Report File

TABLE OF CONTENTS :
Sr. no Topics Page no.
1 Certificate 3
2 Acknowledgement 4
3 Introduction 5-6
4 Directional drilling 6-8
5 Parameters for drilling optimization 8-10
6 Weight on Bit 11-15
7 RPM 15-18
8 GPM 18-20
9 Case Study 20-24
10 Tools used in JDIL workshop 25-39
11 Proposed solution (new technology) 40-46
12 References 47

CERTIFICATE
This is to certify that the work contained in this report titled ―“Optimization
of drilling parameters in directional drilling” has been carried out by
 Hitisha Dadlani
 Ketul Khambayata
 Nikhil Gupta
 Raj Rathod
 Satyam Uppal
 Shivam Misra
under supervision of Mr. Satish Jawanjal, General Manager, Directional
Drilling, JINDAL DRILLING AND INDUSTRIES LIMITED and has not been
submitted previously here as a Project.
Mr. Satish Jawanjal,
Mentor

ACKNOWLEDGEMENT
We are highly obliged to Jindal Drilling and Industries Limited and our
mentor Mr. Satish Jawanjal, General Manager, Directional Drilling, JDIL for
giving us such a wonderful platform in the form of project titled “Optimization
of drilling parameters” and necessary infrastructure to enhance our practical
learning experience. On behalf of our college/university, we express sincere
gratitude towards “Jindal Drilling and Industries Limited” for giving us an
opportunity to pursue our winter internship program in such a renowned
organization.
Next, we wish to express our gratitude to Mr. S.P. Thapliyal for providing
valuable information related to the project. We are indebted to all personnel in
Nagothane workshop who helped in our understanding and cleared all doubts
on different equipment.
We are also thankful to the entire HR team that facilitated our internship.
Also, we are grateful to Ms. Tanu Garg, Ms. Reila Chakraborty and all the
JDIL employees for helping us in learning about the business flow and
practicality of the activities that we gained during the course of internship.
Mr. Satish Jawanjal,
Mentor

INTRODUCTION
Future oilfield resource developments are subject to drill wells in cost efficient
manners. For that reason future management of oilfield drilling operations will
face new hurdles to reduce overall costs, increase performances and reduce
the probability of encountering problems. Drilling wells for energy search from
the ground has shown considerable technological advances in the recent
years. Different methods from different disciplines are being used nowadays in
drilling activities in order to obtain a safe, environmental friendly and cost
effective well construction. Communication and computer technologies are
among the most important disciplines, which can contribute to drilling
optimization.
From the very early beginning of the drilling campaigns the operators have
always been seeking to reduce the drilling costs mainly by increasing the
drilling speed. In the drilling industry, the first well drilled in a new field (a
wildcat well) generally will have the highest cost. With increasing familiarity to
the area optimized drilling could be implemented decreasing costs of each
subsequent well to be drilled until a point is reached at which there is no more
significant improvement [1]. The relationship among drilling parameters are
complex, the effort is to determine what combination of operating conditions
result in minimum cost drilling [2]. The generally accepted convention for a
proper planning of any drilling venture is to optimize operations and minimize
expenditures [3]. Another essential aspect of the optimization is to enhance
the technology and make the system effective [4]. Recently environmental
friendly activities have also started to be common practice in certain locations,
which in turn could be achieved by means of reducing the risks associated
with having technical problems.
In recent years the increasing emphasis that is being paid by the oil and gas
field operator companies towards working much efficiently at the rig sites are
based on some important reasons. The most important of all are: cost and
trouble free operations. During a peak in the cost of hydrocarbon resources,
the rig supplier and oil field service provider contractor charges are increasing,
pushing operators to work efficiently. Due to the complexity of the activities
being offshore and/or being in the form clusters operators restraining
themselves from causing a damage, which may result in destruction of more

than one well due to their proximity between each other being very close.
Directional techniques allowed drilling multiple wells from one location, thus
eliminating construction of expensive structures for each well [5]. Due to the
drilling requirements similarity of the wells located at close distances,
collecting past data, and utilizing in a useful manner is considered to have an
important impact on drilling cost reduction provided that optimum
parameters are always in effect.
Major drilling variables considered to have an effect on drilling rate of
penetration (ROP) are not fully comprehended and are complex to model [6].
For that very reason accurate mathematical model for rotary drilling
penetration rate process has not so far been achieved. There are many
proposed mathematical models, which attempted to combine known relations
of drilling parameters. The proposed models worked to optimize drilling
operation by means of selecting the best bit weight and rotary speed to achieve
the minimum cost. Considerable drilling cost reductions have been achieved
by means of using the available mathematical models.
DIRECTIONAL DRILLING
There are three basic well profiles which include the design of most directional
wells:
1. Type one: Build and hold trajectory. This is made up of a kick off point, one
build up section and a tangent section to target.
2. Type two: S -Shape trajectory. This is made up of a vertical section, kickoff
point, build-up section, tangent section, drop-off section and a hold section to
target.
3. Type three: Deep Kick off trajectory. This is made up of a vertical section, a
deep kick off and a build up to target.
Another secondary type is horizontal wells. A horizontal well is a well which
can have any one of the above profiles plus a horizontal section within the
reservoir. The horizontal section is usually drilled at 90 degrees.
The following are methods of Kick-off:
• Jetting deflection

• Whipstock deflection
• Motor deflection
• Rotary Steerable deflection
Jetting Deflection (Badger bit)
This is an old technique which is rarely used today. It relies on hydraulics to
deviate the wellbore and is therefore only effective in soft formations. A special
jet bit, is often used, but it is possible to use a normal soft formation bit, using
one very large nozzle and 2 small jet nozzles. The large jet nozzle is the
"toolface".The fluid coming out from the large nozzle causes the maximum
formation erosion and allows the well to be, effectively, deflected in the
direction of the jet coming out of the big nozzle. Jetting usually causes high
dogleg severities.
Whipstock Deflection
The whipstock is widely used as a deflecting medium for drilling multilateral
wells.It consists of a long inverted steel wedge (shute) which is concave on one
side to hold and guide a deflecting drilling or milling assembly. It is also
provided with a chisel point at the bottom to prevent the tool from turning,
and a heavy collar at the top to withdraw the tool from the hole, Figure 11.23.
Today, whipstocks are mainly used to mill casing windows for sidetracking
existing wells.
Motor Deflection
The motor is designed with an in-built bent housing below the motor section;
usually the connecting rod housing. The bent housing angle is usually 0.25-
1.5 degrees and is designed to tilt the axis of the bit relative to the axis of the
hole.The reader should note that having only a small bit offset will create a
considerable bit side force (deflecting force).
A steerable motor can be used in oriented mode (sliding) or rotary mode.In the
sliding mode, the drillstring remains stationary (rotary table or top-drive is
locked) while the drillbit is rotated by the motor. The course of the well is only
changed when drilling in sliding mode as the drillbit will now follow the
curvature of the motor bent housing. In rotary mode, the steerable motor
becomes "locked" with respect to trajectory and the hole direction and

