressure drop
Cyclones can be installed to operate at any pressure.
They use pressure as the energy for separation, and
the pressure drop (across the cyclone) required for

46. 42
solids removal is 15 – 70 psi. (1.0 – 4.8 Bar), as this
range provides optimum performance, while
minimising erosion and pressure loss.
Mud gas separator (Degasser)
Mud Gas Separator is commonly called a gas-buster
or poor boy degasser. It captures and separates
large volume of free gas within the drilling fluid. If
there is a "KICK" situation, this vessel separates the
mud and the gas by allowing it to flow over baffle
plates. The gas then is forced to flow through a line
and vent it to a flare. A "KICK" situation happens
when the annular hydrostatic pressure in a drilling
well temporarily (and usually relatively suddenly)
falls below that of the formation, or pore, pressure
in a permeable section downhole, and before
control of the situation is lost.
Fig.: Degasser
Function
The mud/gas separator is designed to provide
effective separation of the mud and gas circulated
from the well by venting the gas and returning the
mud to the mud pits. Small amounts of entrained
gas can then be handled by a vacuum-type degasser
located in the mud pits. The mud/gas separator
controls gas cutting during kick situations, during
drilling with significant drilled gas in the mud
returns, or when trip gas is circulated up.
Types of mud-gas separator
1) Closed type
2) Open type
3) Float
Closed type
The closed-bottom separator, as the name implies,
is closed at the vessel bottom with the mud return
line directed back to the mud tanks. 1. Mud leg is
maintained in the separator by installation of an
inverted U-shaped bend in the mud return line.
Fluid level can be adjusted by increasing/decreasing
the length of the U-shaped bend.
Open Type
The open-bottom mud/gas separator is typically
mounted on a mud tank or trip tank with the
bottom of the separator body submerged in the
mud. The fluid level (mud leg) in the separator is
controlled by adjusting the fluid level in the mud
tank or by moving the separator up or down within
the tank. Mud-tank height can restrict the
maximum mud leg obtainable for open-bottom
mud/gas separators.
Float Type
Fluid level (mud leg) is maintained in a float-type
mud/gas separator by a float/valve configuration.
The float opens and closes a valve on the mud
return line to maintain the mud-leg level. Valves can
be operated by a manual linkage system connected
from the float to the valve, or the valve can be air-
operated with rig air.

47. 43
Well-control system
The function of the well control system is to prevent
the uncontrolled flow of the formation fluids from
the wellbore. When the drill bit enter a permeable
formation the pressure in the pore space of the
formation may be greater than the hydrostatic
pressure exerted by the mud column. If this is so,
formation fluid will enter the wellbore and start
displacing mud from the hole. Any influx of
formation fluid in the borehole is known as a kick.
The well control system is designed to
 Detect a kick
 Close- in the wall
 Remove the formation fluid which has flow
into the well
 Make the well safe
Failure to do this results in the uncontrolled flow of
fluid known as Blow-out which may cause loss of
lives and equipment, damage to the environment
and the loss of oil or gas receiver.
Blow out Preventer (BOP)
When the formation pressure is higher than that of
the drilling fluid pressure the fluid from the well try
to come out of the well it’s known as kick. And
uncontrolled flow of the gas and oil from the well is
known as Blow-out. Blow out preventer is one of the
most important component of the rig and it has been
tasted regularly to ensure it’s proper working
condition.
Blowout preventer equipment should be designed to
1. Close the top of the hole.
2. Control the release of fluids.
3. Permit pumping into the hole.
4. Allow movement of the inner string of pipe.
Fig.: Blow out preventer system
Types of BOP
1) Annular Blow out preventers
2) Ram Blow out preventers
3) Rotational Blow out preventers
4) Diverters Blow out preventers
Annular blowout preventer
The annular blowout preventer is installed at the top
of the BOP stack and has the capability of closing
(sealing off) on anything in the bore or completely
shutting off (CSO) the open hole by applying closing
pressure.
The sealing device of an annular blowout preventer
is referred to as the “packing element”. It is basically
a donut-shaped element made out of elastomeric
material. To reinforce the elastomeric material,
different shapes of metallic material are molded into
the element. This keeps the elastomeric material

48. 44
from extruding when operating system pressure or
wellbore pressure is applied to the bottom of the
packing element. Since the packing element is
exposed to different drilling environments (i.e.,
drilling fluid/mud, corrosive H2S gas and/or
temperature of the drilling fluid), it is important to
make sure that the proper packing element is
installed in the annular preventer for the anticipated
environment of the drilling operation.
During normal wellbore operations, the preventer is
kept fully open by applying hydraulic pressure to
position the piston in the open (down) position. This
position permits passage of drilling tools, casing, and
other items which are equal to the full bore size of
the BOP. The blowout preventer is maintained in the
open position by relaxing all hydraulic control
pressures to the closing chamber and applying
hydraulic pressure to the opening chamber.
Application of hydraulic pressure to the opening
chamber ensures positive control of the piston.
Ram-type blowout preventer
A ram-type blowout preventer is basically a large
bore valve. The ram blowout preventer is designed
to seal off the wellbore when pipe or tubing is in the
well. In a BOP stack, ram preventers are located
between the annular BOP and the wellhead.
The number of ram preventers in a BOP stack ranges
from one to eight depending on application and
water depth. Flanged or hubbed side outlets are
located on one or both sides of the ram BOPs. These
outlets are sometimes used to attach the valved
choke and kill lines too. The outlets enter the
wellbore of the ram preventer immediately under
the ram cavity.
Other than sealing off the wellbore, rams can be
used to hang-off the drill string. A pipe ram, closed
around the drill pipe with the tool joint resting on the
top of the ram, can hold up to 600,000 lb of drill
string.
Several different types of rams are installed in the
ram type BOP body. The five main types of rams are
blind rams, pipe rams, variable bore rams, shearing
blind rams, and casing shear rams. Following is a
brief description of each type
 Blind rams: Rubber sealing element is flat
and can seal the wellbore when there is
nothing in it, i.e., “open hole”.
 Pipe rams: Sealing element is shaped to fit
around a variety of tubulars with a particular
diameter, which include production tubing,
drill pipe, drill collars, and casing that will
seal off the wellbore around it.
 Variable bore rams: Sealing element is much
more complex and allows for sealing around
a particular range of pipe sizes,
 Shearing blind rams: Blade portion of the
rams shears or cuts the drill pipe, and then a
seal is obtained much like the blind ram.
 Casing shear rams: Casing shear rams are
typically shearing rams only and will not seal.
They are specifically designed to cut large
diameter tubulars that are incapable of
being sheared by blind shear rams.
Rotational BOP
Rotational preventers are used
 For drilling in layers that are suspected to
cause possible kick off.
 When drilling on the balance or under
balanced (drilling the rocks of great
permeability or porosity; to avoid pollution
with mud).