1. DECLARATION
I hereby declare that the work presented in this dissertation entitled “TECHNICAL
STUDY ON DIRECTIONAL DRILLING MOTOR” is my original work and wholly carried
out by me. I further declare that it has not been submitted earlier in part or in
whole, to any University, Institution or Organization for the award of any degree.
Station: KAKINADA (SURESH SANAPATHI)
Date: Reg. no- 709212345011
Student’s Signature
1

2. CERTIFICATION
This is to certify that Mr. SURESH SANAPATHI, M-Tech II year student of DELTA
STUDIES INSTITUTE, Andhra University, Visakhapatnam has undergone a major
project work on the topic-
“TECHNICAL STUDY ON DIRECTIONAL DRILLING MOTOR”
From December 1st 2010 to January 1st, 2010 under the guidance of
undersigned of Mr.Sandeep Amin Lead technician , Weatherford Oil Tool M.E
Ltd.
He had been introduced to a complete gamut”TECHNICAL STUDY ON
DIRECTIONAL DRILLING MOTOR” through practical works and theoretical
lectures by the subject experts.
His involvement in the learning, studying as well as documentation was
noticeably good and his conduct during the above period was excellent. I
hope he can make better use of the knowledge and skills thus he gained.
I wish him success in his future endeavors.
Internal Guide
Prof. M. Jagannadha Rao
M.Sc. (Tech), M.S. Engg. (USA), Ph.D.
Director
Delta Studies Institute
College of Science and Technology
Andhra University
External Guide
Mr.Sandeep Amin
Lead Technician
Weatherford Oil Tool M.E. Ltd.
Kakinada
2

3. ACKNOWLEDGEMENTS
I firstly offer my thanks to the one and only Almighty God for what He has done
and what He has planned further for me. I thank Him for everything he provided
to me.
On the completion of my dissertation, I very happily take this opportunity to
express my sincere thanks to venerable Mr.SACHIN ZENDE, L.W.D Coordinator,
Weatherford Oil Tool M.E Ltd, Mumbai, for offering me this project and his
valuable guidance and assiduous help in graciously supervising the work till its
final shape.
I would also very venerably thank Mr.Sandeep Amin, Lead technician,
Weatherford Oil Tool M.E Ltd. for guidance on drilling motor which I feel has
turned me round and brought me to the frontline in my project. I convey my
deep sense of thanks for them.
I express my gratitude to Mr. UMA SHANKAR RAO, for taking special interest,
guidance, encouragement and initiating me into my project work.
My heartfelt thanks are extended to MR.Vinod, MR.Vijay, who have given
technical views & the entire staff of WEATHERFORD for their kind and lovely co-
operation throughout the work and letting us avail the facilities for the present
study.
Very venerably, I present my hearty gratitude to my Parents who have always
been supportive to me and fulfilling all my requisites all through the course of my
academics and prayed for my success earnestly believing that I can pursue
higher studies uninterruptedly. I express my deep love and respect to them
through this and dedicate this work to them.
Last but not the least; I extend my thanks to my colleagues and friends at the
work place Prawal, etc. who have all through been a source of strength and
motivation during the period of my academics and provided a great co-
operation. Their role in the work is highly acknowledged.
3

4. Contents
1.0 INTRODUCTION .....................................................................................................................1
ABOUT THE ORGANIZATION........................................................................................................6
1.1 Objectives ..................................................................................................................................7
1.2 OIL EXPLORATION ..................................................................................................................8
1.3 DRILLING................................................................................................................................15
2. INTRODUCTION TO DIRECTIONAL DRILLING .......................................................................16
2.1 Definition of Directional Drilling...............................................................................................16
2.2 Description of Directional Drilling.............................................................................................17
2.3 Historical Development of Directional Drilling: .........................................................................17
2.4 Controlled Directional Drilling............................................................................................18
2.5 Reasons for Drilling Directional Wells................................................................................18
2.6 Bit Technology ........................................................................................................................21
3.0 DRILLSTRING BASICS ................................................................................................................25
4.0 Well Planning Introduction.....................................................................................................26
4.1 Well Profile Terminology......................................................................................................30
4.2 Types of Directional Patterns .............................................................................................31
5.0 MOTOR ASSEMBLY...................................................................................................................35
5.1 MOTOR CONFIGURATION......................................................................................................35
5.2MOTOR SELECTION ...............................................................................................................36
5.3 POWER TRANSMISSION: ..........................................................................................................39
6.0 COMPONENTS OF MOTOR.....................................................................................................44
7.0 Advances in directional drilling: ...........................................................................................51
7.1 OPERATIONAL OVERVIEW OF ROTARY-STEERABLE SYSTEM ...........................................51
7.2 Advantages of Rotary Steerable System ........................................................................54
8.0 APPLICATIONS OF DIRECTIONAL DRILLING.........................................................................55
4

5. 9.0 DRILLING COMPLICATIONS AND REMEDIES.......................................................................58
CONCLUSION:................................................................................................................................63
5

6. 1.0 INTRODUCTION
This report concerns with Basic geological concepts involved in oil formation,
Geophysical methods involved in exploring the crude oil both onshore & offshore. This report
gives comprehensive description on the detailed design of equipment used at drill site & its
technical operation, an overview of the main processes and few complications its remedies in the
interest of overview.
ABOUT THE ORGANIZATION
Weatherford International oil tool M.E Ltd. is one of the largest global providers of
advanced products and services that span the drilling, evaluation, completion, production and
intervention cycles of oil and natural gas wells. Weatherford operates in more than 100 countries
with 800 service bases and 16 technology development and training facilities.
Today’s Weatherford is a result of internal growth and innovation as well as the consolidation of
more than 250 strategic acquisitions. From a strategic standpoint, Weatherford has two key
objectives--efficiency and productivity. Weatherford strives for efficiency, both in terms of
delivering results for its clients as well as leveraging its worldwide infrastructure. The ultimate
goal in both cases is to help reduce costs and increase well productivity. As well, Weatherford
has created a portfolio of drilling services and products that make well construction safer reduce
nonproductive time and enhance reservoir deliverability.
6

7. 1.1 Objectives
In this module you will learn the following:
1. Brief description of geology.
2. Recall the historical development of directional drilling.
3. Recognize the reasons for drilling the following types of wells: exploration, appraisal, and
development/production.
4. Identification of several features of a directional well profile & general types of directional
well profiles.
5. Detailed study on Power Section of Motor.
6. Identify descriptions and pictures of directional drilling applications.
7

8. Petroleum literally means Rock Oil. Generally petroleum is related to hydrocarbons,
hydrocarbons are naturally occurring materials, including oil, natural gas, and tar. It is made up
of hydrocarbon molecules. Petroleum supplies almost half of our total energy requirements.
1.2 OIL EXPLORATION
Oil is a fossil fuel that can be found in many countries around the world. In this section, we will
discuss how oil is formed and how geologists find it.
FORMING OIL
Oil is formed from the remains of tiny plants and animals (plankton) that died in ancient seas
between 10 million and 600 million years ago. After the organisms died, they sank into the sand
and mud at the bottom of the sea. Over the years, the organisms decayed in the sedimentary
layers. In these layers, there was little or no oxygen present. So microorganisms broke the
remains into carbon-rich compounds that formed organic layers. The organic material mixed
with the sediments, forming fine-grained shale, or source rock. As new sedimentary layers were
deposited, they exerted intense pressure and heat on the source rock. The heat and pressure
distilled the organic material into crude oil and natural gas. The oil flowed from the source rock
and accumulated in thicker, more porous limestone or sandstone, called reservoir rock.
Movements in the Earth trapped the oil and natural gas in the reservoir rocks between layers of
impermeable rock, or cap rock, such as granite or marble.
Fig a: Geological formation of oil
8

9. FINDING OIL
The task of finding oil is assigned to geologists, whether employed directly by an oil
company or under contract from a private firm. Their task is to find the right conditions for an oil
trap -- the right source rock, reservoir rock and entrapment. Many years ago, geologists
interpreted surface features, surface rock and soil types, and perhaps some small core samples
obtained by shallow drilling. Modern oil geologists also examine surface rocks and terrain, with
the additional help of satellite images. However, they also use a variety of other methods to find
oil. They can use sensitive gravity meters to measure tiny changes in the Earth's gravitational
field that could indicate flowing oil, as well as sensitive magnetometers to measure tiny changes
in the Earth's magnetic field caused by flowing oil. They can detect the smell of hydrocarbons
using sensitive electronic noses called sniffers. Finally, and most commonly, they use
seismology, creating shock waves that pass through hidden rock layers and interpreting the
waves that are reflected back to the surface.
1 2 3
Fig b: Oil& Gas exploration on on-shore
1) Can be trapped by folding.
2) Faulting.
3) Oinching out.
9

10. Fig c: Oil & Gas exploration on offshore using seismology
The shock waves travel beneath the surface of the Earth and are reflected back by the various
rock layers. The reflections travel at different speeds depending upon the type or density of rock
layers through which they must pass. The reflections of the shock waves are detected by
sensitive microphones or vibration detectors -- hydrophones over water, seismometers over land.
The readings are interpreted by seismologists for signs of oil and gas traps. Although modern oil-
exploration methods are better than previous ones, they still may have only a 10-percent success
rate for finding new oil fields. Once a prospective oil strike is found, the location is marked by
GPS coordinates on land or by marker buoys on water.
10

11. PREPARING TO DRILL
Once the site has been selected, it must be surveyed to determine its boundaries, and
environmental impact studies may be done. Lease agreements, titles and right-of way accesses
for the land must be obtained and evaluated legally. For off-shore sites, legal jurisdiction must be
determined. Once the legal issues have been settled, the crew goes about preparing the land:
1. The land is cleared and leveled, and access roads may be built.
2. Because water is used in drilling, there must be a source of water nearby. If there is no natural
source, they drill a water well.
3. They dig a reserve pit, which is used to dispose of rock cuttings and drilling mud during the
drilling process, and line it with plastic to protect the environment. If the site is an ecologically
sensitive area, such as a marsh or wilderness, then the cuttings and mud must be disposed offsite
-- trucked away instead of placed in a pit. Once the land has been prepared, several holes must be
dug to make way for the rig and the main hole. A rectangular pit, called a cellar, is dug around
the location of the actual drilling hole. The cellar provides a workspace around the hole, for the
workers and drilling accessories. The crew then begins drilling the main hole, often with a small
drill truck rather than the main rig. The first part of the hole is larger and shallower than the main
portion, and is lined with a large-diameter conductor pipe. Additional holes are dug off to the
side to temporarily store equipment -- when these holes are finished, the rig equipment can be
brought in and set up.
SETTING UP THE RIG
Depending upon the remoteness of the drill site and its access, equipment may be transported to
the site by truck, helicopter or barge. Some rigs are built on ships or barges for work on inland
water where there is no foundation to support a rig (as in marshes or lakes). Once the equipment
is at the site, the rig is set up. Here are the major systems of a land oil rig:
11

12. Fig d: Anatomy of an oil rig
Power system
Large diesel engines - burn diesel-fuel oil to provide the main source of power Electrical
generators - powered by the diesel engines to provide electrical power
12

13. Mechanical system - driven by electric motors Hoisting system - used for lifting heavy
loads; consists of a mechanical winch (drawworks) with a large steel cable spool, a block-and-
tackle pulley and a receiving storage reel for the cable Turntable - part of the drilling apparatus
Rotating equipment - used for rotary drilling Swivel - large handle that holds the weight of the
drill string; allows the string to rotate and makes a pressure-tight seal on the
Hole Kelly - four- or six-sided pipe that transfers rotary motion to the turntable and drill string
Turntable or rotary table - drives the rotating motion using power from electric motors
Drill string - consists of drill pipe (connected sections of about 30 ft / 10 m) and drill collars
(larger diameter, heavier pipe that fits around the drill pipe and places weight on the drill bit)
Drill bit(s) - end of the drill that actually cuts up the rock; comes in many shapes and materials
(tungsten carbide steel, diamond) that are specialized for various drilling tasks and rock
formations
Casing - large-diameter concrete pipe that lines the drill hole, prevents the hole from collapsing,
and allows drilling mud to circulate
Circulation system - pumps drilling mud (mixture of water, clay, weighting material and
chemicals, used to lift rock cuttings from the drill bit to the surface) under pressure through the
kelly, rotary table, drill pipes and drill collars
• Pump - sucks mud from the mud pits and pumps it to the drilling apparatus
• Pipes and hoses - connects pump to drilling apparatus
• Mud-return line - returns mud from hole
• Shale shaker - shaker/sieve that separates rock cuttings from the mud
• Shale slide - conveys cuttings to the reserve pit
• Reserve pit - collects rock cuttings separated from the mud
• mud pits - where drilling mud is mixed and recycled
• mud-mixing hopper - where new mud is mixed and then sent to the mud pits
13

14. Fig e: Drill-mud circulation system
Blowout preventer - High-pressure valves (located under the land rig or on the sea floor) that
seal the high-pressure drill lines and relieve pressure when necessary to prevent a blowout
(uncontrolled gush of gas or oil to the surface, often associated with fire)
14

15. 1.3 DRILLING
The crew sets up the rig and starts the drilling operations. First, from the starter hole, they
drill a surface hole down to a pre-set depth, which is somewhere above where they think the oil
trap is located. There are five basic steps to drilling the surface hole:
1. Place the drill bit, collar and drill pipe in the hole.
2. Attach the Kelly and turntable and begin drilling.
3. As drilling progresses, circulate mud through the pipe and out of the bit to float the rock
cuttings out of the hole.
4. Add new sections (joints) of drill pipes as the hole gets deeper.
5. Remove (trip out) the drill pipe, collar and bit when the pre-set depth (anywhere from a few
hundred to a couple-thousand feet) is reached.
Once they reach the pre-set depth, they must run and cement the casing place casing-pipe
sections into the hole to prevent it from collapsing in on itself. The casing pipe has spacers
around the outside to keep it centered in the hole.
The casing crew puts the casing pipe in the hole. The cement crew pumps cement down
the casing pipe using a bottom plug, a cement slurry, a top plug and drill mud. The pressure from
the drill mud causes the cement slurry to move through the casing and fill the space between the
outside of the casing and the hole. Finally, the cement is allowed to harden and then tested for
such properties as hardness, alignment and a proper seal.
Drilling continues in stages: They drill, then run and cement new casings, then drill again. When
the rock cuttings from the mud reveal the oil sand from the reservoir rock, they may have
reached the final depth. At this point, they remove the drilling apparatus from the hole and
perform several tests to confirm this finding:
15

16. 2. INTRODUCTION TO DIRECTIONAL DRILLING
Introduction
Fig a: Drilling platforms
Directional drilling has become a very important tool in the development of oil and gas deposits.
Current expenditures for hydrocarbon production have dictated the necessity of controlled
directional drilling to a much larger extent than previously.
Probably the most important aspect of controlled directional drilling is that it enables
producers all over the world to develop subsurface deposits that could never be reached
economically in any other manner. In this module a number of topics will be covered that must
be understood by the directional driller. The various types of wells and applications of
directional wells will be touched upon along with well profiles and well planning.
Directional Drilling
2.1 Definition of Directional Drilling
Controlled directional drilling is the science and art of deviating a wellbore along a planned
course from a starting location to a target location, both defined with a given coordinate system.
16

17. 2.2 Description of Directional Drilling
Drilling a directional well basically involves drilling a hole from one point in space (the
surface location) to another point in space (the target) in such a way that the hole can then be
used for its intended purpose.
A typical directional well starts off with a vertical hole, then kicks off so that the bottom
hole location may end up hundreds or thousands of feet or meters away from its starting point.
With the use of directional drilling, several wells can be drilled into a reservoir from a single
platform.
2.3 Historical Development of Directional Drilling:
Directional drilling was initially used as a remedial operation, either to sidetrack around
stuck tools, bring the wellbore back to vertical, or in drilling relief wells to kill blowouts. Interest
in controlled directional drilling began about 1929 after new and rather accurate means of
measuring the hole angle were introduced during the development of the Seminole field,
Oklahoma, USA.
The first application of oil well surveying occurred in the Seminole field of Oklahoma
during the late 1920’s. A subsurface geologist found it extremely difficult to develop logical
contour maps on the oil sands or other deep key beds. The acid bottle inclinometer was
introduced into the area and disclosed the reason for the problem; almost all the holes were
crooked, having as much as 50 degrees inclination at some check points.
Fig b. Directional Drilling
17

18. 2.4 Controlled Directional Drilling
The science of deviating a wellbore along a planned course to subsurface target whose
location is at a given lateral distance and direction from the vertical, at a specified vertical depth.
Drilling a wellbore with planned deviation from vertical to pre-determined target(s).
Figure c: Controlled directional drilling
2.5 Reasons for Drilling Directional Wells...
• Surface reasons
• Subsurface reasons
• Special needs
Surface Reasons...
• Surface obstructions (rig/well positioning problems)
• Restrictions (health, safety or environmental)
• Economics of rig positioning
18

19. Fig d: surface obstructions
Surface Obstructions
• Unsuitable terrain (sloped ground, marsh, forest, sand dunes, etc)
• Proximity to other wells, pipelines, oilfield facilities
• Populated area (city or rural area, farmhouse, Industrial facility)
• Proximity to power lines
• Airports, radar or radio stations
• Access road and site preparation difficulties
Sub-surface Reasons...
• Collision risk with existing wells
• Multiple targets to open for production
• Horizontal drain(s) needed
• Re-entering producing formations
• Drilling extended reach wells (ERD) to remote target(s)
Sub-surface Reasons...
Geological problems exist
• Faults
• Floating Blocks,
• Salt Domes
» Known natural deviation tendencies caused by significant formation dip
19

20. » Sidetracking (lost) down hole objects
» Relief well required
SPECIAL NEEDS
Formation Dip Effects
Laminar formation dipping 45°or less :
• Each layer fractures perpendicular to
• bedding planes
• Bit tilt is significant contributor
• Bit is forced to up dip
• Formation strike
• Laminar formation dipping > 45°
• Bit follows the formation plane
Note : dip angle is measured from horizontal !
Fig e: Formation effects
Fig f: side tracking when object is lost Fig g: Relief well required
20

21. 2.6 Bit Technology
Rolling Cutter Rock Bits
The primary drilling mechanism of the rolling cutter bits is intrusion, which means that
the teeth are forced into the rock by the weight-on-bit, and pulled through the rock by the rotary
action. For this reason, the cones and teeth of rolling cuttings rock bits are made from specially,
case hardened steel.
One advantage of a rolling cutter bits is the three bearing design located around the journal of the
bit. Heel bearings are roller bearings, which carry most of the load and receive most of the wear.
Middle bearings are ball bearings, which hold the cone on the journal and resist thrust in either
direction. The nose bearing consists of a special case hardened bushing pressed into the nose of
the cone and a male piece, hard faced with a special material, to resist seizure and wear.
Although rock bits have been continually improved upon over the years, three developments
remains outstanding:
(1) The change in water course design and the development of the “jet” bit,
(2) The introduction of the tungsten carbide insert cutting structure, and
(3) The development of sealed journal bearings.
Polycrystalline Diamond Compact Bits
In the early days of oil well drilling, fishtail/drag bits were used extensively throughout
the oilfields. In 1976, the cutting structure of the polycrystalline diamond compact (PDC) has
made the drag bit competitive with the conventional roller cone and diamond bits.
PDC Drill Blanks
These drill blanks consist of a layer of synthetic polycrystalline diamond bonded to a
layer of cemented tungsten carbide using a high-temperature, high-pressure bonding technique.
The resulting blank has the hardness and wear resistance of diamond which is complemented by
the strength and impact resistance of tungsten carbide. PDC blanks are self-sharpening in the
sense that small, sharp crystals are repeatedly exposed as each blank wears, and because they are
polycrystalline these blanks have no inherently weak cleavage planes, which can result in
massive fractures as in the large, single crystal diamonds in the diamond bits.
21

22. Diamond Bits
Diamond core bits were introduced into the oilfield in the early 1920's and were used to
core extremely hard formations.
The Diamond Bit
A diamond bit (either for drilling or coring) is composed of three parts:
• Diamonds
• Matrix &
• Shank.
The diamonds are held in place by the matrix which is bonded to the steel shank. The
matrix is principally powdered tungsten carbide infiltrated with a metal bonding material. The
tungsten carbide is used for its abrasive wear and erosion resistant properties (but far from a
diamond in this respect). The shank of steel affords structural strength and makes a suitable
means to attach the bit to the drill string.
Uses of Diamond Bits
• Deep, small holes: Roller cone bits that are 6-inch and smaller have limited life due to the space
limitations on the bearing, cone shell thickness, etc. Diamond bits being one solid piece often last
much longer in very small boreholes.
• Directional drilling: Diamond side tracking bits are designed to drill “sideways” making it a
natural choice for “kicking off” in directional drilling situations.
• Coring: The use of diamond bits for coring operations is essential for smooth, whole cores.
Longer cores are possible with increased on bottom time and cores “look better” because of the
cutting action of diamond bits as compared to those of roller cone bits.
Fig h: Roller cutting bit Fig i: PDC bit Fig j: Diamond bit
22

23. Torque
Torque indications are very useful as a check on smooth operation. No absolute values
have been set up, but a steady torque is an indication that the previous three factors are well
coordinated.
Bit Stabilization
A diamond is extremely strong in compression, but relatively weak in shear, and needs
constant cooling when on bottom. The bit is designed and the rake of the diamonds set, so that a
constant vertical load on the bit keeps an even compressive load on the diamonds, and even
distribution of coolant fluid over the bit face. If there is lateral movement or tilting of the bit, an
uneven shear load can be put on the diamonds with coolant leakage on the opposite side of the
bit. Any of the standard “stiff-hookup” or packed hole assemblies are suitable for stabilization
when running diamond bits. It is recommended that full gauge stabilizers be run near the bit, and
at 10 feet and 40 feet from the bottom.
Drilling
After the bit has been started, rotary speed should be increased to the practical limit
indicated by rig equipment. The drill pipe, hole condition, and depth should also be taken into
consideration. Weight should be added as smoothly as possible in 2000 pound increments.
Observations of penetration rate after each weight increase should be made to avoid overloading.
As long as the penetration rate continues to increase with weight, then weight should be
increased. However, if additional weight does not increase the penetration rate, then the weight
should be reduced back 2000 to 3000 pounds, to avoid packing and balling-up of the space
between the diamonds. Drilling should be continued at this reduced weight. After making a
connection, be sure to circulate just off bottom for at least five minutes, as cuttings in the hole
could damage the bit. The time spent here may lengthen the life of the bit by many hours.
Selection Guideline
Because formations of the same age and composition change in character, with depth,
and drill differently, no universal bit selection guide can be prepared. However, general
guidelines include:
23

24. Soft formations
Sand, shale, salt, anhydrite or limestone require a bit with a radial fluid course set with
large diamonds. Stones of 1-5 carats each are used, depending on formation hardness. This type
of bit should be set with a single row of diamonds on each rib and designed to handle mud
velocities ranging from 300-400 fps to prevent balling.
Medium formations
Sand, shale, anhydrite or limestone require a radial style bit with double rows of
diamonds on each blade or rib. Diamond sizes range from 2-3 stones per carat. Mud should be
circulated through these bits at a high velocity. Good penetration rates can be expected in
interbedded sand and shale formations.
Hard, dense formations
Mudstone, siltstone or sandstone usually requires a crowsfoot fluid course design. This
provides sufficient cross-pad cleaning and cooling and allows a higher concentration of
diamonds on the wide pads. Diamond sizes average about 8 stones per carat.
Extremely hard, abrasive or fractured formations
Schist, chert, volcanic rock, sandstone or quartzite’s require a bit set with small diamonds
and a crowsfoot fluid course to permit a high concentration of diamonds. The diamonds (about
12 per carat) are set in concentric “metal protected” ridges for perfect stone alignment, diamond
exposure and protection from impact damage.
24

25. 3.0 DRILLSTRING BASICS
Introduction
Drill pipe and collars are designed to satisfy certain operational requirements. In general,
down hole tubular must have the capability to withstand the maximum expected hook load,
torque, bending stresses, internal pressure, and external collapse pressure. Other concerns, such
as the presence of H2S, must also be considered in the selection process. Drill Pipe Yield
Strength and Tensile Strength If drill pipe is stretched, it will initially go through a region of
elastic deformation. In this region, if the stretching force is removed, the drill pipe will return to
its original dimensions. The upper limit of this elastic deformation is called the Yield Strength,
which can be measured in psi. Beyond this, there exists a region of plastic deformation. In this
region, the drill pipe becomes permanently elongated, even when the stretching force is removed.
The upper limit of plastic deformation is called the Tensile Strength. If the tensile strength is
exceeded, the drill pipe will fail. Tension failures generally occur while pulling on stuck drill
pipe. As the pull exceeds the yield strength, the metal distorts with a characteristic thinning in the
weakest area of the drill pipe (or the smallest cross sectional area). If the pull is increased and
exceeds the tensile strength, the drillstring will part. Such failures will normally occur near the
top of the drillstring, because the top of the string is subjected to the upward pulling force as well
as the downward weight of the drillstring.
YIELD STRENGTH = Yield Strength x π/4 (OD^2—ID^2)(in pounds)(in psi)
Fig a: Drill String
25

26. 4.0 Well Planning Introduction
There are many aspects involved in well planning, and many individuals from various
companies and disciplines are involved in designing various programs for the well (mud
program, casing program, drill string design, bit program, etc. This section will concentrate on
those aspects of well planning which have always been the provinces of directional drilling
companies.
1. Target Size and Shape:
The objective of a oil well is to reach the target: pay zone However there may be other objectives
in drilling a well inn additions to intersecting the pay zone:
• Defining the geological features such as pinch outs or faults.
• Defining reservoir structures.
• Intersecting another well as in relief well drilling.
The point to be penetrated is called target and area around the target is the target zone. This
allows the directional driller some tolerance in the final positioning of the well. A radius of 50
meters is commonly used as a target zone. However, this depends on particular requirements.
• The smaller the target zone the greater the number of correction runs necessary to hit the
target. It results in longer drilling times and higher drilling cost.
• The target zone should be as large as the geologist or the reservoir engineer can allow.
The job of directional driller is then to place the well bore with in the target at minimum
cost.
2. Formation characteristics (KOP & Lead):
• Hard formations may give poor response to deflection tool resulting in long time and
several bit runs while soft formation may result in large washouts.
• A soft-medium formation provides a better opportunity for a successful kick-off.
• Formations exhibit a tendency to deflect the bit either left or to right. The directional
driller can compensate this effect by allowing some lead angle when orienting the
deflection tool.
26

27. Under normal rotary drilling the bit will tend to walk to the right. Sometimes the bit may also
turn towards left. R.H. walk is more at higher WOB and lower inclinations.
R.H. walking decreases with:
• Increase in RPM
• Low WOB and
• High inclination
3. Optimum surface location for the rig:
It is essential to select an optimum surface location for the rig taking advantage of natural
formation tendencies.
Effect of formation attitude –
• Like wise, the formation attitudes also have effect on directional tendencies.
• If proposed direction is due up dip, it follows the natural bit tendencies and drift angle
can be readily built.
• But if the proposed direction is left of up dip the bit will tend to turn to the right. And if
the proposed direction is right of up dip, the bit will deviate to the left.
• The rotation of DHM forces the bit to turn to the left.
4. Hole size:
Larger diameter holes are easier to control directionally then smaller diameter holes. As
slim hole requires smaller drill collars and pipes which limits the range of weight available.
5. Casing and Mud Programming:
Most directional wells follow the same casing program used in straight hole drilling. Mud
control is extremely important in reducing the torque and drag in directional hole.
6. Location of Adjacent Wells:
On offshore platforms, distance between adjacent conductors is small. In this situation
precise control is required. Therefore, kick off points for adjacent wells are chosen at varying
27

28. depths to give some separations to avoid collisions directly beneath the platforms and problems
of wells running across each other.
To avoid collisions directly below the platform KOP for adjacent wells are chosen at varying
depths to give some separations.
7. Choice of Build up Rate:
If BUR is very high, severe dog-legs can occur. These dog-legs can cause difficulty in
running tubular and wear on the pipe. If BUR is very less it will consume more drilling depth
and time. Hence gradual BUR of 1.5 to 0.5 is commonly used.
If the change of angle occurs too quickly, severe dog-legs can occur in the trajectory.
Sharp bends make it difficult for drilling assemblies and tubulars to pass through and also causes
more wear on the drill string.
8. Experience Gained From Drilling Previous Directional Wells :
A review of previous drilling practices and problems will give better guide lines for
future wells.
Planning a directional well path:
• Kick off point.
• Build up rate.
• Azimuthal direction.
• Inclination angle.
• True vertical depth.
• Measured depth.
• Horizontal displacement.
Fig b: Direction of the well
28

29.
Well drilled without Planning:
29

30. 4.1 Well Profile Terminology
Fig d: Basic Well Profiles
30

31. •TVD - True Vertical Depth
•TMD - Total Measured Depth
•DLS - Dog-Leg Severity
•BUR - Build-Up Rate
• Inclination - The Angle from Vertical
•Azimuth - The Direction of the Well
4.2 Types of Directional Patterns
These complex well paths are harder to drill and the old adage that “the simplest method
is usually the best” holds true. Therefore, most directional wells are still planned using traditional
patterns which have been in use for many years. Common patterns for vertical projections are
shown on the following:
Build and Hold
Simplest
• Inclination 15 -55°
• KOP determines inclination
• Large horizontal displacements at shallow depths
Applications:
• Deep wells with large horizontal displacements
• Moderately deep wells with moderate horizontal displacement, where intermediate casing
is not required
Build Hold and Drop
More difficult control
• Increased torque and drag
• Multiple target intersection
• Small horizontal displacement
• Near vertical target Penetration
31

32. Applications: Disadvantages:
Multiple pay zones - Increased torque & drag
Reduces final angle in reservoir - Risk of key seating
Lease or target limitations - Logging problems due to inclination
Well spacing requirements
Deep wells with small horizontal displacements
Fig e: Build and Hold Fig f: Build Hold and Drop
Continuous Build to Horizontal
• Most simple to drill
• Minimum hole length
• Short horizontal displacement to target
• Smallest measured depth
• Long lateral hole is possible
Applications:
• Appraisal wells to assess the extent of a newly discovered reservoir
• Repositioning of the bottom part of the hole or re-drilling
• Salt dome drilling
Disadvantages:
Formations are harder so the initial deflect ion may be more difficult to achieve
32

33. Harder to achieve desired tool face orientation with down hole motor deflection assemblies
(more reactive torque) Longer trip time for any BHA changes required
Fig g: Continuous Build to Horizontal
On multi-well platforms, only a few wells are given deep kick-off points, because of the
small slot separation and the difficulty of keeping wells vertical in firmer formation. Most wells
are given shallow kick-off points to reduce congestion below the platform and to minimize the
risk of collisions
Horizontal wells
Horizontal well is defined as the well drilled in the zone parallel to the bedding plane.
The well is deflected to the 90° from vertical and the drain hole is placed exactly in the drainage
area. The objective of the first horizontal well, is to determine if a horizontal well could be
drilled economically and to acquire production data to see if future horizontal redevelopment in
the field is beneficial. The directional objective to drill a horizontal section is staying in the top
3m ( 10 ft ) of the sand to increase sweep efficiency and to stay as far as possible from the
oil/water contact thereby lowering the water cut. For many applications, the best well profile is
one in which the inclination is built to 90° or even higher. Unfortunately there are other
considerations (e.g. water injection wells may have to be grouped together for manifold
requirements). Also, as more wells are drilled and the reservoir model is upgraded, targets can be
changed or modified.
33

34. Types of horizontal wells :
• Long Radius (1°-5°/100 ft.)
• Medium Radius (5°-20°/100 ft.)
• Short Radius (20°-40°/100 ft.)
• Ultra Short Radius (45°-90°/ ft.)
Fig h: Multilateral wells
34

35.
Kick‐off Point and Build‐Up Rate
The selection of both the kick-off point and the build-up rate depends on many factors.
Several being hole pattern, casing program, mud program, required horizontal displacement and
maximum tolerable inclination. Choice of kick-off points can be limited by requirements to keep
the well path at a safe distance from existing wells. The shallower the KOP and the higher the
build-up rate used, the lower the maximum inclination. Build-up rates are usually in the range
1.5°/100' M.D. to 4.0°/100' M.D. for normal directional wells. Maximum permissible dogleg
severity must be considered when choosing the appropriate rate. In practice, well trajectory can
be calculated for several KOPs and build-up rates and the results compared. The optimum choice
is one which gives a safe clearance from all existing wells, keeps the maximum inclination
within desired limits and avoids unnecessarily high dogleg severities.
5.0 MOTOR ASSEMBLY
The motor section consists of a rubber stator and steel rotor. The simple type is a helical
rotor which is continuous and round. This is the single lobe type. The stator is molded inside the
outer steel housing and is an elastomer compound. The stator will always have one more lobe
than the rotor. Hence motors will be described as 1/2, 3/4, 5/6 or 9/10 motors. Both rotor and
stator have certain pitch lengths and the ratio of the pitch length is equal to the ratio of the
number of lobes on the rotor to the number of lobes on the stator. As mud is pumped through the
motor, it fills the cavities between the dissimilar shapes of the rotor and stator. The rotor is
forced to give way by turning or, in other words, is displaced (hence the name). It is the rotation
of the rotor shaft which is eventually transmitted to the bit.
5.1 MOTOR CONFIGURATION
Standard drilling Motor
• Standard bearing pack
• Power section lined with a standard or premium elastomer
• Conventional power sections
35

36. High Performance Drilling Motor
• High torque bearing pack
• Power section lined with a standard or premium elastomer
• High torque power section
5.2 MOTOR SELECTION
High Speed Motors–These motors work well in applications where high torque is not
required, such as drilling soft formations.
Medium Speed Motors – These motors have been designed for increased flow rates,
rotary speeds, and torque outputs. They are used in drilling applications where above
normal flow rates are desired such as when needing to clean a hole better due to
increased penetration rates or where high rotary speeds are desired.
Low Speed Motors – These motors have both low speed & high torque outputs which
are ideal for applications such as drilling in hard formations. By design the multi-lobe
configuration provides the ability for high torque output in a shorter length tube which is
beneficial in applications such as high build radius drilling.
Conventional Power Section – These are used for the most common drilling
applications and consist of the widest variety of speeds, torques & lengths.
High Torque Power Section – This configuration is used when the torque output
desired cannot be achieved with a conventional power section. Typically it will consist
of a hard elastomer such as NBR250 which can accommodate larger pressure drops
and thus produce higher torque outputs. This level of performance is only available on
medium & low speed motors. They are ideal for use with aggressive PDC bits and in
applications where maximum torque is required.
Even Rubber Thickness Power Sections - These motors utilize even rubber thickness
technology which has a higher pressure rating over conventional power section s and
thus provide a much higher torque capacity. They are ideal for use with aggressive PDC
bits and in applications where maximum torque is required.
36

37. Different Motors Sizes:
The following are the different motor sizes with respective hole sections. They are listed
below as follows:
S. No HOLE SECTIONS
STABILIZER
SLEEVE MOTORS AT DIFFERENT SIZES
1 26” 25 ¾” 9 5/8” 11 ¼”
2 17 ½” 17 3/8” 9 5/8” -
3 12 1/4” 12 1/8” 9 5/8” 8”
4 8 ½” 8 3/8” 6 ¾” -
5 6” 5 ¾” 5 7/8” 4 ¾”
37

38. CHANGE IN MOTOR :
OPERATION
Converts hydraulic power from the drilling fluid into mechanical power to drive the bit
– Stator – steel tube containing a bonded elastomer insert with a lobed, helical pattern bore
through the center
– Rotor – lobed, helical steel rod
• When drilling fluid is forced through the power section, the pressure drop across the cavities
will cause the rotor to turn inside the stator
Pattern of the lobes and the length of the helix dictate the output characteristics
• Stator always has one more lobe than the rotor
• Stage – one full helical rotation of the lobed stator
• With more stages, the power section is capable of greater differential pressure, which in turn
provides more torque to the rotor
38

39. 5.3 POWER TRANSMISSION:
This is a short tool which has a set number of stages and its bearing section entirely
within one housing. That is, it is not a sectional tool and will be typically less than 30 feet long.
It is designed for short runs to kick off or correct a directional well, using a bent sub as the
deflection device.
Figure: Cross-section of a turbine motor
Motor Observations
• There is minimal surface indication of a motor stalling.
• Sand content of the drilling fluid should be kept to a minimum.
• Due to minimal rubber components, the turbine is able to operate in high temperature wells.
• Pressure drop through the tool is typically high and can be anything from 500 psi to over 2000
psi.
• Motors do not require a by-pass valve.
• Usually, the maximum allowable bearing wear is of the order of 4mm.
Motor Characteristics
• Torque and RPM are inversely proportional (i.e. as RPM increases, torque decreases and vice
versa).
• RPM is directly proportional to flow rate (at a constant torque).
39

40. • Torque is a function of flow rate, mud density, blade angle and the number of stages, and varies
if weight-on-bit varies.
• Optimum power output takes place when thrust bearings are balanced.
• Changing the flow rate causes the characteristic curve to shift.
• Off bottom, the turbine RPM will reach “run away speed” and torque is zero.
• On bottom, and just at stall, the turbine achieves maximum torque and RPM is zero.
• Optimum performance is at half the stall torque and at half the runaway speed, the turbine then
achieves maximum horsepower.
• A stabilized turbine used in tangent sections will normally cause the hole to “walk” to the left.
REACTIVE TORQUE
Generally drilling motor turns the bit with a right-hand (clockwise) rotation. As WOB is
increased, reactive torque is developed in a left-hand (counter-clockwise) direction on the
drilling motor housings. Reactive torque is transferred to the BHA and may cause the
connections above the power section to tighten or connections below to loosen. Reactive torque
increases with larger WOB and reaches a maximum when the motor stalls. Reactive torque
affects directional control and must be taken into account when orienting the drilling motor
from the surface in the desired direction.
Reactive torque is created by the drilling fluid pushing against the stator. Since the stator
is bonded to the body of the motor, the effect of this force is to twist the motor and BHA anti-
clockwise. As weight-on-bit is increased, the drilling torque created by the motor increases, and
reactive torque increases in direct proportion.
Factors Affecting Reactive Torque
The reactive torque which motors generate will be in direct proportion to the differential
pressure across the motor. This in turn is influenced by:·
• Motor characteristics
• Bit characteristics
• Formation drillability
• Weight on bit
40

41. Estimation of reactive torque has always been a problem for directional drillers. Several charts
and rules of thumb have evolved. One is:
EXPECTED REACTIVE TORQUE = 10° - 20° / 1000 ft M.D.
MAXIMUM RPM FOR MOTOR BEND SETTING
The following are the different bend settings with their respective rpm’s. As from
the below table it refers that as the Bend setting goes on decreasing the RPM goes on
increasing.(Straight Hole) Maximum RPM for Motor Bend Setting (Straight Hole)
Bend
Setting
1.83º 1.5º 1.15º 0.78º 0.39º
RPM 60 70 90 110 150
The following are estimated build rates with Sick, One Stabilizer, & Two Stabilizer. This
table refers that build developed is increasing with respect to the increase in stabilizers & its
placement at certain distances.
ESTIMATED BUILD RATES Degrees / 30m (100 ft.)
41

42. ROTARY BHA
It consists of a bit, drill collars, stabilizers, reamers run below the drill pipe. In deviated
well the drill collar makes contact with the low side of the hole. The placement of the stabilizer
in the BHA effects the size of the side force and hence dictates weather the BHA will build or
drop the angle. A stabilizer placed just above the bit acts as the fulcrum. The weight of the collar
above the stabilizer acts as the lever to make the build angle. As the distance between the bit and
the stabilizer increase the upward force on the bit is reduced. Using the concept the BHA can be
designed for the required purpose in the bore hole.
Building Assemblies
This type of assembly is usually run in a directional well after the initial kick-off has been
achieved by using a deflection tool. A single stabilizer placed above the bit will cause building
owing to the fulcrum effect. The addition of further stabilizers will modify the rate of build to
match the required well trajectory. If the near-bit stabilizer becomes undergauge, the side force
reduces. Typical building assemblies are shown in Fig. Assemblies A and B respond well in soft
or medium formations. The inclusion of an undergauge stabilizer in assembly C will build
slightly less angle. By bringing the second stabilizer closer to the near-bit stabilizer, the building
tendency is increased. In hard abrasive rocks, the problems of bit wear are significant. To
maintain gauge hole, the near-bit and second stabilizer should be replaced by roller reamers. The
build rate should be kept below 2' per 100 ft to reduce the risk of dog-legs. The amount of WOB
applied to these assemblies will also affect their building characteristics. Too much WOB will
cause rapid build-up of angle.
Holding Assemblies
Once the inclination has been built to the required angle, the tangential section of the well is
drilled using a holding assembly. The object here is to reduce the tendency of the BHA to build
or drop angle. In practice this is difficult to achieve, since formation effects and gravity may alter
the hole angle, To eliminate building and dropping tendencies, stabilizers should be placed at
close intervals, using pony collars if necessary. Assembly I) in Fig. 3.7 has been used
successfully in soft formations. The undergauge stabilizer in assembly E builds slightly to
counter gravity, In harder formations the near-bit stabilizer is replaced by a reamer. Generally
42

43. only three stabilizers should be used, unless differential sticking is expected. Changes in WOB
will not affect the directional behavior of this type of assembly, and so optimum WOB can be
applied to achieve maximum penetration rates. A packed hole assembly with several stabilizers
should not be run immediately after a down hole motor run.
Dropping Assemblies
In directional wells, only an S shape profile requires a planned drop in angle. The other
application of a dropping assembly is when the inclination has been increased beyond the
intended trajectory and must be reduced to bring the well back on course. It is best to drop
i. Building assembly
ii. Holding assembly
43

44. iii. Dropping assembly
6.0 COMPONENTS OF MOTOR
MUD LUBRICATED BEARING SECTION
The bearing section contains the radial and thrust bearings that transmit the axial and
radial loads from the bit to the drill string while providing a drive line that allows the power
section to rotate the bit. Mud lubricated bearing sections utilize a limited portion of drilling fluid
for lubrication and cooling. The drilling fluid by-passing through the bearing section exits
directly above the bit box and rejoins the primary flow to help clean the hole.
STABILIZATION
Bearing housings are available with screw-on style stabilization. This provides the
option of installing a stabilizer sleeve on the rig floor in a matter of minutes. The drilling motor
can be operated slick through use of a thread protector sleeve when stabilization is not
required.
44

45. DRIVE ASSEMBLY
The design of the power section imparts an eccentric rotation of the rotor inside the
stator. To compensate for this eccentric motion and convert it to a concentric rotation. 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 delivered by the power
section. 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.
POWER SECTION
The power section is comprised of two components: the stator and the rotor. The stator
consists of a steel tube containing a bonded elastomer insert with a lobed helical pattern bored
through the center. The rotor is a lobed helical steel rod. When the rotor is installed into the stator
the combination of the helical shapes form sealed flow cavities between the two components.
When drilling fluid is forced through the power section the pressure drop across the cavities will
cause the rotor to turn inside the stator. This is how rotation provides power to the bit.
The performance characteristics of a power section are controlled by the following design
criteria.
• Lobe configuration
• Stages
• Power section fit
• Elastomer
Generally as the lobe ratio is increased speed of rotation is decreased, and torque
output is increased.
A stage is defined as a full helical rotation of the lobed stator. Power sections may be
classified in stages. As the number of stages increases, a power section is capable of greater
overall differential pressure, which in turn provides more torque to the rotor.
The power section fit is the compression or clearance between the rotor and stator. Each power
section configuration is designed with a specific fit to optimize performance output. Many
45

46. configurations have options available for larger clearance specifically designed to compensate for
elastomeric swell caused by temperature and/or drilling fluid.
Elastomers & Its Types:
The stator elastomer has a large influence on the overall performance output, drilling fluid
compatibility, and operating temperature limit. Weatherford drilling motors have a variety of
elastomeric compounds available to suite the needs of each drilling application.
Weatherford drilling motors use a variety of elastomers that can be classified by their basic
compound make up.
Rotor
Stator
Tube
Stator
Elastomer
NBR – Nitrile Butadiene Rubber (Nitrile)
or
HNBR – Hydrogenated Nitrile Butadiene Rubber
The choice for rubber types depends upon the type of drilling fluid used at drill site. The
following are different types of mud’s used at drill site.
Types of Mud’s Used at the drill site:
There are mostly two types of mud’s used at drill site. They are below as follows
1. Oil based type
2. Water based type
Oil based drilling fluid has a tendency to degrade stator elastomer, particularly at higher
temperatures, increasing the risk of elastomer failure. HNBR is used in applications where
drilling fluid compatibility or temperature is an issue. HNBR is also sometimes classified as
HSN (Highly Saturated Nitrile Butadiene Rubber).
For as such drilling fluid clearance fit is maintained in between the stator elastomer and
rotor. But incase of water based mud tighter fit is maintained and standard rubber is used.
46

47. BOTTOM HOLE ASSEMBLY
String Float Sub
String Float subs are designed to be run above the motor and contain a float valve. The float
valve prevents drilling fluid from back flowing and keep cuttings out of the motor and drill pipe.
This helps prevent damage to the stator and keeps the bit from plugging up. It is also used under
the following conditions.
• Drilling unconsolidated formations
• Drilling underbalanced
• Milling Steel
• Sour H2S wells
• Added blow out protection
String Stabilizers
String stabilizers can be used with drilling motors to help change the build rate characteristics of
that motor or help stabilize the BHA. These come in a large variety of styles and gauge diameters
to meet specific drilling requirements. Estimated build rates using both a screw-on stabilizer and
a string stabilizer
can be found on each
motor spec sheet
under the two stabilizers
column.
Subs Alignment
Alignment subs are a tool used in applications requiring the high side bend on the
drilling motor be aligned with another drilling tool further up on the BHA.
47

48. Adjustable Gauge Stabilizers
Adjustable gauge stabilizer can be used above the motor to make changes to the build
rate and rotary build rate characteristics of the BHA while drilling. It is a hydraulically acti-
vated tool with stabilizer blades that can be extended or retracted radially from its body gauged
for the wellbore.
Back‐Off Prevention
Historically, drilling motor connection back-offs occur when little or no WOB is being
applied. At these times the vibrations created by the drilling motor are at their highest
amplitudes which increase risk of connection back-off.
This may occur when:
• Reaming
• Time drilling
• Sidetracking
• Circulating
• Drilling underbalanced with compressible fluids
• Drilling with a rotor by-pass
When operating a drilling motor with little or no WOB being applied the operator
must reduce the flow rate to 20% to 30% of the maximum allowable flow rates. In
addition to the applications mentioned above, when WOB is about to be removed the flow
rate should be reduced prior to picking up. This will reduce vibration of the BHA.
Once significant WOB has been applied the flow rate can again be brought back up as
high as the maximum allowable flow rate. Applying this procedure as consistently as
possible will reduce risk of connection back-offs.
DEFINE JARRING:
A tool operated mechanically to give an upward thrust to a fish by the sudden release of
a tripping device inside the tool. If the fish can be freed by an upward blow, or downward blow
the jar can be very effective. This mechanical action is called jarring.
There are three types of jars. They are below as follows
48

49. • Mechanical Jar
• Hydraulic Jar
• Hydro-mechanical Jar
Details on jarring:
• Jarring can induce high tensile and compressive shock loads on
drilling motor components.
• Jarring loads are typically much larger than the over pull load
required to actuate the Jar.
• Jarring down in an over gauge hole may result in serious damage to
the motor due to buckling.
Rotor Catch Functioning
The operator should be able to quickly identify connection twist-off or
back-off. The identifying features are:
• Pressure loss when the bit is on bottom (due to loss of flow through housing).
• When the motor is off bottom the standpipe pressure will increase.
• With WOB reapplied the pressure increase disappears.
The rotor catch mandrel will bottom on the inside shoulder of the motor top sub. In this
condition, circulation is not possible and will result in a significant standpipe pressure increase.
The rotor catch design is to prevent a portion of the motor from separating in the event of a
housing connection failure.
TOP SUB ROTOR CATCH
Drilling motors come with a rotor catch assembly as standard equipment. The rotor catch is a
safety device that allows the motor to be pulled out of hole in the event of a connection failure.
The catch mandrel, which is connected to the rotor, will catch on the inside of the top-most sub of
the drilling motor ensuring that when pulling out of the hole the rest of the drilling motor will
come with it. When engaged for retrieval, care must be used to prevent over stressing the catch
49

50. mandrel. Top sub rotor catch assemblies have options available for an integrated float or ported
rotor catch mandrel for rotor by-pass (jetting).
DIFFERENTIAL PRESSURE
To compensate for reduced elastomer strength at higher temperatures the amount of
elastomer loading from drilling should be reduced accordingly.
The reduction in loading will offset the reduction in elastomer strength and help reduce
loss in life expectancy associated with temperature. The loading that occurs on the
elastomer is directly related to the differential pressure applied across the power section
while drilling.
The Load Curve Scaling Factors at Temperature chart can be used as a guideline to
scale the differential pressure based on temperature.
The differential scaling factor can be used in two ways.
1.To limit the maximum differential pressure on a specific motor configuration
based on temperature
2.To adjust the operating differential pressure on a specific motor configuration for a
different temperature
The maximum differential pressure (maximum operating differential pressure)
indicated on each motor spec sheet is based on operating at temperatures below 140ºF
(60ºC). At temperatures above this the maximum differential pressure must be scaled
down. To calculate, find the DSF (Differential Scaling Factor) for the maximum
expected downhole circulating temperature. Multiply this number by the maximum
differential pressure indicated on the motor spec sheet to determine the new maximum
differential pressure.
New Max. differential pressure = Max. differential pressure x DSF
(Temp. adjusted) (As per spec)
50

51. If an ideal operating differential pressure is known for a drilling application at a specific
temperature, the DSF can be used to adjust the operating differential pressure accordingly for a
different temperature. To calculate a new operating differential pressure, find the DSF for both
the old temperature and the new temperature. Multiply the old differential pressure by the new
temp DSF divided by the old temp DSF to determine the new differential pressure required.
New Differential Pressure = Old Diff. Pressure x New Temp. DSF
`
Old Temp. DSF
7.0 Advances in directional drilling:
Rotary steerable tools were introduced to the oil and gas industry in the early 1990’s.
Two basic types emerged; “push-the-bit” and “point-the-bit”. Pushing the bit refers to exerting
lateral side force on the bit as it drills ahead. Pointing the bit involves bending the assembly so
that the bit is pointed toward the intended direction while drilling. Point-the-bit is generally
acknowledged as being superior; resulting in smoother well bores with increased dogleg
capability.
OBJECTIVES OF ROTARY‐STEERABLE SYSTEM
• Better well placement
• Smoother wellbores
• Larger operating envelopes
• Enhanced productivity
• Reduced nonproductive time (NPT)
7.1 OPERATIONAL OVERVIEW OF ROTARY‐STEERABLE SYSTEM
The Revolution® system is the first 4 ¾-in. rotary steerable system to use point-the-bit
drilling technology for improved borehole quality and bit life. The Revolution® uses a near-bit
stabilizer to orient the drill bit axis with the axis of the desired hole. Experience and testing have
shown that point the- bit drills smoother, cleaner wellbores by cutting with the face of the bit.
51

52. The Revolution’s simple, compact design makes it reliable and cost-effective—and easy to scale
up for larger tool sizes.
A non-rotating outer sleeve is used with anti-rotation paddles to restrict it from rotating
with the drillstring. A center drive shaft is incorporated to transmit torque through the tool to the
bit, with the sleeve and shaft being decoupled by bearings. Relative rotation between the center
shaft and the nonrotating outer sleeve drives a hydraulic pump. This pump generates the motive
force required to eccentrically offset the drive shaft within the sleeve. When changes in wellbore
direction are required, hydraulic pistons are activated to deflect the shaft from the stabilizer
sleeve centerline. This shaft deflection forces the bit to point in the opposite direction. The tool’s
onboard navigation control electronics direct the internal hydraulic system via an electrically
operated solenoid. The solenoid energizes particular pistons, controlling toolface and deflection.
Should the sleeve begin to roll, the electronics redirects the hydraulic system to maintain the
required toolface and deflection settings. Sensors mounted on the center shaft measure actual
drillstring toolface, actual deflection and relative rpm between the sleeve and shaft. Power for the
control electronics is provided through an internal lithium battery. The electronics insert also
houses a nearbit inclination sensor, and has provision for near-bit azimuth and gamma ray
measurement capabilities. Uplink telemetry is accomplished with mud pulse via an internal
biphase connection with the PrecisionLWD™ system.
52

53.
BHA CONFIGURATION:
The standard BHA configuration consists of the following elements:
53
The bias unit sleeve, pivot stabilizer and dog sub are all true gauge or very close to it.
Experience and testing have shown that this is the optimum configuration for maximizing
directional performance with the tool. The tool is capable of generating doglegs of up to 12
degrees/100 ft or more with this setup. At 90 degrees inclination tests have also shown that with
zero deflection the tool tends to hold angle or build slightly. Obviously, this is formation
dependent and therefore varies to some degree from well to well. To build angle at 6 degrees/100
ft with the tool with little or no turn, a 0 deg toolface and 50–60% deflection should be initially
selected (a general guide). Monitor the resulting surveys then adjust the setting accordingly to
obtain the required dogleg and counteract any turn. Be aware that formation changes can have a
significant impact on tool response. The assembly achieves the build by deflecting the bias unit
sleeve upwards and internal shaft downwards, which in turn pushes the collar above the pivot
stabilizer downwards. The pivot stabilizer pivots and points the dog sub and bit upwards to build
angle. This is illustrated below:

54. 7.2 Advantages of Rotary Steerable System
The advantages of this technology are many for both main groups of users: geoscientists
& drillers. Continuous rotation of the drill string allows for improved transportation of drilled
cuttings to the surface resulting in better hydraulic performance, better weight transfer for the
same reason allows a more complex bore to be drilled, and reduced well bore tortuosity due to
utilizing a steadier steering model.
The well geometry therefore is less aggressive and the wellbore (wall of the well) is
smoother than those drilled with motor. This last benefit concerns to geoscientists because the
measurements taken of the properties of the formation can be obtained with a higher quality.
Drilling directional wells with a rotary steerable system results in a smoother wellbore.
This results from constant rotation and deflecting the drillstring through adjustments
down-hole.
Rotary-steerable systems (RSS) outperform conventional directional systems by significantly
improving the drilling process through better hole cleaning, higher rates of penetration (ROPs),
precise directional control and extended reach of horizontal wells.
Weatherford's Revolution RSS uses "point-the-bit" technology to deliver a gun-barrel in-
gauge wellbore. The high-quality wellbore provides significant benefits, including improved
formation evaluation, reduced drilling-fluid costs, easier installation of tubular and enhanced
production
In the future, rotary steerable technology must address operator expectations for even
faster rates of penetration. Powered rotary steerable tools will make this possible. Other
enhancements will provide even greater reliability and efficiency. Ultimately, Rotary steerable
drilling will allow companies to drill out the casing shoe and continue drilling to the next casing
point in a single run. With industry costs for nonproductive drilling time estimated at US$ 5
billion per year, rotary steerable systems will be a key to preventing or reducing these significant
losses.
54

55. 8.0 APPLICATIONS OF DIRECTIONAL DRILLING
1. Sidetracking: Side-tracking was the original directional drilling technique. Initially, sidetracks
were “blind". The objective was simply to get past a fish. Oriented sidetracks are most common.
They are performed when, for example, there are unexpected changes in geological configuration
(Figure 3.1).
Fig 3.1 Side tracking Fig 3.2 Inaccessibility
2. Inaccessible Locations: Targets located beneath a city, a river or in environmentally
sensitive areas make it necessary to locate the drilling rig some distance away. A directional well
is drilled to reach the target (Figure 3.2).
3. Salt Dome Drilling: Salt domes have been found to be natural traps of oil accumulating in strata
beneath the overhanging hard cap. There are severe drilling problems associated with drilling a
well through salt formations. These can be somewhat alleviated by using a salt-saturated mud.
Another solution is to drill a directional well to reach the reservoir (Figure 3.3), thus avoiding the
problem of drilling through the salt
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4. Fault Controlling: Crooked holes are common when drilling nominally vertical. This is often
due to faulted sub-surface formations. It is often easier to drill a directional well into such
formations without crossing the fault lines (Figure 3.4).

56. Fig 3.3 Salt Dome drilling Fig 3.4 Fault drilling
5. Multiple Exploration Wells from a Single Well-bore: A single well bore can be plugged back at
a certain depth and deviated to make a new well. A single well bore is sometimes used as a point
of departure to drill others (Figure 3.5). It allows exploration of structural locations without
drilling other complete wells.
Fig 3.5 Multiple wells Fig 3.6 Drilling into shallow offshore reservoirs
6. Drilling into shallow offshore reservoirs: Reservoirs located below large bodies of water which
are within drilling reach of land are being tapped by locating the wellheads on land and drilling
directionally underneath the water (Figure 3.6). This saves money-land rigs are much cheaper.
7. Offshore Multi-well Drilling: Directional drilling from a multi-well offshore platform is the
most economic way to develop offshore oil fields (Figure 3.7). Onshore, a similar method is used
where there are space restrictions e.g. jungle, swamp. Here, the rig is skidded on a pad and the
wells are drilled in “clusters".
8. Multiple Sands from a Single Well-bore: In this application, a well is drilled directionally to
intersect several inclined oil reservoirs (Figure 3.8). This allows completion of the well using a
multiple completion system. The well may have to enter the targets at a specific angle to ensure
maximum penetration of the reservoirs.
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57. Fig 3.7. Offshore Multi-well Drilling Fig 3.8 Multiple Sands from a Single Well-bore
9. Relief Well: The objective of a directional relief well is to intercept the bore hole of a well
which is blowing and allow it to be “killed" (Figure 3.9). The bore hole causing the problem is
the size of the target. To locate and intercept the blowing well at a certain depth, a carefully
planned directional well must be drilled with great precision.
10. Horizontal Wells: Reduced production in a field may be due to many factors, including gas
and water coning or formations with good but vertical permeability. Engineers can then plan and
drill a horizontal drainhole. It is a special type of directional well (Figure 3.10). Horizontal wells
are divided into long, medium and short-radius designs, based on the buildup rates used. Other
applications of directional drilling are in developing geothermal fields and in mining.
Fig 3.9 Relief well Fig 3.10 Horizontal wells
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58. 9.0 DRILLING COMPLICATIONS AND REMEDIES
DRILLING MOTOR STALL
Stalling occurs when the power section is overloaded, stops rotating, and is incapable
of providing enough torque to turn the bit. This may be caused by one, or a
combination, of the following:
• Excessive WOB
• Excessive bend setting or dogleg severity
• Excessive string RPM
• Inadequate hole cleaning or hole sloughing
• Sudden change in formation
VIBRATION
Vibration while drilling is expected. However, the operator can control the level of
vibration that the motor is subject to downhole. Severe downhole vibration can cause
damage to the motor, BHA, drill string, and even surface components.
Some damaging results of vibration include:
• Connection back-off
• Premature bit wear
• Chipped PDC cutters
• Cracking & twist-offs
• Motor & MWD/LWD failures
• Over torqued connections
• Uneven stabilizer wear
• Directional control issues
• Top drive or rotary stalling
• Excessive wear or drill string washout
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59. BIT BOUNCE
Axial vibration is caused by large WOB fluctuations causing the bit to undergo impact
loading. Not only are these vibrations damaging to the bit but also to components in the
BHA. While commonly observed when drilling with tri-cone bits in hard formations, bit
bounce can occur in other situations.
Detecting Bit Bounce
• Erratic fluctuations of the WOB / hook load
• Visible bouncing motion of the top drive and kelly hose
• Slower rate of penetration (ROP)
• Excessive damage / wear to bit
Mitigating Bit Bounce
• Pick up off bottom / work out all torque and vibration
• Decrease RPM / WOB
• Running shock sub in drill string near the bit
Figure 6. Lateral vibration
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59

60. Dog legs ‐ lead to torque (permissible dog leg‐ threshold)
− Have closer interval surveying when drilling with
limber hookups. This takes more time to survey.
− Do not assume that dog-leg is removed by
reaming. Make sure by re-surveying at same
depth.
− Use dog-leg chart to determine the acceptable dog-
leg for each program.
• Plug back and sidetrack well if an excessive dog-leg cannot be eliminated.
Key seats ‐ more problems in soft formation
− Keep dog-legs to minimum
− Use keyseat wipers (hard formations) and string reamers (soft formations)
− Make daily wiper trips
Wall sticking –always a problem when drill string is stationary during survey
and motor run
− Add lubricant (oil) to the mud system
− Keep pipe stationary to a minimum
− Use HWDP (reduces contact area – spiral
DC)
− Use stabilizers & drilling jars
− Design casing program to help reduce open-hole
Hydraulics
− Reduce hydraulics while building angle
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61. − High annular velocities may erode hole while jetting
Lateral drift
− Normally influenced by bedding planes, hence use structural maps for pre-
planning
− Use true rolling-cone bit (zero offset)
− Use rebel tool (azimuth control tool)
− Use jetting with packed BHA
Small hole and Ream Vs. One Pass
− Larger holes more difficult to control
− Dog-legs for larger hole not uniform
− Of course a small hole needs to be opened up to larger hole takes time
Plan Vs Actual
− Plan the well will a lead to the left
− Design lead so that if no walk occurs, one deflection tool run will bring it back to
selected parameters
− Rule of thumb “Never allow yourself to be more than one tool run away from the
target area”
Weight on Bit and Rotary Speed
− Variation is used to control angle & walk
− Because WOB & RPM are reduced, this method is not always conducive to max.
penetration
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62. Off‐bottom rotation
− Creates a ledge and leads to sidetrack
− Aggravates and initiate keyseating
Intersection ‐ Bit and Casing
− Common on multi-platform or drilling pads – develop structural plots (spidal
diagram).
− Curved conductors may be necessary
− Use gyro orientation survey and short course lengths
Hard & Soft Lines
− Soft lines are preferred because hard lines cannot be changed, varied, or extended
(lease or fixed areas). Select big target radius.
Casing wear
− Use rubber pads on the drill string and slow down
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63. 10.0 CONCLUSION:
Directional drilling has become a very important drilling process. It has enabled
producers all over the world to develop subsurface deposits that could never have been reached
economically in any other manner. In this module, directional drilling was defined along with its
historical development. The applications of a directional well as well as the features of a well
profile were also covered. The module also included information on the types of well profiles
and the components of a well plan.
A smaller number of wells, located even at a great distance from sensitive and protected
areas, implies a significant reduction in the infrastructures necessary to develop and keep a field
in production, such as drilling sites, service roads, parking areas, and means of transport. All of
this implies less pressure on the area with great advantages for the environment.
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