inclination are maintained while drilling. The use of steerable motors with the
correct drillbit and BHA reduces the number of round trips required to
produce the desired inclination/azimuth.
Single shot surveys are not usually accurate in orienting steerable motors due
to the high reactive torque produced by the motor. For this reason, most
steerable motor assemblies are run with an MWD (measurement while drilling)
tool to provide real time survey and orientation data. A steerable motor with
an MWD tool is described as Steerable System.
Steerable motors are usually used to drill complete sections of a well, from
current casing shoe to next casing point.
Rotary Steerable System
These systems do not use bent subs for affecting hole angles. Changes in hole
angles are brought about by the action of three pads contained within a non-
rotating sleeve. The pads are kept in constant contact with the formation by
internal mud powered actuators. If no angle change is required, the system is
put in neutral mode by pushing the pads in every direction thereby cancelling
each other.
If changes in angle and direction are required, the electronics within the
instruments cause each pad to extend against the side the hole opposite the
intended bias direction. The resultant action of these forces then cause the bit
to build or drop angles as required. Signals can be sent from surface to the
instrument downhole as is the case with most current rotary steerable
systems or the hole inclination and direction are programmed into the
instrument at surface and the instrument then automatically corrects the hole
trajectory without driller’s intervention.
PARAMETERS FOR DRILLING OPTIMIZATION
The following are the parameters for drilling optimization:-
1. Weight on Bit
2. Revolution per minute.
3. Pump Parameters(GPM & SPM)
4. Mud Parameters
5. Rate of Penetration

Basic Definition:-
Weight on Bit:- is the amount of downward force exerted on the drill bit and is
normally measured in thousands of pounds.
Revolution per minute: - Revolutions per minute is a measure of
the frequency of rotation, specifically the number of rotation around a fixed
axis in one minute.
Pump parameters:- The pump parameters are composed of the liner size in
use, pump strokes, and the pump pressure. In case there are two pumps
working simultaneously all of the data for two of the pumps should be
acquired. With the electric pumps the stroke is transmitted in the same way
as RPM. The pressure at the pump in case of having been acquired could be
compared with the reliability of the standpipe pressure. Pump pressure should
always be greater than the standpipe pressure. Use of flow meters could also
be adapted for accurate flow rate measurements
Effect of Drilling Fluid Properties
The rate of penetration is also affected by the properties of drilling fluid used
during drilling. These properties include: rheological properties, filtration
characteristics, solids content and size distribution, and chemical
composition. The rate of penetration tends to decrease with increasing fluid
density, viscosity and solids content, and tends to increase with increasing
filtration rate. The density, solid content, and filtration characteristics of the
mud control the pressure differential across the zone of crushed rock beneath
the bit. The fluid viscosity controls the system frictional losses in the drill
string and thus the hydraulic energy available at the bit jets for cleaning. The
most important factor out of the drilling fluid properties is the density,
differential pressure tends to increase with increasing density, and the rate of
penetration decreases with increasing differential pressure.
Effect of Operating Conditions
Operating conditions such as the weight on the drill bit, the rotary speed have
significant effect on the rate of penetration. The rate of penetration has been
observed to increase rapidly with an increase in the weight on the drill bit. In
some cases, a decrease in rate of penetration is observed at extremely high
value of weight on the drill bit. This type of behaviour is often called bit
floundering. This poor response of ROP at high values of bit weight is usually
attributed to less efficient bottom hole cleaning at higher rates of cuttings.

The rate of penetration increases from point a to point d with an increase in
the weight on the drill bit, but a decrease in the rate of penetration is
suddenly observed from point d to point e with increase in the weight on the
drill bit.
The rate of penetration also increases with the rotary speed while other
drilling variables held constant. The rate of penetration usually increases
linearly with low rotary speed, but at higher values of rotary speed the rate of
penetration begins to decreases. The reason for decrease in the rate of
penetration is due to poor hole cleaning.
Mud Properties:-
Mud weight selection in a drilling program is a key factor in avoiding
various borehole problems. It is essential to select the correct mud
weight for drilling the individual sections. The following must be
considered when selecting mud weight:
1. A very low mud weight may result in collapse and well cleaning
problems.
2. A very high mud weight may also result in mud losses or pipe
sticking.
3. Excessive variation in mud weight may also lead to borehole
failure; as such a more constant mud weight must be aimed at.
The rate of penetration is also affected by the properties of drilling fluid
used during drilling. These properties include: rheological properties,
filtration characteristics, solids content and size distribution, and chemical
composition. The rate of penetration tends to decrease with increasing fluid
density, viscosity and solids content, and tends to increase with increasing
filtration rate. The density, solid content, and filtration characteristics of
the mud control the pressure differential across the zone of crushed rock
beneath the bit. The fluid viscosity controls the system frictional losses in
the drill string and thus the hydraulic energy available at the bit jets for
cleaning. The most important factor out of the drilling fluid properties is the
density, differential pressure tends to increase with increasing density, and
the rate of penetration decreases with increasing differential pressure.

Weight on bit (WOB)
Drilling bit breaks the rock by combination of processes including: a)
Compressive force (WOB) b) Shearing ( RPM) and sometimes c) Jetting action
of the drilling fluid. As it is very essential to give enough and optimised
amount of compression to the rocks for easy breaking of it. If there is increase
or decrease in this drilling parameter it can significantly affect the rate of
penetration (Drilling rate) and equipment used in drilling process. So a certain
minimum WOB is required to overcome the compressibility of the formation. It
has been found experimentally that once this threshold is exceeded,
penetration rate
increases linearly with
WOB. • WOB
represents amount of
weight applied onto the
bit, that is then
transferred to the
formation which in turn
is the energy created
together with string
speed that advances
drillstring. The weight
applied on the bit is the
difference between the
weight on the hook off
bottom and on bottom.
• It is measured
through the drilling
line, usually by means
of having attached a
strain-gauge which
measures the
magnitude of the
tension in the line itself, and gives the weight reading based on the
calibration. This sensor measures a unique value, which is the overall weight
(Hook-load) of the string including the weight of the block and Top Drive
System (TDS). For all of these circumstances correct calibration is required in
order to have proper reading for this drilling parameter.

• As it is very essential to give enough and optimised amount of
compression to the rocks for easy breaking of it. If there is increase or
decrease in this drilling parameter it can significantly affect the rate of
penetration (Drilling rate) and equipment used in drilling process. So a certain
minimum WOB is required to overcome the compressibility of the formation.
• It has been found experimentally that once this threshold is exceeded,
penetration rate increases linearly with WOB.
There are certain limitations which is applied to WOB as follows:
a) Hydraulic horsepower (HHP) at the bit
If the HHP at the bit is not sufficient to ensure good bit cleaning the ROP is
reduced either by bit balling or hole deviation. If this type of situation occurs
then there will not be any increase in ROP with increase in WOB unless
proper HHP is not applied to efficiently clean the hole.
HHP at bit can be given by this formula:
HHPb = Pb x Q
1714
Where Pb = pressure drop across the nozzle of the bit (psi)
Q = flow rate through the bit (gpm)
To increase HHP therefore requires an increase in Pb (smaller nozzles) or Q
(faster pump speed or larger liners). This may mean a radical change to other
drilling factors (e.g. annular velocity) which may not be beneficial. Hole
cleaning may be improved by using extended nozzles to bring the fluid stream
nearer to the bottom of the hole. Bit balling can be alleviated by using a fourth
nozzle at the centre of the bit.
b) Type of formation
WOB is often limited in soft formations, where excessive weight will only bury
the teeth into the rock and cause increased torque, with no increase in ROP.
c) Hole deviation
In some areas, WOB will produce bending in the drillstring, leading to a
crooked hole. The drillstring should be properly stabilized to prevent this
happening.

d) Bearing life
The greater the load on the bearings the shorter their operational life.
Optimizing ROP will depend on a compromise between WOB and bearing
wear.
e) Tooth life
In hard formations, with high compressive strength, excessive WOB will cause
the teeth to break. This will become evident when the bit is retrieved. Broken
teeth is, for example, a clear sign that a bit with shorter, more closely packed
teeth or inserts is required.
The effect of WOB on the drilling rate is shown in figure (a). It will be seen that
at lower WOB, drilling rate responds slightly to the increase in bit weight. This
is the bit load range when the compressive strength of the rock has not been
exceeded and whatever little penetration is achieved, it is due to the abrading
action of the bit teeth on the formation. Then at weight range above this
critical weight, the penetration rate increases rapidly as the weight on bit is
increased. Here, the compressive strength of the rock is exceeded and bit teeth
begin to chisel and fracture out large pieces of rock. Finally, the response of
penetration rate to increase in weight on bit becomes constant and a linear
relationship develops. This relationship is true for all types of formation
encountered in drilling. This relationship continues till complete burial of
teeth into formation.
Here, the instantaneous penetration rate can be expressed as:
Rp = a (W -M) + b
Where,
Rp = Instantaneous penetration of Rate (m/hr)
W = Weight on Bit (lbs)
a, b = slope and intercept respectively, which are dependent on rock
properties, bit size and type, drilling fluid properties etc.
M = Threshold weight (lbs)
Although, rate of penetration increases linearly with the weight on bit, the
increase in WOB adversely affects the bit life. The bit life may be governed
either by the life of teeth of the bit cones or by the life of the bearings of the
bit, whichever fails earlier.

The effect of weight on bit on the wear rate of the teeth is shown in figure (c). It
will be seen that as the weight on bit increases, the wear rate on the teeth
increases. The rate of wear of the teeth is excessive at large values of weight
on bit. As the weight increases, the wear rate increases until a point is
reached at which the bit teeth would be instantaneously destroyed.
The effect of weight on bit on the bearing life is shown in figure (d). It will be
seen that as the weight on bit is increased, the bearing life reduces. Therefore,
it is concluded that increase in weight on bit results in increase in drilling rate
and simultaneous reduction in bit life.
Therefore, it may not always be advisable to apply higher weight on bit for
higher penetration rate and that is how the concept of minimum cost of
drilling has been introduced. The effect of weight on bit on cost of drilling is
shown in figure (e). It will be seen that initially when the weight on bit is
increased, the cost of drilling falls until point A is reached after which the cost
of drilling starts increasing with the increase in weight on bit. Therefore, there
is an optimum value for weight on bit which will result in the minimum cost of
drilling.
Besides, we should not over-look the fact that application of any additional
weight on bit will call for increase in number of drill collars, thereby,
increasing the trip time and the pressure losses in the system.
Figure (a)

Figure (b) Figure (c)
Figure (d) Figure (e)
REVOLUTIONS PER MINUTE (RPM)
 What is RPM?
Revolutions per minute (abbreviated rpm, RPM, rev/min, r/min) are a
measure of the frequency of rotation, specifically the number of rotations
around a fixed axis in one minute. It is used as a measure of rotational
speed of a mechanical component.
 RPM in Drilling
It represents the rotational speed of the drill string. With the invention of
TDS; the reading is directly linked to the electronics of the unit itself. It is
considered that the measurements for this parameter are accurate as long as
the acquisition system set-up has been thoroughly made up.

 Relation with rate of penetration
Drilling rate increases as the rotary speed is increased. But the increase in
drilling rate is not linear as drilling rate increases as the rotary speed is
increased. But the increase in drilling rate is not linear as in the case of
weight on bit. The effect of rotary speed on drilling rate can be expressed in
general as
Rp = f(N)λ
Where,
f = some function
N = rotary speed, rpm
λ < 1
Therefore, it is observed that although the increase in rotary speed increases
the rate of penetration but at the same time it decreases the bit life. In order
to take its cumulative effect into consideration we must study the effect of
rotary speed on the cost of drilling.
This effect is shown in fig.f. It will be seen that in the lowest rpm range the
meterage cost on drilling decreases with increased rpm and after reaching a
certain value of RPM-cost starts increasing.
Therefore, there is an optimum value of RPM at which the cost of drilling will
be minimum. This optimum value is not very critical and decreases as the
weight on bit and formation hardness increase.
Figure a: Effect of Drilling Rate vs Rotary Speed (RPM)

Figure b: Effect of Drilling Rate vs Rotary Speed (RPM)
The graphical representation in Fig. a and b shows the nature of drilling rate
with increasing rotary speed, from which we can conclude that ROP increases
with increasing RPM, which further depends on the type of formation as well,
Figure c : Effect of Penetration / Revolution vs Rotary Speed (RPM)
The situation containing different values for WOB can be generated to create
the cumulative effect of RPM as well as WOB as shown in fig.c, it is being
observed that with increase in rotary speed causes decrease in penetration
where the slope of the extent of the decrease depends on WOB.
Figure d : Effect of Bearing Life (HRS) vs Rotary Speed (RPM)

Figure e: Effect of Wear Rate vs Rotary Speed (RPM)
It has been observed that higher rotary speeds results in wear and damage the
bearings, the life of different equipments decreases with increase in rotary
speed. So it is very essential to optimize maximum rotary speed with
minimum wear.
Figure f: Effect of Cost of drilling vs Rotary Speed (RPM)
Finally, the ultimate aim to this approach is to accomplish maximum work in
minimum time at the cheapest possible cost, so we derive a relation between
drilling cost and RPM, which is non-linear graph, as at extremely high ROP
tools get damaged, adding up the cost.
GPM
This is one of the most important factors in maintaining the drilling ROP of
the well. GPM, simply stands for Gallons Per Minute, is a unit for flow rate
measurement; and in this case the flow rate of the drilling fluid from the mud
pumps is registered in GPM. Thus whenever we come across the term GPM, it

directly refers to the pumping in flow rate of the drilling mud from the mud
pump/s (Duplex or Triplex).
GPM is a dynamic value depending upon the pump configuration and the
pump efficiency. Apart from these, frictional losses in the transmission pipes
are also a determining factor the eventual GPM of the system.
Importance :
 Hole cleaning (lifting drill cuttings): The primary GPM maintenance
depends on the hole size and depth at which the drilling is going on.
Larger and deeper wells will require a higher GPM so as to clean the
open hole section in minimum time so as to avoid any static filter cake
formation thus lowering the chances of held up and stuck ups due to
differential pressure inside the well bore against the wellbore wall.
Inadequate GPM ( lower than what is required) will result in thick mud
cake formation in deep wells and in larger hole sections resulting in
stuck ups. On the contrary very high GPM will result in high probability
of mud cut in tubulars. Thus efficient management is required in
deciding the GPM with respect to a particular well profile.
 Transferring hydraulic horsepower : This is another aspect in
determining the GPM. This aspect can be studied in two ways, i.e. in the
sliding and the rotary mode respectively.
Lets discuss about the sliding mode where in the hydraulic power is to
be transferred to the power section of the SDMM assembly implying the
dependence on the rotor stator configuration of the power section. GPM
depends upon the torque required to drive the given power section, i.e.
high torque requirement implies high GPM. In the power sections, high
torque is achieved by increasing the no. of stages and number of lobes of
the rotor. Thus, for such a configuration higher GPM is required. Vice
versa for low torque configuration of the mud motor.
In the rotary motion of the string, higher GPM implies, higher hydraulic
force transfer onto the formation surface aiding in chipping through the
formation producing substantially better ROP than in a lower GPM
configuration.

 Dependence on WOB- This aspect is directly related to the driving of the
power section through the transfer of hydraulic HP of the flowing drilling
mud. Whenever the WOB is increased in sliding mode, additional torque
requirement is there as a direct axial force acts upon the SDMM. To
overcome this barrier, GPM is increased so as to increase the differential
pressure across the power section which, in turn, increases the torque
delivered to the power section hence, stalling of the power section is
prevented.
 Well control:- as we know, the mud circulation at a drilling rig is a closed
loop system, thus principles of conservation of energy and mass are
applicable. Thus, we can safely say, in ideal conditions, the rate at which
mud enters the wellbore should be equal to the rate at which the mud
exits. Normal filtrate losses are prevalent universally hence, the rates are
not exactly similar but, approximately comply with each other. If the
filter losses are increased due to low pressure zones or caving in of
wellbore, a substantial difference between the two rates is observed.
Hence, the GPM is increased to keep the wellbore full of mud and well
control procedures are commenced.
CASE STUDY
Case study 1:
Well Name: X
Field Name: ABC
Well profile: Deviated ‘L’ Profile
Kickoff depth: 865m
Drift: 354±50m to be achieved at 1754m TVD.
Maximum Planned inclination- 28.07°.
CSD: 858m
Observing the drilling of Hole Size 12 ¼’’.

Key observations:
Depth: 858m
Further drilling calls for the usage of the modified BHA i.e. the inclusion of the
mud motor (8” SDMM) from the casing shoe.
Directional drilling commences from CSD till 1022m without any substantial
NPT.
In the following days, Mud pump failures occurred (pump took in air, piston
failures, Screen replacements.) and POOH had to be done. Initial POOH was
smooth but tight pull observed near the CSD which were cleared by
reciprocation easily.
Mud pump maintenance had to be carried out. Upon the commencement of
drilling, a good ROP was observed till 1056m. Further, fall in ROP was
observed even when the mud pumps were supplying the adequate amount of
SPM (=110 SPM) and the RPM was recorded 45 r/min.
RPM was increased to 65 r/min but no substantial increase in the ROP was
observed and finally WOB (initially at 6-7T) was increased along with the
increased RPM. (Final WOB was recorded to be 8-10T).
S/N
Depth in and
out
(m)
SP
Pressure
(psi)
SPM
Mud
Pump#
1
SPM
Mud
Pump
#2
Flow
Rate
(GPM)
ROP
(mts/hr)
WOB
(Ton)
RPM
Initial
l
1056-1148 1600 55 55 568 8.12 6-7 45
Trial
1
1148-1315 1800 55 55 590 10.23 6-7 65
Trial
2
1315-1456 1900 60 55 598 16.48 8-10 65
Depth (m) Formation
858 - 1056 Sandstone (Soft )
1056 - 1148 Shaly Sandstone
1148 - 1315 Shale
1315 - 1456 Shale

Inferences:
Formation change from the given depth of concern is implied. A harder
formation is being drilled than the previous. RPM wasn’t sufficiently enough to
increase the ROP.
Hence WOB, was a pivotal factor in increasing the ROP.
Further, in the same well,
Depth: 1456m
Activity: Drilling
Bit Change: from TCR(18x3) to PDC(17x7).
WOB: 8-10T
Observations:
No substantial increase in the ROP was there even the TCR bit was changed to
the PDC one. POOH was carried out and the bit was changed to TCR again
with a different configuration (20x3) and the mud pumps were not able to
pump in the required SPM.
The Replaced TCR bit was accompanied with a decrease in WOB (6-7T). The
required ROP was attained.
Inference:
Lower WOB is preferred for TCR bits for Bit Life Increment.
Case Study 2 :
Well Name: Y
Block Name: Z
Well Profile: Deviated ‘L’ Profile
Kickoff: 560m MD
Drift: 480m to be achieved at 2758.7m MD.
Maximum Planned inclination 26.04°

Planned direction: 232.46°
Key observations:
Depth: 2758.7m
To drill a directional well with kick off from 560m MD up to a depth of
2758.7m MD
Cement plug was placed for side tracking
To signify the effect of RPM, a situation is taken where a soft formation is
being encountered at the depth of 1353m MD
Changes in WOB and ROP are being made in order to optimize the situation
Motor configuration used (SDMM): 7/8
Time
Depth
(m)
Bit
type
Formation
SP
Pressure
(psi)
SPM
Mud
Pump
Flow
Rate
(GPM)
ROP
(m/h
r)
WOB
(Ton)
RPM
(r/mi
n)
Initial 0
PD
C
soft 850-950 95 450 9.6 5-6 45
Trial
1
1317
PD
C
soft
1400 -
1500
110 520 1.2 5-7 45
Trial
2
1353
PD
C
soft
1600 -
1700
120 545 2.8 5-7 70
Inferences:
In order to optimize the situation, the WOB is decreased from 8-9 ton to 5-7
tons as it is a soft formation
While the RPM is kept at 70, comparing the values of ROP as per the above
table, all the values are equal, with different values of RPM, which gives higher
ROP corresponding to higher values of RPM.

