the function of hydraulic optimization on oil and gas …
TRANSCRIPT
THE FUNCTION OF HYDRAULIC OPTIMIZATION ON OIL AND GAS WELL DRILLING PROCESS
An MS Thesis
by
Zoltán Mosonyi
Submitted to the Petroleum Engineering Department of University of Miskolc
in partial fulfillment of the requirements for the degree of
MASTER OF SCIENCE in Petroleum Engineering
May 2014
Table of content
1. Introduction ......................................................................................................... 1
1.1. Structure of thesis ........................................................................................... 1
1.2. Aims and Functions ......................................................................................... 2
1.3. Introduction to the hydraulic system ................................................................ 4
2. Hydraulic parameters and their management ..................................................... 6
2.1 Standpipe Pressure ......................................................................................... 6
2.2 Pumping/Liquid Rate ....................................................................................... 8
2.3 Annular Fluid Velocity.....................................................................................11
2.4 Pressure Losses ............................................................................................12
2.5 Total Flow Area ..............................................................................................15
2.6 Hydraulic Performance ...................................................................................16
2.7 Finishing Thoughts .........................................................................................18
3. Drilling Mud Parameters ....................................................................................20
3.1 Mud Weight ....................................................................................................20
3.2 Rheology and Viscosity ..................................................................................21
3.3 Solid content ..................................................................................................27
3.4 Equivalent Circulating Density ........................................................................28
3.5 Finishing Thoughts .........................................................................................29
4. Steps of the optimization process ......................................................................30
5. Detailed analyses of the hydraulic system of well name "Dip-1" .........................34
5.1 Well structure and initial hydraulic and mud parameters .................................34
5.2 The sectional overview and analyses of the hydraulic and mud parameters ...37
5.3 Summary of the practical well data .................................................................50
5.4 Possible improvements of the sections ..........................................................52
6. Conclusions .......................................................................................................62
Summary
The point of my diploma is to introduce the optimization process of a drilling operation
while thoroughly demonstrates the role of the hydraulic system and the hydraulic
parameters during the drilling process along with the related methods, procedures and
calculations. To understand the whole process of optimization, the deep knowledge of the
hydraulic system’s components is a must, and the ability to use the related formulas and
calculations are also a must to perform the complete drilling process.
The first chapter of my work describes the general aim of the optimization and lists its
functions, while introducing the basics of the hydraulic and drilling fluid systems. There is
primary importance to understand the principles of such a complex subject as the
optimization, which principles have always major influences on the whole process
beginning from the spud of the well till finishing the completion phase.
The second section deals with the most and directly influential hydraulic properties of
the drilling operation, introduces the affective system components and their effects on
each other. It’s necessary to possess sound knowledge on the drilling system components
and to know their effects on the hydraulic properties to provide an acceptable optimization
procedure. The major parameters of drilling mud are also represented in this section,
because their impact on the above mentioned hydraulic properties are significant. The
section also contains the steps of the optimization process which is later used for my
personal work, and analyzes them in details.
The last section of my diploma is about the optimization of an actual well drilling that
took place here in Hungary, applying the previously exposed parameters and calculations,
observing the regulations and principles which was given in the first chapter. The section
provides a huge amount of self-calculated data, which has been evaluated in graphs and
tables for clear presentation. My personal work covers the different stages of optimization,
from the early design of the well, through the construction of proposed plans and
programs of the hydraulic and mud systems, till the completion stage. The chapter
contains a possible forecast with values of the properties, optimized both for security and
performance for the different sections of the well. At the end of the section I listed my
comparisons and the related conclusions based on the gathered and computed data.
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List of acronyms
SI System International
API American Petroleum Institute
BHA Bottom Hole Assembly
ROP Rate Of Penetration
SPM Stroke Per Minute
PDM Positive Displacement Motor
CMC - Carboxy Methyl Celluloze
HSI Horsepower Per Square Inch
POOH Pull Out Of Hole
RIH Run In Hole
MD Measured Depth
TFA Total Flow Area
TVD True Vertical Depth
ERD Extended Reach Drilling
MWD Measuring While Drilling
SG Specific Gravity
ECD Equivalent Circulating Density
LGS Low Gravity Solids
HGS High Gravity Solids
PV Plastic Viscosity
SPP Standpipe Pressure
YP Yield Point
HTHP High Temperature High Pressure
ppg pound per gallon
psi pound per square inch
ft foot
in (”) inch
cP centi poise
IFE Integrated Fluids Engineering
ρ density
d1 outer diameter of drill pipe, collar
D inner diameter of pipe
d2 inner diameter of open hole section
Dn1,Dn2,Dn3 diameter of nozzles
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N Nozzle size in 1/32"
K Consistency index
n Power Law index
Q Flow Rate
gpm gallon per minute
lpm liter per minute
Va Annular Velocity
Vca Critical Annular Velocity
Qca Critical Flow Rate
Dl diameter of liner
Ls stroke length
ev volumetric efficiency
Ph hydrostatic pressure
Pf frictional pressure loss
Pa Pressure Loss in Annulus
Pp Pressure Loss in Pipe
Pbit Bit Pressure Loss
L Well Depth
fa Annular Friction Factor
fp Friction Factor of Pipe
NRea Reynolds number in annulus
NRep Reynolds number in pipe
Θ Fann 35 readings
Vn Nozzle Velocity
P pressure
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1. Introduction
The first objective of the diploma is to emphasize the importance of the optimization
process and proving the relevance of proper hydraulic system design. The second aim is
to demonstrate the financial benefit and time-efficiency of a correctly performed
optimization project.
1.1. Structure of thesis
The first chapter of my work states the general functions of the optimization, gives a list
of its practical uses in case of oil or gas well drillings and describes the key elements
wherethrough the needed parameters can be optimized.
The second section describes the hydraulic system of oil and gas wells in details and
presents the drilling mud parameters which have the major effect on the hydraulic
properties. For understanding the latter calculations, an accurate knowledge of the rig
components and their effects on the hydraulic system is a must. For the logical structure
of each part of this section, the overview of the rig components and the hydraulic system
is based on the path of a closed loop drilling fluids circulation system.
Due to their primary importance in the optimization process, the mud properties such
as density, rheology, viscosity, solid content and ECD must also be exposed in details and
are introduced in the third chapter of the diploma.
The fourth section introduces the main steps of the optimization process and highlights
the most significant features of it. These steps are used in the latest chapter for the
optimization of my personally analyzed well.
The fifth chapter of the diploma gives an overview of my personal work on the subjects
by providing drilling optimization of a real oil-well and collaborating the statements and
principles of the previous chapters through my collected and calculated data. The
introduction of the well is divided into three parts: first the initial plan of the well hydraulic
system is presented, secondly the practical results of the drilling are introduced and the
last part gives the possible improvements of the well hydraulics. The presentation of the
possible prospects is the most significant part of my personal work, because the timely
and financial advantages of the optimization process will be enhanced by these parts. To
make the benefits of the process more highlighted and make the results and their
comparisons more visible, the chapter will provide huge amount of data collected in
tables, charts and graphs. To establish the conclusions of the final chapter the
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understanding of the basic principles of the optimization is a key-element, and that is
provided in the following section.
1.2. Aims and Functions
To clearly see the real purpose of the application of optimization during the drilling
process, we must know the lead ideas and principles behind the well drilling operation
which are the basis of every well design. Engineers always try to improve the performance
of the drilling and the well not just to make it successful, but to make it successful in the
most cost-effective and time-effective way as much as possible. It’s true that these
challenging tasks are highly important in the complex system of oil and gas well drilling,
but the safety always takes priority over all. The safekeeping of the health of the rig
personnel and the well components are always primary because that is the utmost
requirement of all that have to be fulfilled through the whole drilling project. The rig
personnel can ensure the success of the entire project from end to end by keeping the
safety at its maximum, this way all damage to the formation or the well build-up, all
possible harm to the rig components and all potential danger to the crew can be avoided.
The elevation of any of the hydraulic parameters of the system, the mud properties or
performance in drilling are possible only if all the given security standards have been
accounted. That is the so called „safety first” rule, which is practiced by all company in the
world and a basic and leading principle in every task which is any way related to
engineering. The possibility of improving the properties and parameters while keeping the
safety at its maximum is always there, but the crew always has to keep in mind which is
the most important of all. Nowadays, when the rig personnel must work in extreme
conditions and the oil and gas wells develop high temperatures and high pressures at the
same time, thus the smallest gap in safety can lead to life-threatening situations. To
summarize the leading principles of the optimization we can separate two leading ideas
that are used in the drilling practice:
- Safety
- Performance
The world of oil and gas well drilling is constantly (and rapidly) improving as new
advanced technologies introduced every year, thus increasing the competition between oil
companies. The demand for black and refined oil is also growing year by year and in
addition to that the reserves are constantly depleting. Therefore, the price of oil keeps
increasing and with it the cost of equipments are on the rise too, making the whole drilling
operation the most sumptuous work of all. With new technologies in use we can explore
such formations which were previously inaccessible because of the extreme depths,
pressures and temperatures. But in recent days most of these reservoirs are within our
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access radius, although they demand the latest technical developments and a skillful and
well-trained crew due to the extreme conditions in which they can be found. We have to
keep in my mind that the newly explored oil reservoirs are all belong to the type with the
special circumstances, and because of that the daily and overall cost of a well drilled
down in such conditions can be immensely high. To sum up it all, we have decreasing
reserves while increasing demands, more and more difficult to reach oil accumulations
and more expensive equipments. These circumstances leads to the conclusion that
today’s oil companies have to use the advanced but high-cost facilities and drill down the
given well in the shortest possible time while maintaining the maximum safety, which is a
considerably difficult task. That is why the optimization is desirable on every oil well
drilling, its primary functions fulfill the demands of even the most difficult wells and its use
may have timely and financial advantages as well. With the usage of an optimization
process the drilling crew can ensure the safety of the well and the rig personnel while
have the possibility to enhance the drilling performance. Due to the improvement in drilling
rate, the time for the whole operation can be lessen, which leads to reduced costs. In
today’s operations one or even a half-day reduction in time can be significant and can
mean millions of Hungarian Forint less expenses at the end of the drilling project. So, to
summarize all the functions of optimization, we can list several different but cross linked
purposes:
- To ensure the needed safety
- To set the parameters to their optimum
- To keep the wear on the equipment at minimum
- To lessen the overall time of the drilling process
- To decrease the expenses of the drilling project
As we can see the optimization of a well is a quite complex task with many different
aims, so it’s understandable that in most cases it is impossible to maintain all of these at
once. As I mentioned before the safety rule is the first of them and only after that comes
the remaining, depending on the current situation of the drilling operation. It is always
possible that the one and only feature which can be optimized is the safety of the well,
because the limitations given by the circumstances makes it impossible to further improve
the performance or any of the parameters, let alone lessening the drill-time and the
expenses. On the other hand when we reached the adequate security, we can try to
enhance the parameters and properties which can lead to a decent increase in drilling
performance. It’s important to state that the optimization process is mostly depend on the
limitations given by the well parameters and the rig components, basically, the
advantages of its application will only develop if it’s used with the proper installation. The
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list of these limiting parameters will be introduced in later sections of the diploma, as well
as the interfaces of its practical application.
What remains to be stated is that the optimization process has to be applied from the
very beginning of the drilling operation, which means that the early designs have to be
done with the optimized values of the properties. From that point on till the very end of the
drilling procedure, the calculations for optimization are always part of the normal tasks,
thus ensuring the successfulness of the well.
To further understand the process itself, the equipment through which the optimization
can be done must be introduced. Because my diploma deals with the hydraulic system
optimization, I present the hydraulic system of the well and the drilling mud properties in
details in later chapters. The next section gives a general overview of these components
and their influence on the hydraulic optimization.
1.3. Introduction to the hydraulic system
It has to be stated that the successful completion of a well depends on the combined
application of several different earth-science.
Each drilling project starts with thorough geophysical and geological surveys performed
by experts; without these evaluations the design of the operation cannot be continued.
The geophysical and geological surveys are present the necessary data of the strata in
order to get an accurate approximation of the formations which will be drilled through.
Also, the reservoir mechanical evaluation of the offset well data can provide good
estimation of the production of a well. This information on the target formations is
necessary to properly design the well structure by safety and financial aspects and the
basis of further processes. If all the sufficient data on the strata (reservoir) is present the
casing design should take place along with the design of the bottom hole assembly which
is one of the basic requirements for starting of the drilling project. The proper selection of
the components building up the BHA is necessary to successfully drill down any well and
will have a significant impact on the rate of penetration. In addition, the further design of
the hydraulic system also depends on the relation of annular space and bottom hole
assembly due to its function in the management of well hydraulics, so the first point of the
hydraulic system, starting from the bottom, is the BHA. When its design is completed the
remaining parts of the system must be adjusted to it in performance and safety to achieve
a proper relation between the different components of the rig. The BHA will be followed by
the complete drill string in the well and the annulus area which is bounded by the casing.
These parts of the hydraulic system will provide the acting surface of the different
hydraulic factors and thus they are also key important in the optimization process. At the
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surface the most important part of the drilling installation is the mud pumps with the
connected surface equipment. The pressure relations and the pressure losses inside the
well are all related to the standpipe pressure and pump rate developed by the mud
pumps.
To summarize the basic components of the set-up from bottom to top:
- Bottom Hole Assembly
- Drill String and Annulus
- Casing String
- Surface Equipment
- Mud Pumps
Drilling mud has to be added to the list because the impact of its parameter values on
the hydraulic factors is significant and have to be reckoned with. The previously
mentioned rig and well system elements are not the only parts of the rig hydraulic system,
but their impact on the hydraulic factors are the most direct and so they are the base of
the hydraulic optimization process. With the correct management of the listed parts and
the application of the optimization calculations the safety and the drilling performance of
the rig will be improved. We have to emphasize that the effects on the system can be
negative as well, which means that a given factor could not be improved, but instead it’s
limiting property. In these cases, all of the related parameters should be adjusted by this
value and the possibilities of the optimization will be restricted. These limiting factors
usually linked to the reservoir circumstances like formation pressure and nothing could be
done about it, but the rig installation could also happen to be the limiter. If the situation is
that, the rig personnel can check the equipment thus spotting the fault in the system and
solve the problem as soon as possible. Another option is that the early design of the
drilling project lacked the most accurate information about the well and due to that the
program is not optimal because it is based on false data. That is why the optimization
process must always be applied to the calculations during the whole drilling program. The
next section of the diploma gives a detailed overview of the above mentioned factors and
their relation to the previously rehearsed drilling rig components and the drilling mud
parameters.
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2. Hydraulic parameters and their management
As one of the most complex procedure during the drilling operation, the optimization of
the well hydraulics is rather a chain of different tasks than a single problem. The various
components are highly cross linked and have impact on each other’s properties so their
management cannot be done separately. It is of utmost importance to have an under-
standing of the correlation between these components since all of the results from the
required calculations will depend on their interactions. The hydraulic system serves for
many purposes in the well. Since it is focused on the mud system, the purposes of the
application of the mud and hydraulics are often common to each other. The hydraulics
system has many effects on the well. Therefore, the reasons for giving attention to
hydraulics are abundant. The more common reasons are as follows:
- Control sub-surface pressures,
- Provide a buoyancy effect to the drill string and casing,
- Minimize hole erosion due to the mud's washing action during movement,
- