Rohin Goyal REPORT

SUMMER INTERNSHIP REPORT Page 1
UNIVERSITY OF PETROLEUM & ENERGY STUDIES
DEHRADUN
SUMMER INTERNSHIP PROJECT
ESSAR OIL LIMITED
DURGAPUR
Directional Well Plan Design in CBM Reservoirs
28 June 2016 – 30 July 2016
UNDER THE MENTORSHIP OF:
Mr. Saurabh Sharma
Manager
Drilling Department, Essar Oil Ltd., Durgapur
SUBMITTED BY:
Rohin Goyal
R870213029
B. Tech Applied Petroleum Engineering –Upstream

CERTIFICATE
To Whom So Ever It May Concern
The Summer Internship Project entitled “Directional Drilling in CBM Reservoirs”
has been successfully completed by Mr. Rohin Goyal, R870213029, under my
guidance and supervision from 28 June 2016 to 30 July 2016 for partial
completion of B. Tech Applied Petroleum Engineering – Upstream from
College of Engineering Studies, University of Petroleum & Energy Studies,
Dehradun.
The project by him was carried out with full sincerity and dedication.
Mr. Saurabh Sharma Dr. Pushpa Sharma
Team Manager Professor
Drilling Department Dept. of Petroleum and Earth Sciences
Essar Oil Limited UPES, Dehradun
Durgapur

Acknowledgement
First and foremost I would like to thank Mr. Saurabh Sharma, Manager – Drilling
Department, for allowing me to undertake a project on the topic “Directional Well
Plan Design in CBM Reservoirs” and express my sincere gratitude for providing
me this great opportunity to learn.
I would like to express gratitude to Mr. Pawan Arora, Head- Drilling and Mr.
Jonathan Tandon of drilling department for providing me the opportunity to work
with them. . Also, I thank the Weatherford, Baker Hughes and NPS Crew and
other onsite companies for solving my queries and doubts whenever needed.
I would like to acknowledge my hearty gratitude towards Mr. Manoj Kumar,
Manager – HR, Dr. Pushpa Sharma, UPES for their support and the prospect of
undertaking the Summer Internship in Essar Oil Limited. Without their guidance it
would have been extremely difficult to grasp and visualize the intricacies of
Directional Drilling and the project theoretically and practically.

Table of Contents
1. INTRODUCTION
1.1 CBM IN INDIA
1.2 RESERVOIR CHARACTERSTICS OF CBM
1.3 PCP
6
2. PURPOSE AND COMPONENT OF DRILL STRING
2.1 DRILL PIPE
2.2 DRILL PIPE SELECTION
2.3 CLASS OF PIPE & THEIR PROPERTIES
2.4 GRADES OF DRILL PIPE AND STRENGTH
12
3. STANDARD BHA CONFIGURATION
3.1 MAKE UP TORQUE
3.2 BUOYANCY &HOOK LOAD
3.3 OVER PULL
20
4. BHA WEIGHT AND WOB
4.1 REQURIED BHA WEIGHT FOR ROTARY
ASSEMBALIES
4.2 BHA REQUIREMENT
4.3 BHA WEIGHT FOR STEEERABLE MOTAR ASSEMBLIES
22
5. TENSION
5.1 STATIC LOAD
24
6. PIPE BURST CALCULATION 26
7. COLLAPSE
7.1 DRILL PIPE COLLAPSE
27

8. SLIPS 27
9. PIPE TORSION
9.1 TORSION
9.2 TORSION AND TENSION
28
10. FATIGUE
10.1 LIMITS
29
11. TOOL JOINT PERFORMANCE
11.1 MAKE UP TORUE AND YIEDL TORQUUE
11.2 COMBINED TORSION AND TENSION IN BHA
12. CRITICAL ROTARY SPEED
12.1 TRANSVERSE VIBRATION
12.2 AXIAL VIBRATION
12.3 HARMONIC VIBRATION
31
13. DRILL STRING DESIGN 32
14. DIRECTIONAL DRILLING AND TRAJECTORY CALCULATION
14.1 DIRECTIONAL DRILLING TOOL
14.2 WELL PATH CALCULATION
14.3 CALCULATE WELL TRAJECTORY
14.4 ANTI COLLISION
35
15. RIG HYDRAULICS
15.1 SURFACE CONNECTION LOSSES
15.2 PIPE AND ANNULAR PRESSURE LOSS
15.3 PRESSURE DROP ACROSS THE BIT
42
16. CONCLUSION 45
17. REFERENCES 46

1. INTRODUCTION
Coal Bed Methane (CBM) refers to an eco friendly natural gas stored in coal seams and generated during the
process of coalification. The largest CBM resources lie in the former Soviet Union, Canada, China, Australia
and United States. However, much of the world’s CBM recovery potential remains untapped. In 2006 it was
estimated that of global resources totaling 143 trillion cubic meters, only 1 trillion cubic meters was actually
recovered from reserves. This is due to a lack of incentive in some countries to fully exploit the resource base,
particularly in parts of the former Soviet Union where conventional natural gas is abundant.
India lacked the infrastructure to commercially exploit associated CBM gas, which delayed its economical
production in the subcontinent. Depletion of conventional resources and increasing demand for clean energy
,forces India to explore alternatives to conventional energy resources.CBM is considered to be one of the most
viable alternatives to combat the situation .With the growing demand and rising oil and gas prices , CBM is
definitely a feasible alternative source.
India has the fourth-largest proven coal reserves in the world which has been estimated at around 4.6 TCM and
therefore considerable prospects exist for exploration and exploitation of CBM in the country. Most of India’s
coal deposits are located in the eastern and north eastern parts of the country. India is one of these let countries
which have undertaken steps through ansparent policies to harness domestic CBM resources. The Government
of India has received overwhelming responses from prospective producers with several multinational and
domestic operators starting exploration and development of CBM fields in India.
1.1 CBM IN INDIA
Having the 3rd
largest proven coal reserves and being the 4th
largest coal producer in the world, India holds
significant prospects for commercial recovery of CBM. Prognosticated CBM resource has been estimated to be
around 70 TCF.
State No.of Blocks Area (Sq.Km)
WestBengal 4 1308
Jharkhand 6 1326
MadhyaPradesh 5 2648

Rajasthan 4 3972
Chattishgarh 3 1917
Andhra Pradesh 2 1136
Maharashtra 1 503
Gujarat 1 790
Total 26 13600
Essar oil has total 5 secured CBM blocks in India having more than 10 TCFof reserves.
Block Area(Sq. Km)
Sohagpur 339
IBvelly 209
Raniganj 500
Rajmahal 1128
Talchir 557

Fig 2.CBM Blocks in India

Raniganj Block
Formation Depth
From(m)
Depth
To(m)
Thickness (m) Lithology
Topsoil 0 30 30 Alluvium soils.
Tertiary 20 190 170 Coarse to medium grained
sandstone, yellowish to
brownclay.
Panchet 190 410 220 Sandstone ,greenish to light
Grayish shale, chocolate brown
clay & claystone.
Raniganj 410 960 550 Medium to fine grained
Sandstone, Siltstone, and shale.
Barren
Measure
960 Silty shale with thin bands
Ironstone (siderite) and
sandstone.
1.2 RESERVOIR CHARACTERISTIC OF CBM
The term coal refers to a sedimentary rock which contains more than 50% by weight and 70% by volume of the
organic material consisting of coal, hydrogen and oxygen in addition to inherent moisture. Although the term
methane is generally used in industry; the produced gas has constituent mixture of C1, C2 and traces of C3, and
heavier N2 and CO2. Methane as hydrocarbon constituent of coal is of interest for two reasons:-

∑ Methane is generally present in high number in coal, depending on composition, temperature, pressure,
and other factor.
∑ One of many molecular species trapped in the coal methane can easily liberated by sampling reducing
the pressure in the bed.
Reservoir characteristic of coal is complex because they are characterized by two distinct porosity systems:
∑ Primary porosity system: - The matrix primary porosity system in these reservoirs is composed of very
fine pores “Micro-pores” with extremely low permeability. These micro-pores contain a large internal
surface area on which substantial quantities of gas may be absorbed.
∑ Secondary porosity system: - The secondary porosity system (macro-pores) of coal seams consists of the
natural fracture network of cracks and fissure s inherent in all coals. The macro-pores are known as
cleats, act sink to the primary porosity system and provide permeability for the fluid flow. They act as a
conduit to the production.
The cleats are mainly composed of the following two components:-
∑ Face cleats: - The face cleats are conceptually throughout the reservoir and are capable of draining large
areas.
∑ Butt cleats: - The butt cleats contact a smaller area in reservoir and are capable of draining smaller areas.
With production, the cleats properties experience changes due to the following two distinct and opposing
mechanisms:-
∑ Cleat porosity and permeability decline due to compaction and reduction in the net stress Δσ.
∑ Cleat porosity and permeability increase due to coal matrix shrinkage as a result of gas desorption.
1.3 PCP
A progressive cavity pump is type of positive displacement pump and is also known as eccentric screw pump or
cavity pump. It transfer fluid by means of the progress, through the pump of a sequence of small, fixed shaped,

discrete cavities, as its rotor is turned. This leads to the volumetric flow rate being proportional to the rotation
rate (bi directional) and to low levels of shearing being applied to the pumped fluid.
The progressive cavity pump consists of a helical rotor and a twin helix, twice the wavelength and double
helical hole in a rubber stator. The rotor seals tightly against the rubber stator as it rotate, forming a set of fixed-
size cavities in between. The cavities move when the rotor is rotated but their shape or volume does not change.
The pump material moves inside the cavities.
2. PURPOSE AND COMPONENT OF THE DRILL STRING
The drill string could serve several purposes to include the following:
(a). It provides a fluid conduit from the drilling rig to the drilling bit.
(b). Impartation of rotary motion to the drill bit.
(c). It allows weight to be set on the bit.
(d). It is designed to lower and raise the bit in the well.
The following will be examined and discussed in the design of the drill string:
Drill Pipe
Drill collars
Accessories; Heavy wall drill pipe HWDP.
Drill Bits and Bottom Hole Assembly
2.1 DRILL PIPE
The drill pipe is a seamless pipe with threaded connections, known as tool joint; most tool joints are
made from AISI 4140 steel forgings, tubing or bars stock. The major portion of the drill string is the drill
pipe, which consists of three components: a tube with a pin tool joint that is welded to one end and a box

tool joint welded to the other. Drill pipes are subjected to heat treatment to improve its strength as defined
by API specification. The drill pipe is the longest section of the drill string, which transmits rotation and
drill mud under pressure to the bit. The drill pipe is subjected to different types of loading conditions:
a). Axial stress; due to the weight carried and its own weight.
b). Radial stress; due to the well bore pressure.
c) Cyclic stress reversal due to bend in the dog legs.
The drill pipe must be able to withstand all these loads. It is manufactured as seamless pipe with external
upset (EU), internal upset (IU) or internal external upset (EIU). An upset is an increment in the metal size.
The drill pipe is manufactured in three ranges:
Range 1, (18-22ft),
Range 2, (27-30 ft),
Range 3, (38-45).
2.2 DRILL PIPE SELECTION
The Drill pipe is to provide a fluid conduit for pumping drilling mud, imparting rotary motion to the
bit and for drill stem testing and squeeze cementing. Basic factors for consideration in drill string design
includes: collapse, tension, dogleg severity and slip crushing. Collapse together with tension primarily
applies to weight selection, grades and couplings. High- strength pipe is required in the lower sections of
the drill string for collapse resistance. Tension is considered to dictate the higher strength at the top of the
well. “Classes” are given to dill pipes to drill pipe to account for its weight, grade and class. The
established guidelines by API for pipes selection is given below in (table 1). Drill pipe classification is an
essential factor in designing a drill string; the amount and type of wear affect the properties of the pipe and
its strengths.

2.3 CLASSES OF PIPES AND THEIR PROPERTIES
Classes of Pipe Properties
New Never been used, No wear
Premium Uniform wear and a minimum wall thickness of 80%.
Class 2 Allows drill pipe with a minimum wall thickness of 65% with all
wear on one side so long as the cross-sectional area is the same as
premium class; that is to say based on not more than 20% uniform
wall reduction
Class 3 Minimum wall thickness of 55%, all wear on the side.

2.4 GRADES OF DRILL PIPE AND STRENGTH PROPERTIES
Grade letter designation Assumed average yield
strength (psi) Used
for collapse
Minimum Yield (psi)um
Yield
D-55 65000 55000
E-75 85,000 75000
x-95 110000 95000
G-105 120000 105000
S-135 145000 135000
2.5 THREAD TYPES & NUMBERED CONNECTIONS (NC)
Tool joints are short sections of pipe that are attached to the tubing portion of drill pipe by means of
using a flash welding process. The internally threaded tool joint is called a “box”, while the externally
threaded tool joint if the “pin”.
API specifications also apply to tool joints:
• Minimum Yield Strength = 120,000 psi
• Minimum Tensile Strength = 140,000 psi
The tool joints on drill pipe may contain internal and/or external upsets. An upset is a decrease in
the ID and/or an increase in the OD of the pipe which is used to strengthen the weld between the pipe and

the tool joint. It is important to note that under tension, the tool joint is stronger than the tubular. 50,000
160,000
The different thread styles and forms used in the oil industry. The most common thread style is the
Numbered Connection (NC). The thread has a V-shaped form and is identified by the pitch diameter,
measured at a point 5/8 inches from the shoulder; the gauge point, multiplied by 10,
2.6 DRILL COLLAR SELECTION
Drill collars are the predominant component of the bottom hoe assembly (BHA). Both slick and spiral drill
collars are used. In areas where differential sticking is a possibility spiral drill collars and spiral heavy-
walled Drill pipe (HWDP) should be used in order to minimize contact area with the formation. The drill
collars are the first section of the drillstring to be designed. The length and size of the collars will affect the
grade, weight and dimensions of the drill pipe to be used. Drill collar selection is usually based on buckling
considerations in the lower sections of the string when weight is set on the bit. The design approach that
satisfies this criteria is the buoyancy factor method.
2.6.1 BUOYANCY FACTOR METHOD
Drill collars are used to provide weight for use at the bit and at the same time keep the drill pipe in tension.
Drill collars have a significantly greater stiffness when compared to drill pipe and as such can be run in
compression. Drill pipe, on the other hand will tend to buckle when run in compression. Repeated buckling
will eventually lead to early drill pipe failure by fatigue. Since elastic members can only buckle in
compression, fatigue failure of pipe can be eliminated by maintaining drill pipe in tension. Research and
field experience proved that buckling will not occur if weight on bit is maintained below the buoyed
weight of the collars. In practice weight on bit should not exceed 85% of the buoyed weight on the collars.

2.6.2 BENDING STRENGTH RATIO
The bending strength ration (BSR) is defined as the ratio of relative stiffness of the box to the pin for a
given connection. From field experience, a BSR value of 2.5 gives a balanced connection. Above 2.5 BSR,
there is a risk of premature failure in the pin and a BSR of below 2.5 gives a risk of premature failure in the
box.
STIFFNESS RATIO (SR)
The stiffness ratio (SR) is defined as follows:
SR = Section Modulus of lower section tube /Section modulus of upper section tube From field
experience, a balanced BHA should have:
SR = 5.5 for routine drilling
SR = 3.5 for severe drilling or significant failure rate experience
Tool joint
2.7 DRILL COLLAR PROFILES,
Slick Drill Collars
As the name implies, slick drillcollars have the same nominal outside diameter over the total length of the
joint, these drill collars usually have the following profiles:
A slip recess for safety, and An elevator recess for lifting.

Spiral Drill Collars
Spiral drill collars are used primarily to reduce the risk of differential sticking. The spirals reduce the
weight of the collar by only 4 -7% but can reduce the contact area (proportional to sticking force) by as
much as 50%.
Square Drill Collars
These are used in special drilling situations to reduce deviation in crooked hole formations. They are
used primarily due to their rigidity.
2.8 HEAVY-WALLED DRILL PIPE (HWDP)
The HWDP has the same OD as a standard Drill pipe but with much reduced inside diameter
(usually 3") and has an extra tool joint. In the following figure; figure a is a standard HWDP and figure b is
a spiral type. HWDP is used between standard Drill pipe and drillcollars to provide a smooth transition
between the section moduli of the drillstring components. HWDP can be distinguished from standard Drill
pipe by an integral wear center wear pad which acts as a stabilizer thereby increasing the overall stiffness
of the drillstring. In directional and horizontal wells, HWDP is used to provide part or all of the weight on
bit while drilling.

Figure 6 : Type of HWDP
2.9 STABILISERS
Stabilizers are tools placed above the drill bit and along the bottom hole assembly (BHA) to control
hole deviation, dogleg severity and prevent differential sticking. They achieve these functions by
centralizing and providing extra stiffness to the BHA. Improved bit performance is another beneficiary of
good stabilization. There are basically two type of stabilizers:
• Rotating stabilizers
• Non-rotating stabilizers

Figure 7: Types of Stabilizer
3. STANDARD BHA CONFIGURATIONS
The bottom hole assembly refers to the drillcollars, stabilizers and other accessories. All Wells
whether vertical or deviated require careful design of the bottom hole assembly (BHA) to control the
direction of the well in order to achieve the target objectives. Stabilisers and drillcollars are the main
components used to control hole direction. The main means by which directional control is maintained on a
well is by the effective positioning of stabilisers within the BHA. There are five basic types of assembly
which may be used to control the direction of the well
1. Pendulum assembly
2. Packed bottom hole assembly
3. Rotary build assembly
4. Steerable assembly
5. Mud Motor and bent Sub assembly
,

3.1 Make-Up Torque
Part of the strength of the drill string and the seal for the fluid conduit are both contained in the tool
joints. It is very important therefore, that the correct make-up torque is applied to the tool joints. If a tool
joint is not torqued enough, bending between the box and pin could cause premature failure. Also, the
shoulder seal may not be properly seated, resulting in mud leaking through the tool joint, causing a
washout. Exceeding the torsional yield strength of the connection by applying too much torque to the tool
joint could cause the shoulders to bevel outward or the pin to break off the box. Recommended make up
torques for drill pipe and tool joints are listed in the API RP 7G
3.2 Buoyancy & Hook load
Drill strings weigh less in weighted fluids than in air due to a fluid property known as buoyancy.
Therefore, what is seen as the hook load is actually the buoyed weight of the drill string. Archimedes’
principle states that the buoy force is equal to the weight of the fluid displaced. Another way of saying this
is that a buoy force is equal to the pressure at the bottom of the string multiplied by the cross sectional area
of the tubular. This is due to the fact that the force of buoyancy is not a body force such as gravity, but a
surface force.
3.3 Over pull
In tight holes or stuck pipe situations, the operator must know how much additional tension, or pull,
can be applied to the string before exceeding the yield strength of the drill pipe. This is known as over
pull, since it is the pull force over the weight of the string. As depth increases, hook load increases, at a
certain depth the hook load will equal the yield strength (in pounds) for the drill pipe in use. This depth can
be thought of as the maximum depth that can be reached without causing permanent elongation of the drill
pipe (disregarding hole drag as a consideration). Practically, an operator would never intend to reach this
limit. A considerable safety factor is always included to allow for over pull caused by expected hole drag,
tight hole conditions or a stuck drill string. In practice, selection of the drill pipe grade is based upon
predicted values of pick-up load. For a directional well, the prediction of pick-up load is best obtained

using a Torque and Drag program, as well as including the capacity for over pull. Some operators include
an additional safety factor by basing their calculations on 90% of the yield strength values quoted in API
RP7G.
.
4. BHA WEIGHT & WEIGHT-ON-BIT
One important consideration in designing the BHA is determining the number of drill collars and
heavy-weight pipe required to provide the desired weight-on-bit. When drilling vertical wells, standard
practice is to avoid putting ordinary drill pipe into compression (recommended by Lubinski in 1950). This
is achieved by making sure that the “buoyed weight” of the drill collars and heavy-weight pipe exceed the
maximum weight-on-bit. This practice has also been adopted on low inclination, directionally drilled wells.
In other types of directional wells, it must be remembered that since gravity acts vertically, only the weight
of the “along-hole” component of the BHA elements will contribute to the weight-on-bit. The problem this
creates is that if high WOB is required when drilling a high inclination borehole, a long (and expensive)
BHA would be needed to prevent putting the Drill pipe into compression. However, for these high
inclination wells, it is common practice to use about the same BHA weight as used on low inclination
wells. On highly deviated wells, operators have been running Drill pipe in compression for years. Analysis
of Drill pipe buckling in inclined wells, by a number of researchers (most notably Dawson and Paslay), has
shown that Drill pipe can tolerate significant levels of compression in small diameter, high inclination
boreholes. This is because of the support provided by the “low-side” of the borehole. Drill pipe is always
run in compression in horizontal wells, without apparently causing damage to the drill pipe.
4.1 Required BHA Weight for Rotary Assemblies
When two contacting surfaces (i.e. drill pipe and the borehole wall) are in relative motion, the
direction of the frictional sliding force on each surface will act along a line of relative motion and in the
opposite direction to its motion. Therefore, when a BHA is rotated, most of the frictional forces will act
circumferentially to oppose rotation (torque), with only a small component acting along the borehole
(drag).

4.2 BHA Requirements When the Drill string Is Not Rotated
When the drill string is rotated, the component of sliding friction (drag) is small and may be
compensated for by using a safety factor in BHA weight calculations. Drillstring friction for rotary
assemblies will mainly affect torque values. When the drillstring is not rotated (a steerable motor system in
the oriented mode) axial drag can become very significant and drillstring friction should be evaluated. A
proper analysis of drill string friction is more complex and must take into account a number of factors,
including wellbore curvature.
4.3 BHA Weight for Steerable Motor Assemblies
In practice, BHA weight for steerable assemblies on typical directional wells is not a problem for the
following reasons.
• The WOB is usually fairly low, especially when a PDC bit is used.
• When the drill string is not rotated, the drill pipe is not subjected to the cyclical stresses which occur during
rotary drilling.
Therefore, sinusoidal buckling can be tolerated when there is no rotation of the drill string. Helical buckling
however, must be avoided.
Helical buckling occurs at 1.41 FCR, where FCR is the compressive force at which sinusoidal buckling
occurs. Therefore, if BHA weight requirements are evaluated as for rotary drilling, the results should be
valid for steerable systems in the oriented mode except for unusual well paths which create exceptionally
high values of axial drag. The standard practice of minimizing BHA length and weight for steerable
assemblies has not created any noticeable increase in the incidence of drill string failure, even when long
sections are drilled in the oriented mode.

5. TENSION
5.1 Static Load
The design of the drill string for static tension loads requires sufficient strength in the top most joint
of each size, weight, grade and classification of drill pipe to support the submerged weight of all the drill
pipe plus the submerged weight of the collars, stabilizers, and bit. This load may be calculated as shown in
the following equation. The bit and stabilizer weights are either neglected or are included with the drill
collar weight.
FTEN = [(LDP x WTDP) + (LDC x WTDC)] BF
Where
FTEN = submerged load hanging below this section of drill pipe, lb
LDP = Length of drill pipe, ft WTDP =
Air weight of drill pipe, lb WTdc = Air
weight of drill collar, lb
LDC = Length of drill collar, ft
BF = Buoyancy factor
The tension strength values are based on minimum area, wall thickness and yield strength of the
pipe. The yield strength as defined in API specifications is not the specific point at which permanent
deformation of the material begins, but the stress at which a certain total deformation has occurred. This
deformation includes all of the elastic deformation as well as some plastic (permanent) deformation.
The tensile strength can be calculated from the equation.
Fyield = Ym A
Where

Fyield = Minimum tensile strength,lb
Ym = Specified minimum yield strength,psi
A = cross sectional area, sq.in
If the pipe is loaded to the extent shown in the API formula above it is likely that some permanent stretch will
occur and difficulty may be experienced in keeping the pipe straight
5.2 Margin of Over Pull
To prevent this condition a design factor of approximately 90% of the tabulated tension value is
recommended.
Fdesign = Fyield x 0.9
Where
Fdesign = minimum tensile strength, lb Fyield =
minimum tensile strength, lb
0.9 = a constant relating proportional limit yield to strength
The difference between the calculated load FTEN and the maximum allowable tension load represents the Margin
of over Pull (M.O.P.).
M.O. P. = Fdesign - FTEN
The same values expressed as a ratio may be called the Safety Factor (S. F.)
S.F = Fdesign / Ften

The selection of the proper safety factor and/or margin of over pull is of critical importance and
should be approached with caution. Failure to provide an adequate safety factor can result in loss or
damage to the drill pipe while an overly conservative choice will result in an unnecessarily heavy and more
expensive drill string.
Normally the designer will desire to determine the maximum length of a specific size, grade, and
inspection class of drill pipe which can be used to drill a certain well. By combining the above equations
the following equation results:
Ldp = (Fdes – MOP) / ( WTdp x BF) – Ldc xWTdc / WTdp
6. Pipe Burst Calculation
The drill pipe internal yield pressure can be calculated as follows
Pi = 2 Ym Wt. / D
Where
Pi = Burst pressure, psi
Ym = Specified minimum yield strength, psi
Wt. = pipe wall thickness, inches
D = Outside pipe diameter, inches

7. COLLAPSE
7.1 Drill pipe collapse
Drill pipe is used for several purposes, including providing a fluid conduit for pumping drilling
mud, imparting rotary motion to the drill bit, and conducting special operations such as drill stem testing
and squeeze cementing. Drill stem testing (DST) causes the most severe collapse loading on the drill pipe.
API specifications for collapse resistance of drill pipe is calculated assuming either plastic,
transition, or plastic failure based on the pipes D/t (diameter / wall thickness ratio). The applicable
equations can be found in the API RP 7G publication.
8. Slip crushing
The maximum allowable tension load must be determined to prevent slip crushing. In an analysis of
the slip crushing problem, Reinhold, Spini, and Vreeland, proposed an equation to calculate the relation
between the hoop stress (SH) caused by the action of the slips and the tensile stress in the pipe (ST),
resulting from the load on the pipe hanging in the slips. If the dimensions for the cross-sectional area of the
pipe (A) and the cylindrical surface are of the pipe under the slips (AS) are used, the equation can be
presented as follows:
(SH / ST) = [1 + DK/2Ls + (DK/2Ls) 2
]1/2
Where
Sh = Hoop stress, psi

ST = Tensile stress, psi
D = Outside diameter of pipe, inches
Ls = Length of slips, inches
K = lateral load factor on slips 1 / tan (y + z)
Y = slip taper, usually 90
27' 45"
Z =arc tan µ
µ = coefficient of friction (0.08)
Slips are typically 12 or 16 in. long. The friction coefficient ranges from 0.06-0.14. Inasmuch as
tool joint lubricants are usually applied to the back of rotary slips, a coefficient of friction of 0.08 should be
used for most calculations.
The equivalent tension load from slip crushing can be calculated as follows
Ts = TL x (SH /ST)
Where
Ts = Tension from slip crushing,
TL = tension load in string
9. PIPE TORSION
9.1 Torsion Only
Drill pipe torsional yield strength when subject to pure torsion is given by the following
Q = (0.096167 x J x Ym)/ D
Where

Q = minimal torsional yield strength, ft-lb
J = polar moment of inertia
Ym = Minimum unit yield strength, psi
9.2 Torsion and Tension
When drill pipe is subject to both torsion and tension, as is the case during drilling operations, the minimum
torsional yield strength under tension is given as follows
Qt = (.096167 x J / D) (Ym2 – P2
/A2
)1/2
Where
Qt = minimal torsional yield strength under tension, ft – lb
J = polar moment of inertia = (π/32) (D4
- d4
) D
= pipe OD, inches d = Pipe ID, inches
Ym = Minimum unit yield strength, psi
P = total load in tension, lbs
A = cross - sectional area, in2
10. FATIGUE
10.1 Limits
The most common type of drill pipe failure is fatigue wear. It generally occurs in dog legs where the pipe
goes through cyclic bending stresses. These stresses occur because the outer wall of the pipe in a dog leg is
stretched and creates a greater tension load. As the pipe rotates a half cycle, the stresses change to the other
side of the pipe, For example, the stress may change from 50,000 psi to -20,000 psi and again to 50,000 psi
in the course of one cycle or rotation of the pipe. Fatigue damage from rotation in dog legs is a significant
problem if the angle is greater than some critical value. Lubinski has published several works that describe

this value. Rotation in angles below this value does not cause appreciable fatigue. The maximum
permissible dogleg severity for fatigue damage consideration can be calculate with the following equations
C = (432000 σb tanh K L) / (π E D K L)
Where
K = [T / E I] 1/2
C = maximum permissible dogleg severity o
/100 ft
E = Young’s modulus psi
30 x 10 6
for steel
10.5 x 106
for aluminum
D = Drill pipe outer diameter, inches
L = Half the distance between tool joints, 180 inches for range 2 pipe T =
tension below the dog leg, lb
. σb =maximum permissible bending stress, psi
I = Drill pipe moment of inertia π/64 (D4
-d4
)
The maximum permissible bending stress, σb , is calculated from the buoyant tensile stress, σ t(psi), in
the dogleg with the following equations:
σt= T /A
Where A = cross-sectional area of drill pipe body, in2

12. CRITICAL ROTARY SPEEDS
12.1 Transverse Vibration
The approximate critical rotary speeds which induce nodal (transverse) vibration can be calculated using the
following shown below.
Critical RPM = 476000/L2
[D2
+ d2
]1/2
Where
L = Length of one pipe, inches
D = Outside diameter of pipe, inches
d = Inside diameter of pipe, inches
12.2 Axial Vibration
The approximate critical rotary speeds which induce pendulum or spring (axial) vibration can be calculated
using the following shown below
Critical RPM = 258000/L (ft)
Where
L (ft) = total length of string, feet
12.3 Harmonic Vibrations
Secondary and higher harmonic vibrations will occur at 4, 9, 16, 25, 36, … etc. time the speed in the above
equation. Vibrations of spring pendulum type are probably less significant than nodal type. Each higher
harmonic of the spring pendulum type vibration is also less significant. Care should be taken to avoid

operating under these conditions which would be the critical speed for both types of vibration because the
combination would be particularly bad.
13 DRILL STRING DESIGN
Available Data
Available Data
MD 1448 m
KOP 100 m
TCS 650 m
INCLINATION 45°
BUR 3°/30 m
TVD 1269 m
Used Data
Bit size 8 ½
depth 1448 m 4749.44 ft
Mw 8.9 ppg
casing size 5 ½
casing coupling 6.625
BF 0.86
WOB 24000lbs

SAFETY FACTORS USED :
Slip details
Tension 0.9 length (in) 12
colapse 1.15 arcatn Z
Burst 1.2 slip taper y 9
MOP 100000
lateral load
factor K 4
BHA 1.15 coeff of fric μ 0.08
Torsion 1
Table : Safety Factor
PIPES OD ID Z BRR PPFT LENGTH FCRITCAL TotalLength Area Ym(yield) thickness(t)
DC 6.75 2.75 29.34664352 3.813951772 97.63 30 199570.7 240 29.83 2
HWDP 4.5 2.75 7.694550239 1.853743015 42 30 21092.97 180 9.9596875 0.875
DP 4.5 3.85 4.150818197 #DIV/0! 16.6 30 10132.69 4350 4.2605875 75000 0.325

VARIABLE FORMULA VALUE
Neutral point 404.244853
Length of DC
(WOB+L WP(1-B)/(WC-
(1-B)(WP-WC) 220.8753999
No. Of DC 7.362513329 8 240
Required length neutral point -drill collar 164.244853
No. Of HWDP Required length /hwdp 5.474828433 12 HWDP>6
No. Of DP depth -dc-hwdp 4149.44 138.31 139
The neutral point is usually defined as the point in the drillstring where the axial stress changes from
compression to tension. The location of this neutral point depends on the weight-on-bit and the buoyancy
factor of the drilling fluid. In practice, since the WOB fluctuates, the position of the neutral point
changes. It is therefore quite common to refer to a “transition zone” as the section where axial stress
changes from compression to tension.
Length of Neutral point is 404.24 ft. Length covered by Drill collars is 240ft (8 DC). The rest of the length till
Neutral point should be covered by HWDP (minimum 6 ) as calculated .To keep the Neutral point in transition
zone , 12 HWDP will be used .
139 drill pipes will be used to cover the rest of the depth .

Tensile Strength
F tension
ldp*Wdp+ldc*W
dc+lhwdp*Whwdp 105656.4
F yield Ym *A 319544.0625
F Design 0.9*F yield 287589.6563
Margin of Overpull F design - F tension 181933.2563
In tight holes or stuck pipe situations, the operator must know how much additional tension, or pull, can be
applied to the string before exceeding the yield strength of the drill pipe. This is known as Overpull, since it is
the pull force over the weight of the string.
14. DIRECTIONAL DRILLING AND TRAJECTORY CALCULATION
Directional drilling is the process of drilling a well bore intentionally in non-vertical path with sustained and
proactive attention to the preferred path. A well may be drilled directional due to many reasons like land
acquisition problems, salt dome, side tracking due to fish, multiple target , thin formation etc.
For planning a directional well parameters like surface coordinate, target coordinate and TVD to the Target
must be known. Then the best profile which is suitable for this input parameters is selected. There are three
types of well profile included in directional well design.
Type I: Build & Hold Profile, consisting of a kick of point, build up section and a tangent section

Type II: S profile consisting of a vertical section, kick off point, buildup section, tangent section, drop and hold
section to the target
Type III: Deep kick off Profile, Consisting of a vertical section, deep kick of point and hold section to the target
Kick off point is the point at which the well is kicked off from vertical. The kick off point is decided on the
basis of certain parameters like type of formation, well profile and proximity of other wells.
Build Up rate (BUR): The well kicked off is built to the desired angle at certain rate called Build Up rate, it is
decided on the basis of total depth of well, mechanical limitation of drill string and other production
equipments. A build up rate of 3ᵒ
/30 m is generally preferred
Inclination angle is the angle between the vertical and the axis of the well bore at any point.The maximum angle
of inclination that can be acquired with the given vertical depth to target, BUR and KOP has to be calculated.
If R > D2
If R< D2
Where,
V1 = Vertical depth to kick of point (m).
V3 = Vertical depth to target (m).
D2 = Departure (m).
Azimuth of a well is the direction of well at any point measured in reference to the geographic north. The
azimuth value from MWD tool should be optimized for changes in magnetic declination. Initially azimuth is
calculated using surface and target coordinate but during operation azimuth can vary due to bit walk, dip
reactive torque. Azimuth value is continuously monitored using MWD tool and in case of any discrepancies
from the planned trajectory the corrections are incorporated in section to be drilled further.
Radius of curvature of buildup section is the radius of arc joining the KOP and the end of build.
Azimuth = A*tan(α)
αmax = Atan-Acos [*sin[Atan ()]
αmaX = 180 - Atan[] - Acos [ *sin[Atan( )]

Where,
R = Radius of curvature of buildup (m)
BUR = Buildup rate (ᵒ
/30)
End of build is the point at which the well bore has achieved the desired inclination so that the well will
intersect with the given target. Maximum inclination is achieved at the end of build which is preferably above
the top of coal seam .It is not advisable to alter trajectory in coal beds as the drill string can stuck up in the
formation
Departure is the horizontal displacement between surface coordinate and target coordinate.
Where,
D = Departure (m)
&= Change in northing and easting (m)
Build UP section
∑ Measured length of Buildup Section (m)
∑ Vertical Length of Buildup (m)
V2-V1= R * sinα
∑ Horizontal displacement (m)
D1=R*(1-cosα)
Tangent Section
∑ Measured length of tangent section (m) Figure 7 : Directional Trajectory
∑ Vertical length of tangent section (m)
V3-V1= MD3*Cosα
)

∑ Total Measured Depth = KOP+ MD2+MD3
14.1 DIRECTIONAL DRILLING TOOL
BENT SUB - MUD MOTOR ASSEMBLY: The bent sub mud motor assembly is used to kick of the well. PDM
is used it consist of power section, By pass valve, Bent sub, Near bit stabilizer .The power section of mud motor
consist of a helical steel rotor fitted inside a spirally shaped elastomer molded stator .The torque and rotation
depends upon number of lobes. Stator always have one extra lobe than the rotor. If the number lobes is less the
mud motor will be having high RPM and low torque and vice versa.
The mud flowing under pressure fills the cavities between dissimilar shapes of the rotor and stator and under the
pressure of the mud the rotor is displaced and begins to rotate. The elliptical motion of rotor is converted to
circular motion by a universal joint.
MWD TOOL: MWD tool measures the directional parameters like azimuth, inclination and sometimes a
gamma sonde is also included for formation analysis, it relays the data to the surface in form of mud pulse. A
positive mud pulse telemetry in which mud pulse is transmitted through the drill string by a plunger is used in
industry as in negative pulse MWD the signal is transmitted through the annulus which is less accurate and
affected by borehole condition.
Non Magnetic drill collar: The MWD tool consist of a triaxial accelerometer and a magnetometer which is
housed in a collar made special non- magnetic material. This is because that the MWD tool may get affected by
downhole condition like radiation and magnetic properties of formation. The MWD tool is positioned in the
NMDC using a sub called mule shoe sub.
The well is drilled up to kick off point using a slick BHA assembly and then bent sub mud motor assembly is
added to the BHA .To achieve the required angle after kick of the well the spindle lock of top drive is engaged
so that drill string rotational motion is arrested. The bent sub is preset to an angle of 1.5 degree .The tool face is
oriented in required direction and the drilling is further continued in sliding mode, bit is rotated by the mud
motor and the drill bit is forced to follow the path of bent sub.The well trajectory is continuously monitored
using MWD tool

Standard BHA configuration
∑ Packed Assembly consist of a near bit stabilizer and a string stabilizers at 30 and 60 ft. This type of
assembly is used were dip causes tendency of building an angle or to maintain a vertical profile when
high weight on bit is used.
∑ Pendulum Assembly is used for drop angle back to vertical by gravitational force acting on the bit. It
consist of stabilizer at 30 or 60 ft. away from the bit, as this distance increase drop rate increases.
∑ Fulcrum Assembly consists of a near bit stabilizer which act as pivot or fulcrum of a lever. The length
of the lever is the distance between contact point of drill collar with low side of hole to the top of near
bit stabilizer. As the weight on bit increases the drill bit is forced against the high side of the hole thus
building as drilling progresses. The rate of build increases with increase in WOB, reduction in RPM,
increase in hole angle and reduction in drill collar diameter.
14.2 WELL PATH CALCULATION
TVD() KOP(m) TCS(m) BCS(m)
SURFACE COORDINATE TARGET COORDINATE
Northing(m) Easting(m) Northing(m) Easting(m)
1269 200 617.56 1360 2610042.99 533638.09 2610138.06 534273.05
Azimuth
Azimuth = tan-1
((534273.05-533638.09)/(2610138.06-2610042.99)
=1.422174 (RADIANS)
=81.5259206
Radius of buildup section
R = = 573.2

Departure
As R > D2,
14.3 CALCULATED WELL TRAJECTORY
D = 642.0377765
αmax = Atan-Acos [*sin[Atan ()] = 32.69

COMMENTS MD INC INC(radians) R tvd KOP TVD VS AZIMUTH (radians)NORTHING OFFSETEASTING OFFSET
0 0 0 0 0 0 0
25 0 0 0 25 25 0
100 0 0 0 100 100 100 0
130 3 0.052359878 573.2 30 100 130.0015 0.785617 1.42217 0.116333967 0.776955925
160 6 0.104719755 573.2 59.92 100 159.92078 3.1403148 1.42217 0.465017004 3.105694119
190 9 0.157079633 573.2 89.68 100 189.67581 7.0576391 1.42217 1.045093395 6.979831671
220 12 0.20943951 573.2 119.2 100 219.18505 12.526853 1.42217 1.854973192 12.38874984
250 15 0.261799388 573.2 148.4 100 248.36761 19.532966 1.42217 2.89243657 19.31762316
280 18 0.314159265 573.2 177.1 100 277.1435 28.056774 1.42217 4.154639914 27.74746006
310 21 0.366519143 573.2 205.4 100 305.43386 38.074915 1.42217 5.638123612 37.65515496
340 24 0.41887902 573.2 233.2 100 333.16113 49.559929 1.42217 7.338821539 49.01355155
370 27 0.471238898 573.2 260.2 100 360.24933 62.480336 1.42217 9.2520722 61.79151724
400 30 0.523598776 573.2 286.6 100 386.6242 76.800724 1.42217 11.37263151 75.95402854
END OF BUILD UP 426.67 32.67 0.570199067 573.2 309.4 100 409.43928 90.691604 1.42217 13.42958942 89.69176724
430 32.67 0.570199067 573.2 2.803 100 412.24245 92.489136 1.42217 13.69576761 91.46948298
460 32.67 0.570199067 0 25.25 437.49626 108.68313 1.42217 16.09376935 107.4849401
500 32.67 0.570199067 0 33.67 471.168 130.27511 1.42217 19.29110499 128.8388829
530 32.67 0.570199067 0 25.25 496.42181 146.4691 1.42217 21.68910673 144.85434
520 32.67 0.570199067 0 -8.418 488.00387 141.0711 1.42217 20.88977282 139.5158543
550 32.67 0.570199067 0 25.25 513.25768 157.26509 1.42217 23.28777455 155.5313114
580 32.67 0.570199067 0 25.25 538.51148 173.45908 1.42217 25.68577629 171.5467685
TOP OF COAL SEAM 617.56 32.67 0.570199067 0 31.62 570.12925 193.73396 1.42217 28.68807446 191.5981209
640 32.67 0.570199067 #REF! 18.89 589.01909 205.84706 1.42217 30.48177976 203.5776828
670 32.67 0.570199067 0 25.25 614.2729 222.04105 1.42217 32.87978149 219.5931399
700 32.67 0.570199067 0 25.25 639.52671 238.23504 1.42217 35.27778322 235.608597
730 32.67 0.570199067 0 25.25 664.78051 254.42903 1.42217 37.67578496 251.6240541
760 32.67 0.570199067 25.25 690.03432 270.62302 1.42217 40.07378669 267.6395112
790 32.67 0.570199067 25.25 715.28813 286.817 1.42217 42.47178843 283.6549683
820 32.67 0.570199067 25.25 740.54193 303.01099 1.42217 44.86979016 299.6704255
850 32.67 0.570199067 25.25 765.79574 319.20498 1.42217 47.2677919 315.6858826
880 32.67 0.570199067 25.25 791.04954 335.39897 1.42217 49.66579363 331.7013397
910 32.67 0.570199067 25.25 816.30335 351.59296 1.42217 52.06379537 347.7167968
940 32.67 0.570199067 25.25 841.55716 367.78695 1.42217 54.4617971 363.7322539
970 32.67 0.570199067 25.25 866.81096 383.98094 1.42217 56.85979884 379.747711
1000 32.67 0.570199067 25.25 892.06477 400.17493 1.42217 59.25780057 395.7631681
1030 32.67 0.570199067 25.25 917.31857 416.36892 1.42217 61.6558023 411.7786252
1060 32.67 0.570199067 25.25 942.57238 432.5629 1.42217 64.05380404 427.7940824
1090 32.67 0.570199067 25.25 967.82619 448.75689 1.42217 66.45180577 443.8095395
1120 32.67 0.570199067 25.25 993.07999 464.95088 1.42217 68.84980751 459.8249966
1150 32.67 0.570199067 25.25 1018.3338 481.14487 1.42217 71.24780924 475.8404537
1180 32.67 0.570199067 25.25 1043.5876 497.33886 1.42217 73.64581098 491.8559108
1210 32.67 0.570199067 25.25 1068.8414 513.53285 1.42217 76.04381271 507.8713679
1240 32.67 0.570199067 25.25 1094.0952 529.72684 1.42217 78.44181445 523.886825
1270 32.67 0.570199067 25.25 1119.349 545.92083 1.42217 80.83981618 539.9022821
1300 32.67 0.570199067 25.25 1144.6028 562.11482 1.42217 83.23781791 555.9177393
1348.3 32.67 0.570199067 40.66 1185.2615 588.18714 1.42217 87.09860071 581.7026252
BCS 1360 32.67 0.570199067 9.849 1195.1104 594.50279 1.42217 88.03382138 587.9486535
1390 32.67 0.570199067 25.25 1220.3642 610.69678 1.42217 90.43182312 603.9641106
1420 32.67 0.570199067 25.25 1245.6181 626.89077 1.42217 92.82982485 619.9795677
TARGET DEPTH 1448.2 32.67 0.570199067 23.74 1269.3566 642.11312 1.42217 95.08394648 635.0340974
Figure 8 : Calculated Directional Trajectory
Vertical Section

The vertical profile of a well is direction straight from the slot to the target in a plane. The total horizontal
displacement projected in to this plane is called vertical section.
Figure 9: Vertical Section
PLAN VIEW
Plan view is a plot that displays N/S & E/W of a well path projected to a horizontal surface plane.
Figure 10 : Plan view

WELL#EDG-075-D3
MD (m)
Inclination
(®degrees)
Azimuth
(®degrees) TVD (m) VS (m)
Delta
Northing
Delta
Easting BUR (®/m)
0 0 0 0 0 0 0 0
30 0 0 30 0 0 0 0
60 0 0 60 0 0 0 0
200 0 0 200 0 0 0 0
230.0022098 3
138.931
229.9885 0.785277 0.5920411 -0.51589 3/30m
260.0044197 6
138.931
259.8948 3.138954 2.36654166 -2.06216 3/30m
290.0066295 9
138.931
289.6369 7.054581 5.3186379 -4.63457 3/30m
320.0088394 12
138.931
319.1334 12.52142 9.44023832 -8.22605 3/30m
350.0110492 15
138.931
348.3033 19.5245 14.7200459 -12.8268 3/30m
380.0132591 18
138.931
377.0667 28.04462 21.1435891 -18.4241 3/30m
410.0154689 21
138.931
405.3448 38.05842 28.6932614 -25.0028 3/30m
440.0176787 24
138.931
433.0601 49.53845 37.3483696 -32.5447 3/30m
470.0198886 27
138.931
460.1366 62.45326 47.0851907 -41.0292 3/30m
500.0220984 30
138.931
486.5 76.76744 57.8770369 -50.433 3/30m
510.022835 31
138.931
495.1168 81.84314 61.7037381 -53.7675 3/30m

14.4
AN
TI –
CO
LLI
SIO
N
Planning of well from a pad begins with plotting of survey of already drilled wells and superimposing it with
planned well in the same plot. This type of plot is called spider plot and shows N/S & E/W. Spider plot shows
the possibility of collision of planned well with already existing one and allows to take numerous contingencies
like shutting of the producing well in the planned well trajectory ,changing well profile etc.
520.0235716 32
138.931
503.6437 87.06844 65.6432353 -57.2003 3/30m
526.054016 32.603 138.931 508.7409 90.29094 68.072765 -59.3174 0
561.665488 32.603 138.931 538.7409 109.4789 82.5391069 -71.9231 0
597.277001 32.603 138.931 568.7409 128.6669 97.0054656 -84.5288 0
632.888514 32.603 138.931 598.7409 147.855 111.471824 -97.1346 0
668.500027 32.603 138.931 628.7409 167.043 125.938183 -109.74 0
704.11154 32.603 138.931 658.7409 186.231 140.404542 -122.346 0
739.723054 32.603 138.931 688.7409 205.419 154.870901 -134.952 0
775.334567 32.603 138.931 718.7409 224.607 169.337259 -147.557 0
810.94608 32.603 138.931 748.7409 243.795 183.803618 -160.163 0
846.557593 32.603 138.931 778.7409 262.983 198.269977 -172.769 0
882.169106 32.603 138.931 808.7409 282.1711 212.736335 -185.375 0
917.780619 32.603 138.931 838.7409 301.3591 227.202694 -197.98 0
953.392133 32.603 138.931 868.7409 320.5471 241.669053 -210.586 0
989.003646 32.603 138.931 898.7409 339.7351 256.135412 -223.192 0
1024.61516 32.603 138.931 928.7409 358.9231 270.60177 -235.798 0
1060.22667 32.603 138.931 958.7409 378.1111 285.068129 -248.403 0
1095.83819 32.603 138.931 988.7409 397.2991 299.534488 -261.009 0
1131.4497 32.603 138.931 1018.741 416.4872 314.000847 -273.615 0
1167.06121 32.603 138.931 1048.741 435.6752 328.467205 -286.22 0
1202.67272 32.603 138.931 1078.741 454.8632 342.933564 -298.826 0
1238.28424 32.603 138.931 1108.741 474.0512 357.399923 -311.432 0
731.5305941 32.603
138.931 1125 484.4505 365.240255 -318.264 0
747.8417355 32.603
138.931 1138.741 493.2392 371.866281 -324.038
0

15. RIG HYDRAULICS
We can divide the circulating system into four sections:
1. Surface connections.
2. Pipes including Drill pipe, heavy walled Drill pipe and drill collars.
3. Annular areas around Drill pipes, drill collars, etc.
4. Drill bit
15.1 Surface connection losses
Pressure losses in surface connections are those taking place in standpipe, rotary hose etc... The
task of estimating surface pressure losses is complicated by the fact that such losses are dependent on the
dimensions and geometries of surface connections. These dimensions can vary with time, owing to
continuous wear of surfaces by the drilling fluids. The following general equation may be used to evaluate
pressure losses in surface connections:
P = E x MW 0.8
x Q 1.8
x PV 0.2
psi
Where
MW = mud weight (lbm/gal)
Q = volume rate (gpm)
E = a constant depending on type of surface equipment used PV =
plastic viscosity (cP)

Types of surface equipment
The values of the constant E
15.2 Pipe and Annular Pressure Losses
Pipe losses take place inside the Drill pipe and drill collars. Annular losses take place around the drill
collar and Drill pipe. The magnitude of losses depend upon
(a) Dimensions of Drill pipe (or drill collars), e.g. inside and outside diameter and length
(b) Mud rheological properties, which include mud weight, plastic viscosity and yield point and (c) Type of
flow, which can be laminar, or turbulent

It should be noted that the actual behavior of drilling fluids down hole is not accurately known and
fluid properties measured at the surface usually assume different values at the elevated temperature and
pressure downhole. Another point to remember is the large possible discrepancy between the pressures
values calculated using the annular flow models three models will be discussed: Bingham Plastic, Power
law and Herschel- Bulkley.
These models approximate the annulus as two parallel plates, with the effects of rotation being ignored.
15.3 Pressure Drop across Bit
For a given length of drill string (Drill pipe and drill collars) and given mud properties, pressure
losses in pipe and annular will remain constant. However, the pressure loss across the bit is greatly
influenced by the sizes of nozzles used, and volume flow rate. For a given flow rate, the smaller the
nozzles the greater the pressure drop and, in, turn the greater the nozzle velocity.
For a given maximum pump pressure, the pressure drop across the bit is obtained by subtracting pipe pressure
and annulus pressure from the pump pressure.

16. CONCLUSION
a) This Drill string calculations will be a guide for any future case, as it will be used to
characterize the reasons that may lead to that failure
b) The major factors that lead to drill string failure, are: dogleg severity, rotary bottom hole
assembly, higher operating torque while drilling, hard formation etc.
c) An excel sheet program is prepared for the directional well plan.

17. REFERENCES
∑ Schlumberger drill string design manual
• Recommended Practice for Drill Stem Design and Operating Limits API recommended
practice 7g sixteenth edition, August 1998
• Drilling Engineering Workbook, Baker Hughes INTEQ
• Well Engineering and construction, Hussain Rabia
• http://www.cnpc.com.cn/cnpc/gcdx/201407/b900930b8bf344b396517e2a8effd8c7/files/
9bb1ebd11d054130aa1ee1280b87693d.pdf
• http://www.schramminc.com/products/drilling-rigs/t500xd-trailer-mounted

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