Case study 3:
Well Name: XYZ
Field Name: ABC
Well Profile: Deviated ‘L’ Profile
Kickoff depth: 865m
Drift: 354±50m to be achieved at 1754 TVD.
Maximum Planned inclination 28.07°.
CSD: 858m
KEY OBSERVATIONS
Observations at depth 1244m –
Drilling mode- Sliding and rotary
It was observed that the initial build up was smooth till the depth of 1244m.
POOH had to be carried out for bit change, during the same, tight pull was
observed at depths of 1176, 1116, 980 and 832m. The first three conditions
were released by reciprocation but, the last one had to be released by
circulation and rotation using Kelly, thereby increasing the NPT. It was
observed that the GPM transferred by the two mud pumps was 465 g/min,
which is much lower than the standard value of 580-650 g/min for a 121/4”
hole. It was due to the inefficiency of mud pump 1, whose SPM was maximum
40, and the cumulative SPM of both pumps was below 105 strokes/min.
INFERENCE
Due to inadequate GPM, improper hole cleaning became a menace, due to
which, 4 tight pulls occurred, with 1 requiring the use of Kelly
On further drilling in the same well, in the build up section, low ROP was
being registered. The WOB was subsequently increased from 6-7 tons (initial)
to 8-10 tons (final). The cumulative SPM of mud pumps was increased to 110
strokes/min and GPM was increased from 540 to 595 g/min. On further
drilling, in sliding mode, desired ROP was attained.

ANALYSIS OF WORKSHOP TENURE
i. Down hole Mud Motors
There are two major types of down hole motors powered by mud flow;
1) The turbine, which is basically a centrifugal or axial pump and
2) The positive displacement mud motor (PDM).
Turbines were in wide use a number of years ago and are seeing some
increased use lately but the PDM is the main workhorse for directional
drilling.
Four configurations of drilling motors provide the broad range of bit speeds
and torque outputs required satisfying a multitude of drilling applications.
These configurations include:
High Speed / Low Torque
The high speed drilling motor utilizes a 1:2 lobe power section to produce high
speeds and low torque outputs. They are mostly used when drilling with a
diamond bit and tri-cone bit drilling in soft formations.
Medium Speed / Medium Torque
The medium speed drilling motor typically utilizes a 4:5 lobe power section to
produce medium speeds and medium torque outputs. They are commonly
used in most conventional directional and horizontal wells, in diamond bit and
coring applications, as well as sidetracking.
Low Speed / High Torque
The low speed drilling motor typically utilizes a 7:8 lobe power section to
produce low speeds and high torque outputs. They are used in directional and
horizontal wells, medium to hard formation drilling, and PDC bit drilling
applications.
Components
All drilling motors consist of five major assemblies:
 Dump Sub Assembly
 Power Section
 Drive Assembly
 Adjustable Assembly
 Sealed or Mud Lubricated Bearing Section.

The gear reduced drilling motor contains an additional section, the gear
reducer assembly located within the sealed bearing section. Some other motor
manufacturers have bearing sections that are lubricated by the drilling fluid.
Dump Sub Assembly
As a result of the power section, the drilling motor will seal off the drill string
ID from the annulus. In order to prevent wet trips and pressure problems, a
dump sub assembly is utilized. The dump sub assembly is a hydraulically
actuated valve located at the top of the drilling motor that allows the drill
string to fill when running in hole, and drain when tripping out of hole. When
the pumps are engaged, the valve automatically closes and directs all drilling
fluid flow through the motor.
In the event that the dump sub assembly is not required, such as in
underbalanced drilling using nitrogen gas or air, its effect can be negated by
simply replacing the discharge plugs with blank plugs. This allows the motor
to be adjusted as necessary.
Power Section
The drilling motor power section converts hydraulic power from the drilling
fluid into mechanical power to drive the bit. The power section is comprised of
two components; the stator and the rotor. The stator consists of a steel tube
that contains a bonded elastomer insert with a lobed, helical pattern bore
through the centre. The rotor is a lobed, helical steel rod. When the rotor is
installed into the stator, the combination of the helical shapes and lobes form
sealed 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
the drilling motor is powered.
It is the pattern of the lobes and the length of the helix that dictate what
output characteristics will be developed by the power section. By the nature of
the design, the stator always has one more lobe than the rotor.
The second control on power section output characteristics is length. A stage
is defined as a full helical rotation of the lobed stator. Therefore, power
sections may be classified in stages. A four stage power section contains one
more full rotation to the stator elastomer, when compared to a three stage.
With more stages, the power section is capable of greater overall pressure
differential, which in turn provides more torque to the rotor.

As mentioned above, these two design characteristics can be used to control
the output characteristics of any size power section.
In addition, the variation of dimensions and materials will allow for specialized
drilling conditions. With increased temperatures, or certain drilling fluids, the
stator elastomer will expand and form a tighter seal onto the rotor and create
more of an interference fit, which may result in stator elastomer damage.
Special stator materials or interference fit can be requested for these
conditions.
Drive Assembly
Due to the design nature of the power section, there is an eccentric rotation of
the rotor inside of the stator. To compensate for this eccentric motion and
convert it to a purely concentric rotation drilling motors utilize a high strength
jointed drive assembly. The drive assembly consists of a drive shaft with a
sealed and lubricated drive joint located at each end. The drive joints are
designed to withstand the high torque values delivered by the power section
while creating minimal stress through the drive assembly components for
extended life and increased reliability. The drive assembly also provides a
point in the drive line that will compensate for the bend in the drilling motor
required for directional control.
Adjustable Assembly
Most drilling motors today are supplied with a surface adjustable assembly.
The adjustable assembly can be set from zero to three degrees in varying
increments in the field. This durable design results in wide range of potential
build rates used in directional, horizontal and re-entry wells. Also, to minimize
the wear to the adjustable components, wear pads are normally located
directly above and below the adjustable bend.
Sealed or Mud Lubricated Bearing Section
The bearing section contains the radial and thrust bearings and bushings.
They 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. The
bearing section may utilize sealed, oil filled, and pressure compensated or
mud lubricated assemblies. With a sealed assembly the bearings are not
subjected to drilling fluid and should provide extended, reliable operation with
minimal wear. As no drilling fluid is used to lubricate the drilling motor
bearings, all fluid can be directed to the bit for maximized hydraulic efficiency.
This provides for improved bottom-hole cleaning, resulting in increased

penetration rates and longer bit life. The mud lubricated designs typically use
tungsten carbide-coated sleeves to provide the radial support. Usually 4% to
10% of the drilling fluid is diverted pass this assembly to cool and lubricate
the shaft, radial and thrust bearings. The fluid then exits to the annulus
directly above the bit/drive sub.
Hydraulics
The use of a PDM in the drill string changes the hydraulic calculations and
should be considered. Various factors have to be taken into account. These
are:
1. Range of flow rates allowable: Each size and type of PDM is designed to
take a certain range of volumes of fluid.
2. No-load Pressure Loss: When mud is pumped through a mud motor which
is turning freely off-bottom (i.e. doing no work) a certain pressure loss is
needed to overcome the rotor/stator friction forces and cause the motor to
turn. This pressure loss and motor RPM are proportional to flow rate.
3. Pressure Drop across the Motor: As the bit touches bottom and effective
WOB is applied, pump pressure increases. This increase in pressure is
normally called the motor differential pressure. Motor torque increases in
direct proportion to the increase in differential pressure. This differential
pressure is required to pump a given volume of mud through the motor to
perform useful work. For a multi-lobe motor, it can be 500 psi or even more.
4. Stall-out Pressure: There is a maximum recommended value of motor
differential pressure. At this point, the optimum torque is produced by the
motor. If the effective WOB is increased beyond this point, pump pressure
increases further. This is known as stall-out condition.
Studies have shown that the power output curve is a parabola and not a
smooth upward curve, as originally thought. If the PDM is operated at 50%-
60% of the maximum allowable motor differential pressure, the same
performance should be achieved as when operating at 90% of differential. The
former situation is much better however there is a much larger ‘cushion’
available before stall-out.
5. Rotor Nozzle: Most multi-lobe motors have a hollow rotor. This can be
blanked off or jetted with a jet nozzle. When the standard performance range
for the motor matches the drilling requirements, a blanking plug is normally
fitted. The selection of the rotor nozzle is critical. Excessive bypass will lead to
a substantial drop in motor performance and, consequently, drilling efficiency.

If a rotor nozzle is used at lower flow rates, the power of the motor will be
greatly reduced.
DRILLING JAR
Basic Definition:
A mechanical device used down hole to deliver an impact load to another
down hole component, especially when that component is stuck. There are two
primary types, hydraulic and mechanical jars. While their respective designs
are quite different, their operation is similar. Energy is stored in the drill
string and suddenly released by the jar when it fires. The principle is similar
to that of a carpenter using a hammer. Kinetic energy is stored in the hammer
as it is swung, and suddenly released to the nail and board when the hammer
strikes the nail. Jars can be designed to strike up, down, or both. In the case
of jarring up above a stuck bottom hole assembly, the driller slowly pulls up
on the drill string but the BHA does not move. Since the top of the drill string
is moving up, this means that the drill string itself is stretching and storing
energy. When the jars reach their firing point, they suddenly allow one section
of the jar to move axially relative to a second, being pulled up rapidly in much
the same way that one end of a stretched spring moves when released. After a
few inches of movement, this moving section slams into a steel shoulder,
imparting an impact load. In addition to the mechanical and hydraulic
versions, jars are classified as drilling jars or fishing jars. The operation of the
two types is similar, and both deliver approximately the same impact blow,
but the drilling jar is built such that it can better withstand the rotary and
vibrational loading associated with drilling.

Bico Jars
Mechanical jars operate using a series of springs, lock and release
mechanisms. Hydraulic jars operate using the controlled passage of hydraulic
fluid. Hydro mechanical jars are a hybrid of designs, usually hydraulic up and
mechanical down.
The jars of three different sizes are being used by Jindal Drilling: 43/4 in,
61/2 in, 8 in.
Hydraulic Mechanical Jar Components:
1. Mandrel
2. Pressure Cylinder
3. Upper Flex Joint
4. Kelly Stabilizer
5. Kelly Mandrel
6. Drive Cylinder
7. Bottom Sub
8. Connector Sub
9. Lower Flex Joint
10. Knocker

MEASUREMENTS WHILE DRILLING(MWD)
As early as the 1960’s, companies were experimenting with ways to log
formations during drilling, but, technologically, it was difficult to build tools
that could withstand the harsh down hole environment and transmit reliable
data. A spinoff of the effort to overcome the problem was recognition that
inclination, direction, and tool face angle could be measured during drilling
and the data could be transmitted to the surface. This leads to the
development of MWD tools.
Various transmission methods were used- such as electromagnetic, acoustic,
pressure pulse, pressure-pulse modulation, or cable and drill pipe. Of all the
transmission methods, the pressure-pulse and pressure-pulse modulation
methods have evolved into commercial systems often used by the directional
drilling community.
The main benefits of MWD are-
(1) Borehole navigation.
(2) Drilling efficiency and safety.
(3) Geological information in real time.
BASIC MWD THEORY
Telemetry Systems
Commercial MWD Systems use Mud Pulse Telemetry to transmit survey data
during tool operation. In Mud Pulse Telemetry (Figure 4.14) the mud pressure
in the drill string is modulated to carry information in digital form. Pressure
pulses are converted to electric voltages by a transducer installed in the pump
discharge circuit (Figure 4.15). Then this information is decoded by the
surface equipment. Tool measurements are digitized downhole. The measured
values are transmitted to the surface as a series of zeros and ones. The
surface panels recognize these as representations of tool measurements

MWD Process Schematic MWD Pressure Transducer
There are three telemetry systems in common use today. Positive pulse
telemetry uses a flow restrictor which when activated increases stand pipe
pressure. Negative pulse tools have a diverter valve that vents a small amount
of mud flow to the annulus when energized. This decreases standpipe
pressure momentarily. Standing (or continuous) wave pulses, also known as
mud sirens, use rotating baffled plates which temporarily interrupt mud flow,
creating a pressure wave in the standpipe. Changes in relative rotation speed
of the plates changes the wave phasing. These phase changes are identified at
the surface and decoded.
Advantages
Positive Pulse Systems are commonly used in current MWD & LWD. This may
be because the generation of significant sized negative pulse requires pressure
drop across BHA, which reduces hole cleaning capacity of fluid.
 Simplicity over other methods.
 No special drill pipe is required.
 No complication due to wire line in the hole.
 Only minor alterations to normal drilling practices are necessary.
Disadvantages

 The pressure pulses travel through mud column at around 4000 -5000
ft/sec, but there is limit to the amount of information that can be sent in
real time.
 It does not work in compressible fluids.
MWD Telemetry
MWD Tool Features
 Efficient
 Economical
 Retrievable and Reinsert able
 Modular Design
 Short radius application
 Standard Non Magnetic Drill Collars (NMDC)
 Power Conversation
 Efficient Encoding/decoding
 Safe Area System
Components of MWD tool
 Dummy switch
 Electronic module
 Centralizer
 Battery
 Gamma ray tool
 Pulsar driver
 Stinger Assembly

Dummy Switch
It is the up hole end component of the MWD tool. It helps in lowering down
the tool and retrieving the tool when stuck up takes place. The MWD tool can
be retrieved with the help of an overshot assembly.
Dummy Switch
Electronic Module
Electronic Module
The electronic module is also known as direction and inclination module. The
Directional Sensor is made up of electronic printed circuit boards, a Tensor
Tri-Axial Magnetometer and a Tensor Tri-Axial Accelerometers, and
Temperature sensor. These modules are configured into a directional probe
and are run in the field mounted in a nonmagnetic drill collar. The
Directional Sensor provides measurements, which are used to determine the
orientation of the drill string at the location of the sensor assembly.
The Directional Sensor measures three orthogonal axis of magnetic bearing,
three orthogonal axes of inclination and instrument temperature. These
measurements are processed and transmitted by the pulser to the surface.

The surface computer then uses this data to calculate parameters such as
inclination, azimuth, high-side tool face, and magnetic tool face.
The sensor axes are not perfectly orthogonal and are not perfectly aligned,
therefore, compensation of the measured values for known misalignments are
required in order to provide perfectly orthogonal values. The exact electronic
sensitivity, scale factor and bias, for each sensor axis is uniquely a function of
the local sensor temperature. Therefore, the raw sensor outputs must be
adjusted for thermal effects on bias and scale factor. Orthogonal misalignment
angles are used with the thermally compensated bias and scale factors to
determine the compensated sensor values required for computation of precise
directional parameters.
Centralizer
Centralizer
It provides electrical conductivity between the electronics, battery and pulsar
driver. It helps in keeping the tool inside the Monel and also prevents
excessive lateral vibration. They are used in multiple MWD tool.
BATTERY
Battery

Lithium-thionyl chloride is commonly used. It provide stable voltage source
until the very near end of their service life, don’t require complex electronics to
condition supply. It is safer at lower temp., if heated above 1800C, can go a
violent, accelerated reaction, and explode with significant force. These
batteries are efficient over their service life, are not chargeable, and disposal is
subject to strict environmental regulations.
Gamma Tool
Gamma Tool
The gamma tool is optional i.e. it is used only if it is required. It consists of
Scintillation counter which is made up of thallium activated sodium iodide
crystal. The gamma rays are multiplied by photo multiplier. All of earth’s rock
formations exhibit varying degrees of radio activity. The gamma ray log is a
measurement of the natural radioactivity of the formations. Gamma rays are
emitted by radioactive elements such as isotopes of potassium, thorium and
uranium. These elements are found more commonly in shale than in other
rocks. Thus by measuring the gamma-ray emission from a sequence of rocks
it is therefore possible to identify the shale zones. To be most effective in
detecting changes of lithology, the gamma ray sensor should be positioned as
close to the bit as possible, so that only a few feet of new formation are drilled
before the tool responds.

Pulser Driver
Pulser driver
The pulser driver has a screen housing at the down hole end because of which
it can be identified in MWD. The pulser driver system uses DC motor which is
controlled by electronic module through the electrical pin connections present
in the various components of the MWD tool. The up hole end connection of the
pulsar driver system have 6 male pins connection while the down hole end is
connected to the stinger assembly.
Pulser driver system is divided into three major sections:
 Snubber assembly: It consists of the electric circuits.
 Oil field housing: It houses the DC motor and capacitor bank.
 Screen Housing: Consists of the bellow, servo shaft and servo poppet.
Stinger assembly
Stinger Assembly

SURFACE MWD SYSTEM (SAI)
It is the surface decoding system for mud pulse telemetry, a platform for us to
obtain subsurface information on-hand. It contains respective ports for
transducer, qBUS, qNIC, encoder etc as well as programming cable port.
It tells about current toolinclination, azimuth, gravity magnetic toolface,
gamma frequency, subsurface temperature, battery capacity etc
Surface readings obtained Main SAI tool

OUR PROPOSED SOLUTION:-
DUAL DRILL STRING (DDS)
In order to improve the cost efficiency of petroleum exploration and
production, it is required to develop improved technology. Hence, a completely
fresh drilling method has been developed, the prime new concept being the
use of a conventional drill string with a special inner string to form a
concentric dual drill string (DDS). It highly extends the capabilities beyond
conventional drilling. It allows the fluid and cuttings from the bottom of the
well to return to the surface through the inside of the drill string. It enables
improved hole cleaning, reduced possibility for washouts and improved
downhole pressure control. It has unique features for managed-pressure
drilling (MPD) and extended-reach drilling (ERD).
ARRANGEMENT SCHEMATICS
Figure gives a schematic description of the arrangement for the process. This
arrangement is based on conventional drilling; however, the following new
components are used:
• The Dual Drill String (DDS) facilitates a closed loop circulation of the drilling
fluid. The cuttings are transported to the surface by the drilling fluid through
the center pipe, leaving the wellbore annulus free of cuttings. The current size
used consists of 6⅝-in. drill pipe adapted with 3.5-in. inner pipe that has
been fitted with stab-in inner string connectors.
• The Top Drive Adapter (TDA) is a dual conduit swivel facilitating rotation of
drill string, accommodates discharge and return conduits and slip-ring for
power and data transmission.
• The Dual Float Valve (DFV) enables downhole pressure isolation of the well
and facilitates controlled pressure drilling and pressure less pipe connections.
• The Piston can be used to pump the BHA in the horizontal section of the
well. The Piston provides hydraulic WOB and gives the ability to push the ERD
limits.
The unit is equipped with pressure and flow sensors both on the drilling fluid
inlet and the return lines. A computer is used for annulus behind the piston.
• The Flow Control Unit (FCU) is a control valve arrangement for the active
drilling fluid to assure constant downhole pressure during drilling and pipe
connections. The unit is equipped with pressure and flow sensors both on the
drilling fluid inlet and the return lines. A computer is used for control and
monitoring of the status of the well. An annular Control Unit is used to keep a
constant pressure in the annulus behind the piston.

A main difference compared to conventional drilling is the circulation flow
path of the drilling fluid. For conventional drilling, the fluid returns through
the wellbore annulus, whereas in this case, the drilling fluid returns to surface
through the inner pipe of the DDS. It is based on pumping the drilling fluid
into DDS annulus via the TDA. The drilling fluid flows down DDS annulus to
the DFV. The DFV terminates the DDS at the top of a conventional Bottom
Hole Assembly (BHA). Drill cuttings are transported back to surface by the
drilling fluid in the well bore annulus outside the BHA up to the return
entrance ports in the DFV. From this point the cuttings are then transported
back to surface via the inner string, securing clean hole conditions at any
time. The DFV blocks both inflow and return flow when circulation is stopped.
This isolates the wellbore pressure, and allows for internal circulation
immediately above the DFV. DFV will open when the pressure above it
balances the wellbore pressure.
The sliding Piston provides hydraulic Weight On Bit (WOB), which is especially
advantageous for drilling long horizontal sections. The hydraulic force results
from pressurizing the fluid behind the piston in the annulus between the drill
string and the casing.

Flow from the surface
Flow from swivel
and top drive

Midflow mechanism
Bottomhole valve mechanism

Potential for Extended Reach Horizontal Wells/Directional Drilling
The DDS allows for drilling horizontal wells in a new way compared to
conventional drilling. The new arrangement can give significant improvements
on several of the challenges of long reach horizontal wells, such as:
1. Solve the hole cleaning challenge
An important factor when drilling long horizontal sections with conventional
drilling, is the hole cleaning. Since the cuttings tend to deposit in the low side
of the hole it is important to rotate the drill string to avoid cuttings
accumulations in the hole. For example, if the drilling fluid circulation is
stopped, it is possible that local cuttings bed avalanches in the curved section
of the well, which can result in high local cuttings accumulations that will
increase the risk for plugging of the hole and consequently lead to stuck pipe
situations.
The DDS solves the hole cleaning problem by cleaning the well from the
bottom. The cuttings are transported back to the surface through the inner
string, rather than through the annulus of the well. Thus there are no
cuttings in the annulus of the well, hence the chance for cuttings
accumulations that can lead to circulation stoppage and stuck pipe is
eliminated.
2. Solve the ECD challenge
When drilling long horizontal wells it is important to keep the well pressure
within a certain pressure window for hole stability reasons. This pressure
window may be quite small, maybe in the range of 10 bar. Conventional
drilling requires a pressure gradient in the horizontal section of the well, for
the annular fluid to flow back to the surface. The Equivalent Circulating
Density (ECD) is the additional friction pressure loss, i.e. the difference
between the annulus well pressure in the start and the end of the horizontal
section. The maximum horizontal reach for conventional drilling is in this case
achieved when this dynamic ECD component is equal to the allowed pressure
window, subject to minimum allowed flow rate and fluid rheology
requirements.
The DDS solves the above issue due to the elimination of the dynamic ECD
component. The dynamic ECD component represents the difference between
the annulus well pressure in the start and the end of the horizontal section.
For DDS, there is a short section between the drill bit and the DFV where the

fluid flows in the well annulus. However, this section is short and the pressure
gradient here is of little importance in a long horizontal section. In the well
annulus behind the DFV there is normally little or no flow, and thus the ECD
in this horizontal section is eliminated. Therefore RDM provides a drilling
solution, where the ECD as defined above is no longer a limiting factor for the
horizontal drilling reach.
3. Solve the WOB challenge
For drilling long reach horizontal wells it is often a challenge to provide
sufficient and stable Weight On Bit (WOB). This leads to poor rate of
penetration and time consuming operations. This problem is very significant
when trying to drill long horizontal sections in shallow reservoirs, because of
the short vertical section. This is solved by DDS by built in feature where one
can pressurize to the volume behind the Sliding Piston which will drive the bit
forward, independent of gravity. This allows to maintain hydraulic WOB in
very long horizontal sections. The available additional WOB force from the
Sliding Piston is dependent on the piston size and the differential pressure
across the piston.
4. Reduce drill string buckling problems
Buckling of the drill string occurs when the drill string is in compression, due
to the WOB and downhole frictional forces. This buckling leads to additional
friction and problems to transfer sufficient WOB force to the drill bit. For
conventional horizontal drilling, this buckling occurs along the whole well
path from the neutral point in the vertical section down to the drill bit. The
DDS arrangement reduces the buckling problems by the following:
- If the Sliding Piston is positioned in the horizontal section of the well, the
drill string in front of the Sliding Piston will be in compression and be prone to
buckling. However, the drill string along the whole well path behind the piston
can be held in tension. Thus the buckling and high friction forces especially in
the curved section of the well can be avoided.
- Conventional drilling relies on the use of limited or small drill string diameter
to avoid high ECD. DDS has the advantage of using a large diameter drill
string downhole without causing high ECD, since the return flow is contained
inside the drill string and not in the well annulus. As the buckling resistance
is strongly increasing with increasing drill string diameter, the use of a large
diameter drill string will also reduce buckling problems significantly.

5. Improve downhole conditions
When drilling long horizontal wells, the mechanical transfer of forces through
the drill string is subjected to high friction and dynamic loads. For long and
relatively small diameter drill strings this can result in downhole drill string
vibrations and stick-slip behavior on the drill bit. Such situations will cause
strongly reduced rate of penetration, and may lead to costly drill string failure.
RDM improves the downhole conditions to avoid the above mentioned
problems by using a larger than normal diameter drill pipe.
For example the rotational stiffness will typical be more than 3 times for a 6
5/8” drill pipe compared to a 5” drill pipe. The larger pipe will increase the
torsional stiffness thereby, reducing the onset of vibrations and stick-slip, and
avoid downhole fatigue problems.
The torque and drag are challenging aspects of drilling long horizontal wells.
Torque and drag is created from the friction between the drill string and the
wall of the wellbore along the well path. The torque and drag values are
typically dominated by the friction in the curved and horizontal section. The
presence of cuttings along the hole will increase this friction, and can cause
problems in the case of cuttings bed accumulations. Cuttings bed
accumulation can occur when drilling with high rate of penetration and by
settlements in critical zones, especially during stops in circulation. DDS
enables the drilling to be performed with no cuttings in the well annulus,
since the cuttings are transported back to the surface inside the drill string,
rather than in the well annulus. The additional torque and drag from the
cuttings can therefore be eliminated. Larger diameter pipe has also normally
improved torque rating compared to smaller diameter pipe.

REFERENCES
 Directional drilling training manual, Schlumberger (unpublished work)
 Baker Hughes training manual, 750-500-072 Rev. July 1998
 Applied drilling engineering, SPE, Richardson, TX, 1991.
 Drilling operations manual by IDT, ONGC
 Operating manual ofgriffit double acting hydraulic mechanical jars.
 www.bicodrilling.com – Bico corporate brochure.
 https://sites.google.com/site/directionaldrillingclub/downhole-mud-
motors
 SPE Paper-68088
 Kerr et.al. “New Approach to Improve the Horizontal Drilling Reach”,
SPE 138521, Calgary, Aug 2015.
 Egorenkov and Vestavik, “Deployment of DDS in a Shale Gas Field in
Canada”, SPE 148169, Aberdeen, Sept. 2015.
 Walker M. “Extended Reach Drilling-new solution with a unique
potential”, IADC/SPE 171046, San Diego, Mar. 2015.
 Tarek Ahmed, “Reservoir Engg. Handbook” Woburn, MA, 2001.
 Heriot Watt Petroleum Dept. “Heriot Watt University Drilling Engg.”
2001.

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