BIT HYDRAULICS ANALYSIS FOR EFFICIENT HOLE CLEANING

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TECHNOLOGY PARK MALAYSIA
ASSIGNMENT
BIT HYDRAULICS ANALYSIS FOR EFFICIENT HOLE CLEANING
(EE052-3.5-3-DH)
DRILLING HYDRAULIC
STUDENT NAME: MAHMOOD ABDULJABBAR
STUDENT NUMBER: TP040947
INTAKE: UC4F1903PE
PROGRAMME: PETROLEUM ENG
LECTURER NAME: MS NUR AILIE SOFYIANA SERASA
ASIA PACIFIC UNIVERSITY OF TECHNOLOGY & INNOVATION
FACULTY OF COMPUTING, ENGINEERING & TECHNOLOGY SCHOOL
OF ENGINEERING
22 November 2019

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Acknowledgment:
I would like to thank God as the Creator of the world for all his help during
the elaboration of this work and for keeping me alive and giving me the strength
in the presence of weakness. In performing this assignment, I had to take the help
and guidelines of some respected persons, who deserve my greatest gratitude, the
completion of this assignment gives me much pleasure. I would like to show my
deepest gratitude to Ms. Nur Ailie for giving me good guidelines for the
assignment throughout numerous consultations. Moreover, I would also like to
expand my gratitude to all those who have directly and indirectly guided me in
writing this assignment.

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Abstract
This project was helpful for the student to get knowledge in general about
the petroleum engineer and how to calculate the pressure loss of the system as
well as the section of the optimum nozzle for the drill bit this assignment will
helps allot the drilling engineer in future. Furthermore; this project helps to solve
the challenges that faced the petroleum engineer in real life. However, in this
project, the student learned how to deal with errors and converted to the advantage
and overcome with better results. From the given data the optimum mud flow
rates and the nozzle sizes should be designed for drilling at various depths until
the end of the section. The nozzle areas of hydraulics horsepower for surface
casing was 0.27 〖in〗^2, and for the intermediate casing are 0.23〖in〗^2 and
0,17〖in〗^2, and the last optimum nozzle area for the production which has been
calculated is 0.2〖in〗^2. Last but not less this assignment was helpful l for
student to get knowledge about the drilling hydraulics. Nozzle configuration
appears to have an effect on penetration rate. Several authors have described
improved drill rates with extended or blanked nozzle bits. However, presently
used criteria have been unable to account for these improved drill rates. in fact,
has suggested a different optimum may exist for each nozzle size. Drill cuttings
in the well bore cause wear and tear to the drill string and this reduces the rate of
penetration; therefore, there is need for efficient bottom hole cleaning. During
drilling operation, optimization of hydraulic horsepower at the drill bit is adopted
to enhance bottom hole cleaning and to increase the rate of penetration. Optimum
drilling conditions are achieved using either the maximum horsepower criterion
or the hydraulic jet impact force criterion.

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TITLE PAGE NO.
ACKNOWLEDGMENT ii
ABSTRACT iii
TABLE OF CONTENTS iv
LIST OF FIGURES vi
LIST OF TABLES vii
Table of Contents
CHAPTER 1........................................................................................................................... 1
INTRODUCTION.................................................................................................................... 1
Research Problem................................................................................................................ 3
Aim and Objectives .............................................................................................................. 3
Justification for this research................................................................................................ 4
Organization of the rest of the chapters............................................................................... 4
Summary ............................................................................................................................. 5
CHAPTER 2........................................................................................................................... 6
Introduction......................................................................................................................... 6
Literature Review................................................................................................................. 6
Mud Hydraulics Optimization............................................................................................... 6
Effects on Drilling Efficiency and Rate of Penetration ........................................................... 7
Bit Hydraulics....................................................................................................................... 7
CHAPTER 3......................................................................................................................... 10
Justifiable assumptions and limitations of selected parameters.......................................... 10
Basic Planning—Hydraulic Design....................................................................................... 13
Mud Hydraulics Optimization............................................................................................. 13
limitations of selected parameters..................................................................................... 14
Design constraints of bit hydraulics data ............................................................................ 16
Project description............................................................................................................. 16
Drilling rig location............................................................................................................. 16
Well types, location and trajectories .................................................................................. 17
Well trajectory design........................................................................................................ 18

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Elevation depth (Above the sea level) ................................................................................ 18
Well architecture and casing design ................................................................................... 22
Casing material selection.................................................................................................... 35
Efficiency and flow characteristics of drilling fluid which includes drilling rate and pump
operation........................................................................................................................... 38
Description of the Process.................................................................................................. 38
Correct interpretation of bit hydraulics data ...................................................................... 42
Pressure loss...................................................................................................................... 42
Optimum Nozzle Size ......................................................................................................... 44
Adhere to IADC bit classification......................................................................................... 52
Drill bit cost (10 marks) ...................................................................................................... 54
Drilling fluid cost ................................................................................................................ 54
Suitability of the proposed innovative solutions with suggested improvements, where
necessary........................................................................................................................... 55
CHAPTER 13....................................................................................................................... 56
Discussion.......................................................................................................................... 56
Conclusion ......................................................................................................................... 57
Limitations......................................................................................................................... 58
References......................................................................................................................... 59

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List of Figures
Figure 1Real-Time Drilling Analytics...........................................................................2
Figure 2Borehole configuration at the total depth..........................................................9
Figure 3Top Structure Map......................................................................................... 11
Figure 4Porosity Distribution Map.............................................................................. 11
Figure 5Horizontal Permeability Distribution Map...................................................... 12
Figure 6Vertical Permeability Distribution Map.......................................................... 12
Figure 7Water Saturation Distribution Map ................................................................ 12
Figure 8Hydraulic horsepower versus flow rate profile in the circulating system. .......13
Figure 9Jet impact force versus flow rate profile in the circulating system. ................. 14
Figure 10ECD at 11,500 (ft) versus flow rate profile in the circulating system. ...........14
Figure 11Wells location in X field in term of primary scenario for vertical and deviated
wells........................................................................................................................... 17
Figure 12Wells direction for X field for vertical and deviated wells............................ 20
Figure 132D design for the trajectory of directional well.............................................21
Figure 142D design for the trajectory of vertical well ................................................. 21
Figure 15Pressure Profiles Versus Depth ....................................................................23
Figure 16Casing and bit size selection ........................................................................24
Figure 17Show the burst and collapse for the conductor casing...................................28
Figure 18Show the burst and collapse for the surface casing .......................................30
Figure 19Show the burst and collapse for the intermediate 1 casing ............................ 32
Figure 20Show the burst and collapse for the intermediate 2 casing ............................ 34
Figure 21Show the burst and collapse for the production casing..................................35
Figure 22Drilling data.................................................................................................38
Figure 23Pump pressure versus mud flow rate. ........................................................... 41
Figure 24IADC Classification for Roller Cone Bits .................................................... 53

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List of Tables
Table 1Petrophysical Properties of Exploration Wells................................................. 10
Table 2PVT Data........................................................................................................10
Table 3Composition of Reservoir Fluid ......................................................................10
Table 4Show the limited depth and daily average rate for offshore drilling rigs...........16
Table 5Location of the wells target in term of primary scenario ..................................18
Table 6Summary result of the drilling parameters for vertical and directional wells ....21
Table 7Pressure data versus depth for X reservoir....................................................... 22
Table 8bellow show the selected casing size, bit size and mud weight versus depth ....25
Table 9Casing section size with other properties......................................................... 26
Table 10Summary result for burst pressure at the conductor casing............................. 27
Table 11Summary result for collapse pressure at the conductor casing........................ 27
Table 12Summary result for burst pressure at the surface casing.................................29
Table 13Summary result for collapse pressure at the surface casing ............................ 29
Table 14Summary result for burst pressure at the Intermediate 1 casing...................... 31
Table 15Summary result for collapse pressure at the Intermediate 1 casing................. 31
Table 16Summary result for burst pressure at the Intermediate 2 casing...................... 33
Table 17Summary result for collapse pressure at the Intermediate 2 casing................. 33
Table 18Summary result for burst pressure at the production casing ........................... 35
Table 19Summary result for collapse pressure at the production casing....................... 35
Table 20Show the selection of the casing grade based on the burst and collapse .........36
Table 21Show the selected drilling bit with the number of drilling bit required...........36
Table 22Assemble Required Bit Hydraulics Data....................................................... 39
Table 23Finding data ..................................................................................................40
Table 24From the above drilling data, we can get the following..................................40
Table 25selecting flow rate......................................................................................... 41
Table 26Selecting yield point...................................................................................... 41
Table 27Combination for pressure loss in in drill pipe ................................................ 41
Table 28Show the selected drilling bit with the number of drilling bit required...........52
Table 29Drilling bit cost ............................................................................................. 54
Table 30Cost of drilling mud ...................................................................................... 54

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CHAPTER 1
PROJECT SCOPE STATEMENT
1.1 NTRODUCTION
The ability of the drilling fluid to effectively transport cuttings from the
bottom of the hole depends upon the hydraulics of the system and the properties
of the drilling fluid. As bottom hole cleaning is the major factor causing the
decrease in drilling rate with depth, the proper use of hydraulic practices can
eliminate such a drilling problem. Figure 1 gives a clear view of the concept of
the hydraulic principle.
The essence of a good hydraulic system is to provide adequate
impingement to hydraulic power at the formation. As soon as the bit teeth crater
and fracture the rock, the bit nozzle will provide jet force to transport the debris
of cuttings to the surface. Insufficient hydraulic power will lead to regrinding the
cuttings in the bottom hole instead of transporting them to the surface. This hole
cleaning deficiency can cause accumulation of cuttings in the bottom hole and
consequently impede the rate of penetration.
Drilling hydraulics is associated with the related effect of drilling fluid
viscosity and flow rate, drill pipe rotational speed, and system pressure losses. Bit
hydraulics is related to the effects of nozzle sizes, number of nozzles, the jet
velocity of drilling fluid passing through the bit nozzle, and the pressure loss
across the bit.
Optimized hydraulics reduces the overall drilling cost. Two criteria that
are commonly used to analyze bit hydraulics for hole cleaning are the Hydraulics
Horsepower (HHP) and Jet Impact Force (JIF). However, today there is still no
agreement on which one of these criteria provides a better analysis for hole
cleaning (Lim, 1996).
Engineered to help you predict ahead of the bit, our Real-Time Drilling
Analytics suite enables you to continuously optimize your operations by defining
invisible lost time while reducing non-productive time. This forward-thinking

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suite of products allows you to apply continuous improvement cycles in real-time
to address a wide variety of drilling challenges (PetroLogging, 2019).
Optimization occurs when the total available system energy is
proportioned to maximize available hydraulic energy at the bit. Theoretical
relationships that maximize bit hydraulic horsepower, impact force, and jet
velocity were first published by Kendall and Goins. They stressed the need to
consider “all necessary restrictions on operating conditions”, provided
procedures for maximizing the different criteria, and presented a graphical
method for determining flow rates and sizing nozzles (PetroLogging, 2019).
Figure 1Real-Time Drilling Analytics
(PetroLogging, 2019).
During drilling operation, optimization of hydraulic horsepower at the
drill bit is required to increase the Rate of Penetration (ROP). Drill cuttings in the
wellbore may causes stuck pipe, and increases the mechanical torque and drag
especially in deviated wells which requires unnecessary backreading. Therefore,
there is a need to enhance bottom hole cleaning efficiency to ensure adequate
cuttings evacuation from bit.

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1.2 Research Problem
Inadequate hole cleaning can lead to a number of problems, including
hole fill, packing off, stuck pipe, and excessive hydrostatic pressure. Drill
cuttings in the hole cause wear and tear of the drill string and also reduce the
rate of penetration, thereby increasing the cost and time for drilling; hence,
there is need to design a system that will efficiently remove the drill cuttings,
transport them to the surface in a cost effective manner, prepare an appropriate
drilling mud and maximize the hydraulic horse power at the drill bit.
During the course of this project work, some of the limitations of this
project work were as
follows:
1. The use of conductivity data to estimate the abnormal pressure zone in this
study has some degree of inaccuracy since conductivity is affected by salinity.
However, seismic data is more accurate for detecting and quantifying abnormal
pressure.
2. The Hottman and Johnson approach were used to estimate the pore pressure,
which has some degree of inaccuracy since the approach does not account for
the effect of overburden stress.
3. The Hubbert and Willis approach were used to estimate the fracture pressure,
which has some degree of inaccuracy, since the approach assumes a poison’s
ratio of 0.25 and an over burden pressure gradient of 1psia/ft.
4. In this study, factors such as drill pipe eccentricity, drill pipe rotation and the
weight on the drill bit that affect the rate of penetration were not accounted for,
this study focused on the mud rheology and hydraulics.
5. Due to unavailability of mud pump data, a theoretical flow exponent of 1.75
was used for the hydraulic design (Kendall and Goin, 1960), since the flow
exponent can only be obtained by operating the mud pump on a drilling rig.
1.3 Aim and Objectives
The objective of this study aims at designing a hydraulic system to specify
the operating conditions to operate the mud pump for drill cutting removal and to
enhance the rate of penetration during drilling.
The effect of mud rheology on the pressure losses in a mud circulatory
system will also be considered in this study.

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obtained the optimum nozzle size to drill the wells, for the production
casing, intermediate and the surface casing if needed
1.4 Justification for this research
This research provides easy to follow steps to help you define, analyze,
understand and solve the problems which may happen during the drilling stages.
The ethics of professionals are different from the ethics of the community
at large Conduct which would be unethical by community standards is ethical
within the context of a profession. This article examines the ways in which a
different professional ethic can be justified and, by reference to a contemporary
play, considers the consequences of such justifications.
1.5 Organization of the rest of the chapters
In this assignment will analyze the Bit Hydraulics Analysis for Efficient
Hole Cleaning, based on the drill bit size, mud type used, and the nozzle sizes to
allow the drill bit to clean the hole.
Chapter 2 briefly reviews the work is done by other researches based on
the scenarios, in this chapter will see the other researches of the drilling engineer
and specially for the pressure loss and some of the factor which may affect while
drilling the well
Chapter 3 show the calculation and analysis of this assignment, this is the
most important section in this assignment, first of all it shows the casing deign
and how we select the bit size and mud weight of this reservoir. Moreover, in this
section has been found the parameters which need to be used in this assignment,
and also has been set the casing types and explain the classification of the bit type
which will be used. Furthermore, will be calculation the pressure loss and the
optimum nozzle.
Chapter 4 briefly summaries all the works of this assignment. Moreover;
it will summaries the literature review and what has been explained in this chapter,
also will be conclude this chapter and do some recommendation to improve this
process.

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1.6 Summary
In this chapter, it explained and discussed several parts to give a clear
idea of this assignment and how this assignment can help the industry in the
future, also it explains what the process of the next chapter and what to do on
it. First of all; it has been writing an introduction to Bit Hydraulics Analysis
for Efficient Hole Cleaning
The introduction was explained with general information and discussed
out to the specifications of the assignment. Furthermore; has been mention
about the main objective of this assignment. In addition, the development of
this assignment was justified as well.

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CHAPTER 2
LITERATURE REVIEW
2.1 Introduction
Drill cuttings in the well bore cause wear and tear to the drill string and
this reduces the rate of penetration; therefore, there is need for efficient bottom
hole cleaning. During drilling operation, optimization of hydraulic horsepower at
the drill bit is adopted to enhance bottom hole cleaning and to increase the rate of
penetration. Optimum drilling conditions are achieved using either the maximum
horsepower criterion or the hydraulic jet impact force criterion.
This project work focused on the application of optimization using the
maximum horsepower criterion in an over pressure zone for bottom hole cleaning
and for showing the effect of mud rheology on pressure losses in a mud circulatory
system. In this work, optimum conditions for drilling were determined by
estimating pore pressure and fracture pressure from conductivity data, selecting a
suitable mud with an appropriate density based on the result of the conductivity
data analysis, studying the rheological properties of mud samples, calculating the
pressure losses in the mud circulatory system and finally applying the maximum
horsepower criterion for optimization.
2.2 Literature Review
2.2.1 Mud Hydraulics Optimization
Bit Hydraulics
Regarding the question of which criterion is the best for optimizing bit
hydraulics, most people use the maximum bit hydraulic horsepower or the
maximum bit hydraulic impact force criterion at shallow to middle depths and
then shift to the maximum nozzle velocity at deeper depths. Between the
maximum bit hydraulic horsepower and the maximum bit hydraulic impact force
criteria, neither criterion has been proved better in all cases because there is little

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difference in the application of the two procedures. If the jet impact force is a
maximum, the hydraulic horsepower will be within 90% of the maximum and
vice versa. Another argument is that in many cases bits provide higher than
required hydraulics, so the effects of design using different criteria are masked.
The concept of bit hydraulic horsepower was introduced as a design
criterion in the early 1950s. It is a measure of the work required to squeeze mud
through the bit nozzles. This work is related to the removal of cuttings from below
the bit. Bit hydraulic horsepower is the most common design procedure, probably
because it was used first.
2.2.2 Effects on Drilling Efficiency and Rate of Penetration
Combining of all factors affecting rates of penetration (ROPs) into a single
closed-form set of equations to enable economic optimization has long been a
goal of drilling visionaries. While individual pieces of the puzzle have been
satisfactorily solved (bit hydraulics for example), the combined effect on all
factors on the overall economics remains elusive and an area rich for more
research and engineering.
Though hydraulics is an important part of improving ROP and should
where possible be optimized, there are cases where pump horsepower is limited
and other uses for the hydraulic energy are more advantageous. This could be in
cases where a mud motor consumes most of what hydraulic energy is available
with little left over for bit nozzles. Even in those cases the available energy should
be utilized. Optimization, including a reiterative optimization of flow rates, mud
motor parameters, and bit nozzles remains a productive endeavor.
2.2.3 Bit Hydraulics
Introduction and Importance of Bit Hydraulics Optimization
The proper design of bit hydraulics is one of the potentially most beneficial
aspects of drilling wellbore hydraulics. When properly utilized, it can result in
improved rate of penetration (ROP), due to improved removal of newly formed
cuttings from beneath the bit, eliminating the need to “drill the hole twice” before
new cuttings are removed; decreased ECD, due to optimization typically resulting
in lower flow rates compared to nonoptimized conditions; reduce the risk of stuck
pipe from cuttings accumulating on the low side of the hole; decreased wear and
tear on pressure generating machinery, due to a more efficient use of available

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hydraulic energy, and hence less wasted energy or pressure; and reduced diesel or
other fuel usage and hence less associated pollution and greenhouse gas
emissions.
Optimized bit hydraulics is one of the rare technologies that offer a true
“win” for both the drilling contractor and the operator. To the operator, optimized
bit hydraulics presents the opportunity to drill faster and hence incur less cost in
drilling a particular wellbore or series of wells. This translates into an improved
drilling efficiency in an economic sense.
2.2.4 Hole Cleaning
With the advent of modern synthetic muds and advanced performance
water-based mud systems, one of the nemesis of drillers, stuck pipe, has been on
the decline. At the same time, the use of directional wellbores, and the lengths and
complexities of wellbores, has increased. In addition, penetration rates of the drill
bit have improved dramatically over the past 10 years or so.
As a result, one of the more troublesome challenges facing modern drillers
is how to efficiently clean the hole of the drill cuttings in order to minimize or
eliminate trouble costs associated with the inability to do so.
Hole cleaning is a two-part process of removing drilling cuttings from the
hole. The first part involves moving cuttings from the very bottom of the well
(beneath the bit), and the second part is to get those cuttings up the annulus and
to the surface.
2.2.5 Rate of Penetration
The chapter after those two ties the wellbore hydraulics, bit hydraulics,
and hole cleaning together in the interest of drilling faster, near and dear to all
drillers’ hearts.
After these cardinal chapters, the remaining chapters in the book address
tightly related subjects in sufficient details with suitable equations to permit
modeling of pressure losses.
The overall approach is that some pressure losses are required by the
drilling operation and cannot nor should not be minimized. Mud motor losses
come to mind as these (and the associated torque and rpm they impart to the bit)
can be extremely important to drilling rate. However, if the rig pumping capability
is sufficient, any extra pressure that is available should be spent across the bit

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nozzles, rather than being wasted as friction loss in pumping drilling fluid through
the drill string and up the annulus.
2.2.6 Mud Pumps
The selected mud pump should also be capable of providing pressure that
is strong enough to overcome the total pressure loss and pressure drop at the bit
in the circulating system at the total hole depth. The pressure loss depends on the
mud properties, the drill string configuration, the borehole geometry, and the mud
flow rate. The pressure drop at the bit should be optimized based on the total
pressure loss in the system to maximize bit hydraulics. Therefore, extreme
borehole architecture and condition should be considered.
Extreme Borehole Configurations
Maximum pressure loss normally occurs when the total hole depth is
reached. At this point, the drill string and the open hole section assume their
longest values. The borehole configuration is shown in Figure 2. To perform
pressure loss calculations, it is convenient to put the dimension (lengths and
diameters) data along the circulating path in the graph.
Figure 2Borehole configuration at the total depth.

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CHAPTER 3
CALCULATION AND ANALYSIS
3.1 Justifiable assumptions and limitations of selected parameters
Table 1Petrophysical Properties of Exploration Wells
Properties Well 2 Well 3 Well 4 Well 5
Thickness (ft.) 135 130 250 176
Type of Fluid Oil Oil Oil Oil
Vshale (%) 41 26.5 45 36
Porosity (%) 25 30.3 23.2 28
Table 2PVT Data
Parameter Value
API Gravity 40
GOR (scf/stb) 528
Saturation Pressure (psia) 1813
Reservoir Pressure (psia) 5189
Reservoir Temperature (°F) 250
Bubble Point Pressure (psia) 1785
Viscosity (cP) 0.37
Density (g/cc) 0.68
Table 3Composition of Reservoir Fluid
Component Mol %
N2 0.8
CO2 0.66
C1 23.4
C2 8.32
C3 8.61
iC4 1.21

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nC4 5.00
iC5 1.62
nC5 3.06
C6 3.58
C7 5.66
C8 5.55
C9 4.33
C10+ 28.32
Figure 3Top Structure Map
Figure 4Porosity Distribution Map

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Figure 5Horizontal Permeability Distribution Map
Figure 6Vertical Permeability Distribution Map
Figure 7Water Saturation Distribution Map

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3.1.1 Basic Planning—Hydraulic Design
Hydraulic design is another critical design factor. The flow rates must be
high enough to clean the hole, but not so high that circulating pressures in the tight
annular space exceed the open hole fracture gradient. This is basic equivalent
circulating density (ECD) management. In general, the flow rate should allow for
an annular velocity of 175 ft per minute (fpm) as long as the fracture gradient is
not exceeded. The rate of penetration might have to be limited if an adequate flow
rate to clean the hole cannot be achieved without generating an equivalent
circulating density greater than the fracture gradient. If the flow rate is too low
the hole could easily pack off and the entire string could become stuck.
3.1.2 Mud Hydraulics Optimization
The calculated effects of the mud flow rate on other parameters these
parameters include hydraulic horsepower, jet impact force, ECD, pump pressure,
and pressure components. The calculated hydraulic horsepower profile is
illustrated in Figure 8. It shows that the bit hydraulic horsepower will reach 50%
of pump horsepower at a mud flow rate of about 500 gpm.
Figure 8Hydraulic horsepower versus flow rate profile in the circulating system.
The calculated jet impact force profile is presented in Figure 9, which
indicates that the impact force will be maximal at a mud flow rate of about 570
gpm. The calculated equivalent circulating density profile is illustrated in Figure
10. It shows that the ECD profile is between the pore pressure gradient, 9.2 ppg,
and the fracture pressure gradient, 10.65 ppg, if the mud flow rate is less than 560

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gpm—that is, neither kick nor loss of circulation is expected at mud flow rate
values lower than 560 gpm.
Figure 9Jet impact force versus flow rate profile in the circulating system.
Figure 10ECD at 11,500 (ft) versus flow rate profile in the circulating system.
3.1.3 limitations of selected parameters
1. The use of conductivity data to estimate the abnormal pressure zone in this
study has some degree of inaccuracy since conductivity is affected by salinity.
However, seismic data is more accurate for detecting and quantifying
abnormal pressure.
2. In this study, factors such as drill pipe eccentricity, drill pipe rotation and the
weight on the drill bit that affect the rate of penetration were not accounted
for, this study focused on the mud rheology and hydraulics.
3. Due to the unavailability of mud pump data, a theoretical flow exponent of
1.75 was used for the hydraulic design (Kendall and Goin, 1960), since the

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flow exponent can only be obtained by operating the mud pump on a drilling
rig.
4. The deposition of evaporites can create high abnormal pore pressures in the
surrounding zones with the pore pressure approaching the overburden
gradient. When salt is deposited, the pore fluids in the underlying formations
cannot escape and therefore become trapped and abnormally pressured
(Rabia, 2002).
5. The fracture pressure is dependent on the formation type, overburden pressure
and on how the formation is compacted. If abnormal formation pressure is
encountered, the density of the drilling fluid must be increased to maintain the
wellbore pressure above the formation pore pressure to prevent the flow of
fluids from permeable formations into the well. However, since the wellbore
pressure must be maintained below the pressure that will cause a fracture in
the well bore. Hence, there is a maximum drilling fluid density that can be
tolerated in the well bore to maintain well bore stability. This means that there
is a maximum depth into the abnormally pressured zone to which the well can
be drilled safely without cementing another casing string in the well. Thus,
the knowledge of the pressure at which formation fracture will occur at all
depths in the well is essential for well planning and in drilling an oil well.
6. 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 (Prassl, 2003):
• A very low mud weight may result in collapse and well cleaning problems.
• A very high mud weight may also result in mud losses or pipe sticking.
• Excessive variation in mud weight may also lead to borehole failure; as
such a more constant mud weight must be aimed at.
• A median line concept is recommended generally for mud weight
planning. The mid-point is between the pore pressure and fracture
pressure. Hence keeping the mud weight within this median level causes
least disturbance on the borehole wall.

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3.2 Design constraints of bit hydraulics data
3.2.1 Project description
This reservoir is offshore Sandston oil reservoir which is about 2800 ft
thick that starts from 8,600 ft to 11400 ft and consider as a shallow reservoir in
which the sea level about 200 ft. The sea level together with the top reservoir
depth is equal to 8800 ft and the oil-water contact located at depth 11,250 ft.
Based on the geologist and reservoir engineer investigated, it found that reservoir
is economically to be produced due to the years of the sharing contract.
3.2.2 Drilling rig location
Based on the contour map of the reservoir, one drilling rigs will be used
to do the drilling process. Drilling rig coordinate selected to be 4500 ft in the x-
direction and 6200 ft in Y-direction. The drilling rigs position will provide for
build and hold type and vertical drilling and will provide the drilling trajectory to
all the drainage points.
The drilling rig will be selected based on the location of the reservoir and
the surrounding environment such as, whether the reservoir is located on land or
in the ocean. Additionally, the weather conditions in the surrounding area of the
reservoir whether calm or stormy. Due to the X reservoir, which is located in the
offshore, several factors will be taken into account for the selection of the drilling
rig which includes depth of the sea level, rig capacity, cost of the drilling rig and
its stability on the seawater. Figure 11 below shows some specifications of
available marine offshore drilling rigs.
Table 4Show the limited depth and daily average rate for offshore drilling rigs

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The sea level of the X field is about 200 ft above the seabed and according
to this depth, only three offshore drilling rigs are suitable to be used which are
jacket rig, jack-up rig and semi-submersible rig. The semi-submersible rig will be
excluded from the selection due to its high cost comparing to jacket rig and jack-
up rig. The jack-up rig is a common drilling rig used in offshore fields due to its
low cost compared to other drilling rigs. Besides, Jack-up Rig characterizes by its
stability on offshore reservoirs because it can rise above the sea level and therefore
sea waves do not affect its movement. Additionally, Jack-up rig is easy to move
from one location to another and thus speeds up the drilling process. Due to the
many features of the Jack - up rig, it has been selected to drill wells in the X field.
3.2.3 Well types, location and trajectories
Optimal selection of the type of wells contributes significantly to
successful the drilling process. To define the type of wells, the shape of the
reservoir and location of the targets for each well should be taken into account.
Based on the shape of the X reservoir as clearly show in the contour map, vertical
and deviated wells type (J) build and hold are the suitable types to hit the target
in this reservoir. The build and hold wells are proposed to tap the drainage points
where the kick-off point will be below the surface casing for all the deviated wells.
One build-up rate will design for the dogleg severity of the build-up section will
be used which are short build-up rate. This section shows the coordinate of the
wells that has been selected based on the contour map, porosity map and water
saturation map.
Figure 11Wells location in X field in term of primary scenario for vertical and deviated wells

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The location of each well was defined by the use of the CMG software
which the well coordinate in term of X and Y direction was known. Table 5 below
shows the location of each well based on real X contour map. Additionally, those
coordinates used to design the trajectory of the wells in order to hit the target (pay
zone) softly and economically.
Table 5Location of the wells target in term of primary scenario
Wells X Target Coordinate Y Target Coordinate
Vertical well
Well B 4500 ft 6200 ft
Directional Wells
Well A 6800 ft 3800 ft
Well C 1000 ft 9000 ft
Well D 2600 ft 10800 ft
3.2.4 Well trajectory design
Designing the trajectory of the well is one of the most important things
that drilling engineer must do through which a plan is drawn up in how to reach
the target with an optimal path in order to minimize the risks that can occur due
to the drilling process. In order to design the trajectory of the well, several
parameters should be taken into consideration as follow:
3.2.5 Elevation depth (Above the sea level)
Elevation depth is the distance above the sea level into the drilling rig. Elevation is
also called the height of above the level of sea into the surface or platform.
1. Sea level depth
Sea level is the level or height of the water in the ocean. While depth is the distance
below sea level.
2. Target depth
Target depth is the distance from the seabed into the maximum point which drilled to
reach the pay zone.

19
3. Kick-off point (KOP)
The Kick-off point is the point at which a directional well is deliberately drifting
vertically or drifting in a particular direction. To determine the kick-off point should
follow the equation below.
Kick-off point = Total TVD – ab – bd
4. Radius of curvature
Radius of curvature is the most known method to determine the directional survey.
The drillers can determine North, East, and TVD between directional surveys based
on the Radius of Curvature manner. The eqution shows below is used to determine
the raduis of curvature as the following. Radius of curvature is classified as a long
radius, medium radius, and short radius.
R =
1
Ꞵ
Ꞵ = (
𝑥
100
) (
𝜋
180
)
5. Build-up rate
The build-up rate is the rate of alteration of rising angle in the hole or the change of
hole inclination angle along the well path. To determine the build-up rate should
follow the equation below. After determined the radius of curvature, use the equation
below to find the build-up rate.
R =
1
Ꞵ
,
6. Inclination angle
The inclination angle is the angle between the vertical and the wellbore. The
inclination is the angle measurement between the true vertical axis and the wellbore
at any given point. The inclination angle is 90 degrees for horizontal well. Equation
shows below is used to determine the inclination angle.
Φ = built up rate x Radius
7. Azimuth
Azimuth is the measurement of angular in a several coordinate system. Azimuth is
defined as the angle between the reference north and the horizontal component of the
wellbore axis. For example, the north is 0° or 360°. East is 90° South is 180° West is
270°.

20
8. Total true vertical depth
The total true vertical depth is to measure a straight line vertically down from a
horizontal level. A true vertical depth, defined as TVD, is the measure from the top
to the bottom of the well in a straight vertical line represented by the line. The
equation shows below is used to determine the true vertical depth.
TVD = TVD well + water depth + DFE depth
9. Total departure
Total departure is the total distance from the surface to a point along a well track.
10. Total measure depth
The measure depth is the total length of the measured borehole along the well path.
The following equation is used to calculate the total measure depth.
S2 = KOP +
Ꞵ
3.8/100
S1 = S2 +
𝑇𝑉𝐷− (𝐾𝑂𝑃 + 𝑎𝑏𝑇𝑉𝐷)
𝐶𝑂𝑆 Ꞵ
Through the usages of the equations above, drilling parameters have been calculated in
which the trajectory of the wells has been designed based on them. Tables 6 bellow
show summary result for the drilling parameters for vertical and directional wells.
Figure 12 show the wells location.
Figure 12Wells direction for X field for vertical and deviated wells

21
Table 6Summary result of the drilling parameters for vertical and directional wells
2D design for vertical and directional wells
Well’s
Name
Elevation
depth
(Above
the sea
level) (ft)
Sea
level
depth
(ft)
Target
depth
(ft)
Kick-
off
point
(KOP)
(ft)
Radius of
curvature
(ft)
Build-
up rate
ft/100
Inclination
angle
(Degree)
Azimuth
(Degree)
True
vertical
depth
at
build-
up
section
(ft)
True
vertical
depth
at the
end of
build-
up
section
(ft)
Departure
at build-
up section
(ft)
Departure
at the end
of build-
up section
(ft)
Total
true
vertical
depth
(ft)
Total
departure
(ft)
Total
measure
depth
(ft)
B 80 200 10920 - - 0 0 - - - - 11200 - 11,200
A 80 200 10920 2300 1500 2.49/100 56 29 1243 7657 661 7128 11200 7789 15,992.9
C 80 200 10920 2100 2200 2.7/100 56 76.4 1823.9 7176 925 8130 11200 9055 18,867
D 80 200 10920 2300 2700 2.1/100 56 83.6 2238 6262 1190 9918 11200 11108 14,613.6
Figure 132D design for the trajectory of vertical well Figure 142D design for the trajectory of directional well

22
3.2.6 Well architecture and casing design
Pressure management
Analysis of the pore pressure in the reservoir formation is one of the main
factors through which the casing of the well is designed to suit the pressure in
each depth in order to avoid the burst or collapse issue. Additionally, the number
of casing can be defined by using the pore pressure and fracture pressure. Besides,
the mud weight can also be formulated based on pore pressure. The pore pressure
measured while drilling by the usage of Drill Stem Test (DST) and the fracture
pressure can be calculated through Eaton's Method. Table 7 shows the pore
pressure and fracture pressure versus depth which used to design the casing setting
depth
Table 7Pressure data versus depth for X reservoir
Pore pressure (ppg) Depth (ft) Frac pressure (ppg) Depth (ft)
9.542056 3.904577 11.57944 85.01902
9.747664 881.3009 11.72897 793.5738
9.971963 1287.125 11.84112 1097.564
10.23364 1558.43 11.99065 1334.421
10.49533 1863.428 12.40187 1707.812
10.70093 2302.819 12.70093 2316.296
10.98131 2843.792 13 2790.009
11.24299 3317.253 13.26168 3465.627
11.33645 3924.352 13.39252 4072.978
11.54206 4262.665 13.84112 4446.621
12.02804 4501.789 14.58879 4721.201
12.51402 4707.22 14.90654 6071.051
12.64486 4977.643 15.13084 6611.646
12.81308 5787.402 15.29907 7084.477
13.09346 6429.453 15.46729 7591.002
13.35514 7307.227 15.59813 8029.889
13.56075 7948.774 16.00935 8234.816
13.95327 8187.269 16.28972 8472.555
14.36449 8526.967 16.66355 9148.928
14.57009 9067.436 16.7757 9655.075
14.79439 9574.338 17.01869 10027.33

23
15.13084 10149.38 17.28037 10500.79
15.28037 10756.86 17.28037 10905.11
15.54206 11095.55 17.52336 11075.21
15.71028 11905.31 17.71028 11918.78
As shown in Table 7 there is an increase in the pore pressure as the depth
increases and then a slight decrease in the pore pressure followed by slight
overpressure and this happened due to two reasons. The first reason accrued
during drilling the exploration well in which the operation encountered
underbalanced in pressure while drilling through the pay-zone. Figure 15
illustrated the pressure profile in which the setting casing depth and mud weight
have designed. As shown clearly from the schematic, five different casing have
been selected which are conductor casing, surface casing, intermediate 1 casing,
intermediate 2 casing and production casing. The conductor casing started from 0
ft up to 300 ft and the mud weight for this depth formulated to be 10.7 ppg.
Additionally, the surface casing run until 2050 ft with a similar mud weight to the
conductor casing. Furthermore, the mud weight used for 4050ft depth where the
intermediate1 casing set is 12.3 ppg and for intermediate casing 2 set at depth
8200 ft with 14 ppg mud density. Additionally, the production casing set at depth
11200 ft with 16.7 ppg mud weight.
Figure 15Pressure Profiles Versus Depth

24
Casing and bit size
The cost of drilling and well completion process highly relied on the
annular and casing size. In order to select the optimal size of the wells, nodal and
sensitivity analysis should be taken into consideration in which the proper tubing
size selected. Therefore, the well and casing size designed will be selected based
on the production analysis result. Moreover, according to the casing setting depth
schematic that shows in Figure 16, it found that five types of the casing have been
selected based on the pore pressure and fracture pressure which are conductor,
surface, intermediate 1, intermediate 2 and production casing. additionally,
several parameters have considered for the selection of well and casing size for X
field as follow. The optimal tubing size has been selected based on the inflow and
outflow performance analysis and the completion facilitate planned to install with
the tubing string with considering the out diameter of completion equipment that
has a direct impact on the production casing. In addition, the casing size designed
smaller than the bit size and the largest outside diameter of the completion
equipment designed to be smaller than the inside diameter of the drilling bit size.
Figure 16 show the selection of the drilling bit and casing size for the five casing
types.
Figure 16Casing and bit size selection

25
Since there is no any investigation on the nodal analysis, it has assumed
that the optimal tubing size is 3.5 inch and according to that the production casing
size has selected to be 4.5 inches. Additionally, the conductor casing size has been
selected to be 24 inch which is the best option that can be used in an offshore
reservoir. Thus, by knowing the conductor and production casing size, the other
casing and bits size selected following API as shown in Figure 16 above.
Table 8bellow shows the selected casing size, bit size and mud weight versus depth
Load calculation
When all the casing depth have settled for each well, the burst and collapse
pressure calculated for each casing in order to distinguish the most proper type of
casing which can withstand the pressure.
Burst pressure is low expected of internal pressure in which the casing will
expose when the casing subjected to no external pressure. Meaning that the casing
will be deformed if the pressure inside the well is larger than the pressure outside
the well. Additionally, burst issue can happen during pumping drilling fluid
within the well and production process.
Collapse pressure is low expected of external pressure in which the casing
will collapse if the casing were subjected to no internal pressure. Meaning that the
casing will be collapse if the pressure outside the well is larger than the pressure
inside the well. In addition, Collapse issue can happen during the cementing
process, trapped fluid expansion and well evacuation.
In this section burst and collapse pressure for each casing will be calculated
in order to select the optimal casing grade based on the data illustrated in table 9
bellow.
Casing types Depth Mud density Casing Size Drilling Bit
size
Conductor Casing 300 ft 10.7 ppg 24inch 26 inches
Surface Casing 2050 ft 10.7 ppg 16 inches 20 inches
Intermediate 1 Casing 4050 ft 12.3 ppg 10 ¾ inch 14 ¾ inches
Intermediate 2 Casing 8200 ft 14 ppg 7 inches 8 ¾ inches
Production Casing 11200 ft 16.7 ppg 4 ½ inches 5.875 inches

26
Table 9Casing section size with other properties
Conductor Surface Intermediate
1
Intermediate
2
Production
Hole size (inch) 26 20 14 ¾ 8 ¾ 5.875
Casing size (inch) 24 16 10 ¾ 7 4 ½
Setting depth (ft) 300 2050 4050 8200 11200
Expected min/max pore
pressure gradient (ppg)
9.1/9.5 9.5/9.8 12/12.6 13.8/14.6 16.1/16.9
Expected LOT pressure
gradient (ppg)
13 14 16 17 18
Mud weight (ppg) 10.7 10.7 12.3 14 16.7
Burst Pressure at shoe
Burst Pressure = Internal Pressure − External Pressure ………………………………1
Internal Pressure = 0.052 × (𝜌 + 𝑠𝑎𝑓𝑒𝑡𝑦 𝑚𝑎𝑟𝑔𝑖𝑛) × ℎ ……………….……………...2
External Pressure = Brine Pressure Gradient × ℎ………………………………...…....3
Burst Pressure at surface
Internal Pressure = Injection Pressure − (0.1 × ℎ) × safety factor……………………...….4
Collapse Pressure
𝑃 = 𝜌𝑔ℎ ……………………………………………….……………...…………..…...5
Conductor Casing Section
Conductor casing used to prevent cave-in of the surface, and the burst and collapse
pressure must be calculated so that the casing used can meet its requirements.
Burst
Pore pressure at the bottom of the next hole (surface hole) = Max pore pressure at bottom
of next hole (surface hole) * Depth of next hole *0.052
= 9.1*2050*0.052
= 970 psi
Pressure at the surface = Pore pressure at the bottom of next hole (Surface hole) - (0.1*
Depth of next hole (surface hole))
= 970– (0.1 * 2050) = 765psi

27
Pressure at conductor casing shoe = Fracture Pressure at conductor shoe – (0.1 *
conductor setting depth)
= 970– (0.1 *300) = 940 psi
LOT pressure at conductor casing shoe = Expected LOT pressure gradient – (0.052 *
conductor setting depth)
= 13 * 0.052 *300 =202.8 psi
Max pressure at surface = LOT pressure at conductor casing shoe – (0.1* conductor
setting depth)
= 202.8 – (0.1 * 300) = 172.8 psi
Pore pressure conductor casing shoe = Min Pore pressure at conductor casing * 0.052 *
conductor setting depth
= 9.1 * 0.052 *300 = 141.9 psi
There is not any external force acting, then External pressure at surface = 0
Collapse
Collapse calculation for conductor casing, external, internal pressure at the surface and at
the shoe is zero.
Pore pressure at conductor casing shoe = Pore pressure at conductor casing * 0.052
*conductor setting depth
= 9.1 * 0.052 *300 = 141.9 psi
Table 10Summary result for burst pressure at the conductor casing
Depth External
load
Internal
load
Net load Design load Depth (ft)
Conductor 0 172.8 172.8 190.08 0
Casing shoe 141.9 202.8 60.9 67 300
Table 11Summary result for collapse pressure at the conductor casing
Depth External
load
Internal
load
Net load Design load Depth (ft)
Conductor 0 0 0 0 0
Casing shoe 141.9 0 141.9 141.9 300

28
Figure 17Show the burst and collapse for the conductor casing
Surface Casing Section
This part of the casing used to prevent water zone to inter in the drilled
well. The hole size can be up 17 inches in diameter. The depth of surface hole set
by regulatory agencies and they require the surface hole to be drilled by all water
zone and surface case to set and cemented to protect the zone from damage from
the addition drilling operation. This casing must be strong enough to support BOP
when connected and to be able to support the additional casing strings hanging
inside it.
Burst
Pore pressure at the bottom of the next hole (Intermediate hole) = Max pore
pressure at bottom of next hole (Intermediate hole) * Depth of next hole *0.052
= 9.5*4050*0.052
= 2000.7 psi
Pressure at the surface = Pore pressure at the bottom of next hole (Intermediate
hole) - (0.1* Depth of next hole (Intermediate hole))
= 2000.7 – (0.1 * 4050) = 1595 psi
Pressure at surface casing shoe = Fracture Pressure at surface shoe – (0.1 * surface
setting depth)
= 2000.7 – (0.1 *2050) = 1795.7 psi

29
LOT pressure at surface casing shoe = Expected LOT pressure gradient * 0.052 * surface
setting depth)
= 14 * 0.052 *2050 = 1492 psi
Max pressure at surface = LOT pressure at surface casing shoe – (0.1* surface setting
depth)
= 1492 – (0.1 * 2050) = 1287 psi
Pore pressure at surface casing shoe = Min Pore pressure at surface casing * 0.052 *
surface setting depth
= 9.5* 0.052 *2050 = 1012 psi
There is not any external force acting, then External pressure at surface = 0
Collapse
Collapse calculation for surface casing, external, internal pressure at the surface and at
the shoe is zero.
Pore pressure at surface casing shoe = Pore pressure at surface casing * 0.052 * surface
setting depth
= 9.5* 0.052 *2050 = 1012 psi
Table 12Summary result for burst pressure at the surface casing
Depth External
load
Internal load Net load Design load Depth (ft)
Surface 0 1287 1287 1415.7 0
Casing shoe 1012 1492 480 528 2050
Table 13Summary result for collapse pressure at the surface casing
Depth External
load
Surface 0 0 0 0 0
Casing shoe 1012 0 1012 1012 2050

30
Figure 18Show the burst and collapse for the surface casing
Intermediate 1 Casing Section
This part sometimes called troublesome formation, can be drill by adjusting
drilling fluids, and once drilled need to be sealed off to limit the problems that
occur while drilling deeper section of the well. The hole of this section must be
easily fitted inside the surface casing and can be up to 12 inches in diameter.
Intermediate casing often the largest part of the well.
Burst
Pore pressure at the bottom of the next hole intermediate 2 hole) = Max pore
pressure at bottom of next hole (production hole) * Depth of next hole *0.052
= 12 *8200*0.052
= 5116.86 psi
Pressure at the Intermediate 1 = Pore pressure at the bottom of next hole (intermediate 2
hole) - (0.1* Depth of next hole (intermediate 2))
= 5116.86 – (0.1 * 8200) = 4296.8 psi
Pressure at Intermediate 1 casing shoe = Fracture Pressure at Intermediate 1 shoe – (0.1
* Intermediate setting depth)
= 5116.86 – (0.1 *4050) = 4711.86 psi

31
LOT pressure at Intermediate 1 casing shoe = Expected LOT pressure gradient – (0.052
= 16* 0.052 *4050 = 3369.6 psi
Max pressure at Intermediate = LOT pressure at Intermediate 1 casing shoe – (0.1*
Intermediate setting depth)
= 3369.6 – (0.1 * 4050) = 2964.6 psi
Pore pressure at Intermediate casing shoe = Min Pore pressure at Intermediate 1 casing *
0.052 * Intermediate setting depth
= 12* 0.052 *4050 = 2527 psi
There is not any external force acting, then External pressure at Intermediate = 0
Collapse
Collapse calculation for Intermediate 1 casing, external, internal pressure at the surface
and at the shoe is zero.
Pore pressure at Intermediate 1 casing shoe = Pore pressure at Intermediate casing * 0.052
* Intermediate setting depth
= 12* 0.052 *4050 = 2527 psi
Table 14Summary result for burst pressure at the Intermediate 1 casing
Depth External
load
Surface 0 2964.6 2964.6 3261.1 0
Casing shoe 2527 3369.6 842.6 926.86 4050
Table 15Summary result for collapse pressure at the Intermediate 1 casing
Depth External
load
Surface 0 0 0 0 0
Casing shoe 2527 0 2527 2527 4050

32
Figure 19Show the burst and collapse for the intermediate 1 casing
Intermediate 2 Casing Section
It needed to divide two sections of intermediate casing because it’s the
longest section in the well and function of this part is same as the intermediate 1
as in is to prevent troublesome formation, and also can be drill by adjusting
drilling fluids, And once drilled need to be sealed off in order to prevent problems
in drilling deeper portion of the well.
Burst
Pore pressure at the bottom of the next hole (production hole) = Max pore pressure at
bottom of next hole (production hole) * Depth of next hole *0.052
= 14.6*11200*0.052
= 8503 psi
Pressure at the Intermediate 2 = Pore pressure at the bottom of next hole (production hole)
- (0.1* Depth of next hole (production hole))
= 8503– (0.1 * 11200) = 7383 psi
Pressure at Intermediate casing shoe = Fracture Pressure at Intermediate 2 shoe – (0.1 *
Intermediate setting depth)
= 8503 – (0.1 *8200) = 7683 psi

33
LOT pressure at Intermediate 2 casing shoe = Expected LOT pressure gradient – (0.052
= 17 * 0.052 *8200 = 7248.8 psi
Max pressure at Intermediate = LOT pressure at Intermediate casing shoe – (0.1*
Intermediate 2 setting depth)
= 7248.8 – (0.1 * 8200) = 6428.8 psi
Pore pressure at Intermediate casing shoe = Min Pore pressure at Intermediate 2 casing *
0.052 * Intermediate setting depth
= 13.8* 0.052 *8200 = 5543.2 psi
There is not any external force acting, then External pressure at Intermediate = 0
Collapse
Collapse calculation for Intermediate casing, external, internal pressure at the surface and
at the shoe is zero.
Pore pressure at Intermediate casing shoe = Pore pressure at Intermediate casing * 0.052
* Intermediate setting depth
= 13.8* 0.052 *8200 = 5543.2 psi
Table 16Summary result for burst pressure at the Intermediate 2 casing
Depth External
load
Surface 0 6428.8 6428.8 7071.7 0
Casing shoe 5543.2 7248.8 1705 1876 8200
Table 17Summary result for collapse pressure at the Intermediate 2 casing
Depth External
load
Surface 0 0 0 0 0
Casing shoe 5543.2 0 5543.2 5543.2 8200

34
Figure 20Show the burst and collapse for the intermediate 2 casing
Production Casing Section
The hole size of this section is between 4.5 - 10 inches in diameter. This
part of the zone penetrates the producing zone. Once the production zone is drilled
is needed to be protected and sealed. So, the production casing applied to isolate
the production zone and be ready for production after perforation.
Burst
Max pore press at tops of Production zone = Test perforation depth * Mud weight * 0.052
= 11200 * 16.7 * 0.052 = 9726 psi
CITHP at surface = Max pore press at tops of production zone – (0.15 * Test perforation
depth)
= 9726 – (0.15 * 11200) = 8046 psi
Pore press at top of liner = Casing shoe *Press at 11200 casing shoe * 0.052
= 11200 *16.9 *0.052
= 9376 psi
Internal load = Mud weight casing to be run * casing shoe *0.052
= 16.7 * 11200 * 0.052
= 9726 psi

35
External pressure = 0 (there is no external force act on it)
Table 18Summary result for burst pressure at the production casing
Depth External
load
Surface 0 9726 9726 10698 0
Casing shoe 9726 10698 972 1069 11200
Table 19Summary result for collapse pressure at the production casing
Depth External
load
Surface 0 0 0 0 0
Casing shoe 9726 0 9726 9726 11200
Figure 21Show the burst and collapse for the production casing
3.2.7 Casing material selection
The burst and collapse pressure calculation, casing size, casing grade are
summarized in the table 20 below.

36
Table 20Show the selection of the casing grade based on the burst and collapse pressure
Drilling bit type
The selection of the optimal drilling bit type is one of the important factors
that have a direct effect to enhance the drilling operation. Moreover, due to the
diversity of the formation rock in the oil and gas reservoir, one type of drilling bit
is not suitable to be used for all of them and thus drilling engineer used a different
type of drilling bit as appropriate accordingly to the formation condition. This
section includes an explanation for the selection of drilling bit for X field.
The X reservoir's formation has investigated and studied in order to define
the types of rock within the reservoir. Based on the geologist analysis, it found
that X formation consisted of pure sandstone rock that characterized by soft soil
in the top of the reservoir and medium rock in the rest of the reservoir lithology.
Therefore, one types of drilling bit have been selected with different size as it
shows in the table 21 below.
Table 21Show the selected drilling bit with the number of drilling bit required
As table 21 above shows, one types of drilling bit have been selected
which is TCI based on the reservoir lithology. Besides, the cost of drilling bit has
Depth (ft) Lithology Formation
Type
Bit
Type
Bit
Size
(Inch)
Rotary
Speed
(ft/hr)
Bit Limit
(ft)
No of Bit
required
0
Sandstone
Soft
TCI 26 25.67 419 1
300 Soft
2050
Soft
TCI
24 20.34 349 5
Soft Medium
Soft Medium
4050
Soft Medium
TCI 14 ¾ 15.12 400 5
Soft Medium
8200 Soft Medium
TCI
8 ¾
9.64 560 10
11200 Soft Medium 5.675 6

37
been considered in order to select the most suitable drilling bit types with
minimum cost. Accordingly, to the drilling bit limitation, the number of the
drilling bit that needed to drill from the surface to the target have defined.
Additionally, as clearly shown in table 21, only one drilling bit type TCI that
required to drill the depth for conductor casing and 5 drilling bits with the same
type used to drill the surface casing depth. However, when the reservoir formation
become harder while drilling, 15 drilling bit type TCI have been used to drill from
the intermediate 1 & 2. Additionally, For the production section, 6 bits required.

38
3.3 Efficiency and flow characteristics of drilling fluid which includes drilling
rate and pump operation
Figure 22Drilling data
3.3.1 Description of the Process
Secure Drilling is a managed pressure drilling technology specifically
designed to enable drilling of high-pressure, complex wells while enhancing
safety, improving drilling efficiency, and reducing the costs of the well. It collects
and analyzes drilling data (including pressures) and flow rates into and out of the
well bore to manage the well-bore pressures effectively. The Secure Drilling
system, using the patented Micro-Flux Control (MFC) technology, provides a
revolutionary change in the accuracy of measurement and analysis of flow and
pressure data, using proprietary algorithms to identify minute down-hole influxes
and losses on a real-time basis.
Santos, Leuchtenberg, and Shayegi (2003) describe MFC as a method
where drilling is conducted with the well closed (i.e., using a rotating control
device) and the return flow routed through a pressure/flow-control device (i.e., a
choke) and a precision flow measuring device

39
The system provides automated flow or pressure control using proprietary
software algorithms and real-time trending and comparison of well-bore pressures
and flows into and out of the well bore. It allows for adjustments in pressure or
flow and, thus, down-hole conditions while drilling, accomplished through
precise control of choke position. The system allows drilling decisions to be made
based on actual data versus predicted down-hole environments, providing real-
time monitoring of well-bore parameters. The Secure Drilling system is based on
real-time, measured data and uses typical drilling data inputs, including:
• Flow rates in and out of the well bore.
• Injection pressure (also called standpipe pressure).
• Surface back pressure
• Drilling fluid density (mud weight).
• Optionally, down-hole sensors, such as bottom-hole pressure
By assuming the discharge coefficient for small hole-size Cd =0.94 where
the discharge coefficient may be as high as 0.98, depending on the nozzle type
and size, but they recommended a value of 0.95 as a more practical limit.
In order to find the total flow area of each bit or reamer, you must add all
areas of each nozzle. For an instant, you use a bit that has a total of 5 nozzles.
Three nozzles have a diameter of 10/32 inch and the other 2 nozzles are 12/32-
inch diameter. Determine the total flow area (TFA) of the bit. By the definition,
you must sum every nozzle together in order to get the TFA; therefore, you can
apply the formula above into this form.
Table 22Assemble Required Bit Hydraulics Data
3.1 Data Values
Thickness (ft.) 135
Type of Fluid Oil
Vshale (%) 41
Saturation Pressure (psia) 1813
Reservoir Pressure (psia) 5189
Reservoir Temperature (°F) 250
Bubble Point Pressure (psia) 1785
Viscosity (cP) 0.37
Density ppg

40
Casing condition Casing is affectively closed with afloat
show
Surface equipment Combination 3
Rheology
reading
Reading at 600 rpm 55
Reading at 600 rpm 30
Pipe velocity 105 ft/min
Density 10.5 ppg
Table 23Finding data
Casing OD = 9 5/8 in 43.5 ib/100ft
ID = 8.775 in set at 6500ft
Open hole 8 ½ in 6500ft to 9500ft
Drill pipe OD = 4 ½ in, 16.6ib/100ft
ID = 3.826 in set at 9500
Drill coleader OD = 6 3/4 in, 450 ft
ID = 2 1/4 in set at 9500
Table 24From the above drilling data, we can get the following
Pipe Velocity 105
60
= 1.75 ft/s
𝜇𝑝 Plastic viscosity (cp)= [600 rpm reading] – [300 rpm reading]
𝜇𝑝 = 60 − 25 = 35cp
𝛾 Yield point = [300rpm reading] – Plastic Viscosity
𝛾 = 35 − 29 = 8 lb/100 ft
Total Flow Area (TFA)=
𝑛2
1303.8
= 0.451inch2
• A=0.451in2
• Pump efficiency = 80%
• Pmax =5189 psi
• μ𝑝 = 35
• Yield point = 6 ib/100ft2
Bump section will be used the Centrifugal Pumps which is used for high
depth and can be used till 15000ft.

41
The flow rate capacity which can be handle by using the Centrifugal Pumps
• Q1=300 gpm
• Q2= 500 gpm
Based on the graphs and the flow rate will be easy to find the pump pressure which
mean the surface pressure
• Ps1 = 3000psi
• Ps2= 7000psi
• HHP=
𝑝𝐵𝑜𝑝𝑡×Q
1714
= 1513 psi
. Figure 23Pump pressure versus mud flow rate.
Table 25selecting flow rate
Table 26Selecting yield point
Table
(1):

42
Table 27Combination for pressure loss in in drill pipe
3.4 Correct interpretation of bit hydraulics data
3.4.1 Pressure loss
Inside the drill pipe
V=
𝑞
2.448(𝑑2)
V=
300
2.448(3.826)2 = 8.37ft/s
μ𝑎 = μ𝑝 +
6.66γd
v
= 56 cp
μ𝑎 = 35 +
6.66×6×3.826
8.37
= 53 cp
𝑁𝑅𝑒 = 928 ×
ρvd
μa
𝑁𝑅𝑒 = 928 ×
14×8.37×3.826
36
= 7850
𝑁𝑅𝑒 = 7850 𝑁𝑅𝑒 ≥ 4000 Turblent flow
Drill pipe =11150ft
Id = 3.826
Od = 4.5
Drill collar = 50ft
Id = 2.25
Od = 6.75
Total =11200ft
Cased hole =11150ft
Id = 4.5
Od = 7

43
∆pf = (
𝜌0.75
𝑣1.75
𝜇0.25
1800(d)1.25
) × ∆l
∆pf = (
140.75 8.371.75350.25
1800(3.826)1.25 ) × (11150 + 479) = 875psi
Inside the drill collar
V=
𝑞
2.448(𝑑2)
= 24.2
μ𝑎 = μ𝑝 +
6.66γd
v
= 56 cp
μ𝑎 = 35 +
6.66×6×2.25
24.2
= 38 cp
𝑁𝑅𝑒 = 928 ×
ρvd
μa
= 18,616
𝑁𝑅𝑒 = 7850 𝑁𝑅𝑒 ≥ 4000 Turblent flow
∆pf = (
𝜌0.75
𝑣1.75
𝜇0.25
1800(d)1.25
) × ∆l
∆pf = (
140.75 24.21.75350.25
1800(2.25)1.25 ) × (50) = 46 psi
In the cased-hole annulus
V=
𝑞
2.448(𝑑2
2−𝑑1
2)
= 4.26ft/s
μ𝑎 = μ𝑝 +
𝟓×𝜸×(𝒅𝟐−𝒅𝟏)
𝒗
= 49.67
𝑁𝑅𝑒 = 757 ×
𝑃𝑉(𝑑2−𝑑1)
𝜇𝑎
= 2257
4000 > 𝑁𝑅𝑒 > 2100 Transtional flow/ Laminar flow
∆pf = (
μa × V
1000(d2 − d1)2
+
γ
200(d2 − d1)
) × ∆l
∆pf = 399 psi
Total pressure loss = 875psi + 46 psi + 399 psi = 1323 psi

44
3.4.2 Optimum Nozzle Size
• By assuming the discharge coefficient for small hole-size Cd =0.94 where the
discharge coefficient may be as high as 0.98, depending on the nozzle type
and size, but they recommended a value of 0.95 as a more practical limit.
• In order to find the total flow area of each bit or reamer, you must add all areas
of each nozzle. For an instant, you use a bit that has a total of 5 nozzles. Three
nozzles have a diameter of 10/32 inch and the other 2 nozzles are 12/32-inch
diameter. Determine the total flow area (TFA) of the bit. By the definition,
you must sum every nozzle together in order to get the TFA; therefore, you
can apply the formula above into this form
Total Flow Area (TFA)=
𝑛2
1303.8
= 0.451inch2
• A=0.451in2
• HHP=
𝑝𝐵𝑜𝑝𝑡×Q
1714
= 1513 psi
• 𝜌 = 14𝑝𝑝𝑔
• Pump efficiency = 80%
• Pmax =5189 psi
Surface casing
• Q1=500 gpm
• Q2= 1100 gpm
• Ps1=7000 psi
• Ps2=10000 psi
• 𝜌 = 16.7
∆PB1 =
8.311 × 10−5
p × 𝑞2
cd2 × Al2
∆PB1 =
8.311 × 10−5
× 10.7 × 5002
0.952 × 0.4512
= 1890 psi

45
∆PB2 =
8.311 × 10−5
× 10.7 × 11002
0.952 × 0.4512
= 9148 psi
𝑃𝑓1 = surface pressure − Bit pressure
Pf1= 7000-1890= 5110 psi
Pf2= 10000-9148= 851psi
α =
log(
pf2
pf1
)
log(
Q2
Q1
)
α =
log(
5110
851
)
log(
1100
500
)
= 2.27
❖ Finding Qmax and Qmin
Qmax =1714 × 𝑛 (
𝐻𝐻𝑃
𝑃𝑚𝑎𝑥
)
Qmax =1714× 2.27(
5189
9148
) = 2206 gpm
Qmin = 2.448(𝑑22
− 𝑑12)𝑣
Qmin = 2.448(242
− 162
) × 1.75 = 1370 𝑔𝑝𝑚
❖ Optimum friction pressure
Pfopt = (
1
𝛼+1
)𝑝𝑚𝑎𝑥
Pfopt = (
1
2.27+1
)9148 = 2797 𝑝𝑠𝑖
❖ Optimum pressure drops at the bit. PB
PB =Pmax – Pfopt
PB =9148-2797= 6350 psi
❖ Optimum flow rate
Qopt= Qa 𝑙𝑜𝑔−1
(
1
𝛼
𝑙𝑜𝑔 (
𝑝𝑓𝑜𝑝𝑡
𝑝𝑓𝑞𝑎
)

46
Qopt= 500× 𝑙𝑜𝑔−1
(
1
2.27
𝑙𝑜𝑔 (
2797
1890
)) = 594 gpm
Atopt=√
8.311×10−5×𝑝𝑄2𝑜𝑝𝑡
𝑐𝑑2𝑃𝐵𝑜𝑝𝑡
Atopt=√
8.311×10−5×10.7×5942
0.952×6350
=0.23 in2
𝑑 = 2√
0.23
3𝜋
= 0.16 𝑖𝑛
➢ Jet Impact force
α = 2.27 Qmax = 1100 gpm Qmin = 500 gpm
Pfopt = (
2
𝛼+2
) 𝑃
𝑚𝑎𝑥 = 2430 𝑝𝑠𝑖
❖ Optimum pressure drops
PB= Pmax- Pfopt
PB= 5189 - 2430 = 2758 psi
(
1
𝛼
𝑙𝑜𝑔 (
𝑝𝑓𝑞𝑎
)
Qopt = 500 𝑙𝑜𝑔−1
(
1
2.27
𝑙𝑜𝑔 (
2430
5110
)) = 360 𝑔𝑝𝑚
Atopt= √
8.311×10−5×10.7×3602
0.952×2758
= 0.22 𝑖𝑛2
𝑑 = 2√
0.22
3𝜋
= 0.15 𝑖𝑛
Intermediate casing
• Q1= 450 gpm
• Q2=700 gpm

47
• Ps1=4000 psi
• Ps2=7000 psi
• 𝜌 = 12.3
∆PB1 =
8.311 × 10−5
p × 𝑞2
cd2 × Al2
∆PB1 =
8.311 × 10−5
× 12.3 × 4002
0.952 × 0.4512
= 891 psi
∆PB2 =
8.311 × 10−5
× 12.3 × 7502
0.952 × 0.4512
= 3132 psi
❖ 𝑃𝑓1 = surface pressure − Bit pressure
Pf1= 3500-891= 2609 psi
Pf2= 8000-3132= 4868 psi
α =
log(
pf2
pf1
)
log(
Q2
Q1
)
= 1.42
Qmax =1714 × α (
𝐻𝐻𝑃
𝑃𝑚𝑎𝑥
) = 710
Qmin = 2.448(𝑑22
− 𝑑12)𝑣 = 601
Pfopt = (
1
𝛼+1
)𝑝𝑚𝑎𝑥 = 2144 𝑝𝑠𝑖
PB =Pmax – Pfopt = 3045 psi
(
1
𝛼
𝑙𝑜𝑔 (
𝑝𝑓𝑞𝑎
) = 391
Atopt=√
8.311×10−5×𝑝𝑄2𝑜𝑝𝑡
= 0.23𝑖𝑛2

48
𝑑 = 2√
0.23
3𝜋
= 0.16 𝑖𝑛
α = 1.42 Qmax = 700gpm Qmin = 400gpm
Pfopt = (
2
𝛼+2
) 𝑃
𝑚𝑎𝑥 = 3034psi
PB= Pmax- Pfopt = 2155
(
1
𝛼
𝑙𝑜𝑔 (
𝑝𝑓𝑞𝑎
) = 500gpm
Atopt= √
8.311×10−5×12.3×5002
0.952×2155
= 0.36 𝑖𝑛2
𝑑 = 2√
0.36
3𝜋
= 0.19 𝑖𝑛
Intermediate (2) casing
• Q1= 300 gpm
• Q2=500 gpm
• Ps1=4500 psi
• Ps2=7000 psi
• 𝜌 = 14
∆PB1 =
8.311 × 10−5
p × 𝑞2
cd2 × Al2
∆PB1 =
8.311 × 10−5
× 14 × 3002
0.952 × 0.4512
= 570 psi

49
∆PB2 =
8.311 × 10−5
× 12.3 × 4002
0.952 × 0.4512
= 1548 psi
Pf1= 3000-570= 2430 psi
Pf2= 7000-1548= 5452 psi
α =
log(
pf2
pf1
)
log(
Q2
Q1
)
= 1.58
Qmax =1714 × α (
𝐻𝐻𝑃
𝑃𝑚𝑎𝑥
) = 789
Qmin = 2.448(𝑑22
− 𝑑12)𝑣 = 285
Pfopt = (
1
𝛼+1
(
1
𝛼
𝑙𝑜𝑔 (
𝑝𝑓𝑞𝑎
) = 267
Atopt=√
8.311×10−5×𝑝𝑄2𝑜𝑝𝑡
= 0.17𝑖𝑛2
𝑑 = 2√
0.17
3𝜋
= 0.13 𝑖𝑛

50
Pfopt = (
2
𝛼+2
) 𝑃
𝑚𝑎𝑥 = 2898 psi
PB= Pmax- Pfopt = 2290psi
(
1
𝛼
𝑙𝑜𝑔 (
𝑝𝑓𝑞𝑎
) = 335gpm
Atopt= √
8.311×10−5×14×3352
0.952×2290
= 0.25 𝑖𝑛2
𝑑 = 2√
0.25
3𝜋
= 0.16 𝑖𝑛
Production casing
• Q1= 200 gpm
• Q2= 400 gpm
• Ps1=2000 psi
• Ps2=3500 psi
• 𝜌 = 16.7
∆PB1 =
8.311 × 10−5
p × 𝑞2
cd2 × Al2
∆PB1 =
8.311 × 10−5
× 16.7 × 2002
0.952 × 0.4512
= 302 psi
∆PB2 =
8.311 × 10−5
× 16.7 × 4002
0.952 × 0.4512
= 1209 psi
Pf1= 2000-302= 1698 psi
Pf2= 3500-1291= 2291 psi

51
α =
log(
pf2
pf1
)
log(
Q2
Q1
)
= 1.04
Qmax =1714 × α (
𝐻𝐻𝑃
𝑃𝑚𝑎𝑥
) = 519
Qmin = 2.448(𝑑22
− 𝑑12)𝑣 = 123
Pfopt = (
1
𝛼+1
(
1
𝛼
𝑙𝑜𝑔 (
𝑝𝑓𝑞𝑎
) = 295
Atopt=√
8.311×10−5×𝑝𝑄2𝑜𝑝𝑡
= 0.22
𝑑 = 2√
0.22
3𝜋
= 0.15 𝑖𝑛
Pfopt = (
2
𝛼+2
) 𝑃
𝑚𝑎𝑥 = 3413 psi
PB= Pmax- Pfopt = 1774 psi
(
1
𝛼
𝑙𝑜𝑔 (
𝑝𝑓𝑞𝑎
) = 391gpm

52
Atopt= √
8.311×10−5×16.7×3912
0.952×1774
= 0.36 𝑖𝑛2
𝑑 = 2√
0.36
3𝜋
= 0.2 𝑖𝑛
3.5 Adhere to IADC bit classification
3.5.1 Drilling bit type
The selection of the optimal drilling bit type is one of the important factors
that have a direct effect to enhance the drilling operation. Moreover, due to the
diversity of the formation rock in the oil and gas reservoir, one type of drilling bit
is not suitable to be used for all of them and thus drilling engineer used a different
type of drilling bit as appropriate accordingly to the formation condition. This
section includes an explanation for the selection of drilling bit for this resrvoir
Therefore, there is one type of drilling bit have been selected with different
size as it shows in the table 28 below.
Table 28Show the selected drilling bit with the number of drilling bit required
As table 28 above shows, two types of drilling bit have been selected
which are TCI based on the reservoir lithology. Besides, the cost of drilling bit
has been considered in order to select the most suitable drilling bit types with
minimum cost. Accordingly, to the drilling bit limitation, the number of the
drilling bit that needed to drill from the surface to the target have defined.
Additionally, as clearly shown in table 20, only one drilling bit type TCI that
Depth (ft) Lithology Formation
Type
Bit
Type
Bit
Size
(Inch)
Rotary
Speed
(ft/hr)
Bit Limit
(ft)
No of Bit
required
0
Sandstone
Soft
TCI 26 25.67 419 1
300 Soft
2050
Soft
TCI
24 20.34 349 5
Soft Medium
Soft Medium
4050
Soft Medium
TCI 14 ¾ 15.12 400 5
Soft Medium
8200 Soft Medium
TCI
8 ¾
9.64 560 10
11200 Soft Medium 5.675 6

53
required to drill the depth for conductor casing and 4 drilling bits with the same
type used to drill the surface casing depth and others.
IADC CLASSIFICATION FOR ROLLER CONE BITS
IADC code consists of four characters, indicating bit design and formation
type being drilled. The first three characters are numerical, the fourth one – literal.
The numerical code character sequence is determined as «series-type-
bearing/gauge». The fourth literal code character defines «additional features».
First code digit – roller cone bit series (1-8). Eight categories of roller cone bit
series correspond to the general characteristics of rock formations being drilled.
Series from 1 to 3 determine Steel Tooth bits, and series from 4 to 8 – Tungsten
Carbide Tooth. Increasing of inside group digits designates increasing of rock
formation hardness. Second code digit – roller cone bit type (1-4). Each series
divided into 4 types according to rock formation hardness. Type 1 corresponds to
drill bits for the softest rock formations within the series, and type 4 – for the
hardest ones. Third code digit (1-7) characterizes bearing type and gauge
protection availability. Fourth literate code character – «additional features»
(unrequired). 16 letters are used to describe specific cutting structures, bearings,
jets and gauge protections of a bit. If bit has more than one additional feature the
only most significant one is to be indicated.
Figure 24IADC Classification for Roller Cone Bits

54
3.6 Drill bit cost (10 marks)
3.6.1 Drilling bit cost
The cost of the drilling bit highly relied upon the material that used to
make the drilling bit and its size. As it has explained in the section of selecting
the drilling bit, two types of drilling bit have been chosen which are roller cutter
type TCI and fix cutter type PDC. The cost estimation for all the bit that used to
drill well illustrated in table 29 below.
Table 29Drilling bit cost
Bit Type Bit Cost (USD) Number of
Bit needed
Total Cost (USD)
TCI (24 Inches) $ 23,100 1 $ 23,100
TCI (20 Inches) $ 15,500 4 $ 62,000
TCI (14 ¾ Inches) $ 13,000 5 $ 104,000
TCI (8 ¾ Inches) $ 12,000 7 $ 84,000
Total Cost $ 273,100
3.6.2 Drilling fluid cost
Drilling fluid cost can be estimated based on the price of the component
that mud consisted of. The drilling mud used in this project is water-based mud
that consisted of water and bentonite. Additionally, barite has been added in order
to increase the density of the drilling mud for intermediate and production
sections. Table 30 below show the cost of the drilling fluid that used for Sirri A
field.
Table 30Cost of drilling mud
Mud Cost Mud Mixture Cost per liter
USD/liter
Total of
liter used
Total cost
Water, Bentonite
clay, barite
$ 0.98 101317 $ 99,291

55
3.7 Suitability of the proposed innovative solutions with suggested
improvements, where necessary
This section will analyze the process which has been analyzing for this
assignment. First of all, it has been used the porosity map and oil saturation map
to find the suitable area to drill the well, the secondary has been analyzed and
found the data required to calculate the pressure loss and the Optimum Nozzle
Size for drilling the wells and types of the wells which will be used. The types of
drill bits depending on the formation. Moreover, the innovative of this project has
been found analyze the Bit Hydraulics Analysis for Efficient Hole Cleaning from
the surface till production case and considering the pressure loss, and calculating
the how many nozzles required for each stage of drilling
Secondly, has been selecting the casing design based on the pore pressure
and fracture pressure and based on the graph has been selecting the bit sizes, depth
for each casing and the mud weigh required to calcite the pressure loss and the
nozzle sizes.
Finally, I suggested improvements on the work and try to use software to
make which make the calculation more accurate, and also I suggested that the data
should be found before you start the process, and make sure you have timeline to
start the project which well helps to finish the project successfully.

56
CHAPTER 13
DISCUSSION, CONCLUSION AND RECOMMENDATIONS
4.1 Discussion
This project was helpful for the student to get knowledge in general about
the petroleum engineer and how to calculate the pressure loss of the system as
well as the section of the optimum nozzle for the drill bit this assignment will
helps allot the drilling engineer in future. Furthermore; this project helps to solve
the challenges that faced the petroleum engineer in real life. However, in this
project, the student learned how to deal with errors and converted to the advantage
and overcome with better results.
First of all. It has been collecting all the data required to design the system,
the data which has been calculating those partners are flow rate, hours
overpressure at surface and the pumps efficiency which is 80%. The flow rate has
been found from the table (25). Moreover, the surface pressure has been
calculating from the graph which is versus the flow rate for minimum and
maximum.
which is selected based on the bit dimeters. After founding the flow rate
was easy to found the Hp which was 1513 psi. A after that it has been obtained
the location for the depth to drill based on the water saturation map and the
porosity
Moreover, after getting all the data required has been calculated the
pressure loss for the system based on the pore pressure graph, it has calculating
the pressure loss for the drill pipe, drill collier and the cased hole annulus, and the
total loss was 1323 psi.
Secondly, it has been calculating the optimum nozzle for surface casing
intermediate casing and the production casing. The optimization of bit hydraulics
increases the penetration rate and improves the cleaning action at the hole bottom.
There is controversy as to whether maximization of hydraulic horsepower or
impact force produces the best results. The program utilizes both optimization

57
method. Actually, both theories provide almost the same results. If hydraulic
horsepower is maximum, the jet impact force will be 80% - of the maximum and
vice versa.
It is sometimes desired to estimate the proper pump operating conditions
and nozzle sizes for hydraulics optimization during the planning phase of the well.
The data required for planning include mud program, hole geometry, and assumed
flow rate. Based on frictional pressure drop, the program calculates the optimum
hydraulics based on either the maximum jet impact force or maximum hydraulic
horsepower criterion.
From the given data the optimum mud flow rates and the nozzle sizes
should be designed for drilling at various depths until the end of the section. The
nozzle areas of hydraulics horsepower for surface casing was 0.27 𝑖𝑛2
, and for
the intermediate casing are 0.23𝑖𝑛2
and 0,17𝑖𝑛2
, and the last optimum nozzle area
for the production which has been calculated is 0.2𝑖𝑛2
. Last but not less this
assignment was helpful l for student to get knowledge about the drilling
hydraulics.
4.2 Conclusion
Nozzle configuration appears to have an effect on penetration rate. Several
authors have described improved drill rates with extended or blanked nozzle bits.
However, presently used criteria have been unable to account for these improved
drill rates. in fact, has suggested a different optimum may exist for each nozzle
size. Drill cuttings in the well bore cause wear and tear to the drill string and this
reduces the rate of penetration; therefore, there is need for efficient bottom hole
cleaning. During drilling operation, optimization of hydraulic horsepower at the
drill bit is adopted to enhance bottom hole cleaning and to increase the rate of
penetration. Optimum drilling conditions are achieved using either the maximum
horsepower criterion or the hydraulic jet impact force criterion.
This study shows that pressure loss in the mud circulatory system depends
on the mud and the circulating flow rate. Also, the operating conditions obtained
in this study show that the flow rate exceeds the minimum flow rate required for
drill cuttings removal. One unique aspect of this project work is the integration of
experimental work designed to generate rheological data for theoretical
computation.

58
Finally, a method of selecting nozzle sizes and flow rates is presented
which can be used with familiar bit-hydraulic and calculators to design jet-bit
programs for maximum bit hydraulic horsepower, impact or jet velocity, as
desired.
4.3 Limitations
1- While finding the data was difficult to predict the hores poer due to
the por in data given, however this problem has been solved
2- Obtaining the location to drill the now wells was difficult to know the
suitable location for it
3- Viscosity, yield point, and mud density should be found in proper way
other whys will affect in our results
4.4 Recommendations and Suggestions for further research
Recommendations and Suggestions of this assignment, reduce the errors
of the of calculating the pressure loss and the optimum nozzle size, by founding
the suitable data needed to calculate those prompters.
Use more technology and idea to overcome with better results, I
suggestions that this assignment can helps a lot the student if they refer back to
this project will help a lot in solving the problems in each department of the
petroleum.

59
4.5 References
1. Anon., 2018. IADC CLASSIFICATION FOR PDC AND DIAMOND BITS. s.l.:s.n.
2. Anon., 2019. IADC CLASSIFICATION FOR ROLLER CONE BITS. s.l.:s.n.Juan,
2018. Total Flow Area (TFA). s.l.:s.n.
3. KEYUAN, 2019. Nozzle Total Flow Area (TFA). s.l.:s.n.
4. Lim, 1996. Bit Hydraulics Analysis for Efficient Hole Cleaning. s.l.:s.n.
5. Makogon, T. Y., 2018. Hydraulic and thermal analysis. s.l.:s.n.
6. Mount Carmel, 2018. Nozzle Total Flow Area (TFA). s.l.:s.n.
7. ONEPETRO, 2018. Bit Hydraulics Analysis for Efficient Hole Cleaning. s.l.:s.n.
8. Ramsey, M. S., 2017. Introduction and Importance of Bit Hydraulics
Optimization. s.l.:s.n.
9. Staff, P., 2018. Pump Types Guide - Find the right pump for the job. s.l.:s.n.

60
http://www.drillingformulas.com/total-flow-area-tfa/
http://www.bestebit.com/wp-content/uploads/2016/11/TFA-Chart.pdf
http://www.premiumrockbit.com/BitNozzleFlowChart.pdf
http://burintekh.com/upload/iblock/d51/d5160461ef4a840e5a038956f77ea242.pdf
https://www.sciencedirect.com/topics/engineering/hydraulic-design
http://burintekh.com/upload/iblock/021/0216f0d14fd93c321768361cd9a9d977.pdf
http://www.pumpscout.com/articles-scout-guide/pump-types-guide-aid100.html
https://www.onepetro.org/conference-paper/SPE-35667-MS
https://www.sciencedirect.com/topics/engineering/bit-hydraulics

BIT HYDRAULICS ANALYSIS FOR EFFICIENT HOLE CLEANING

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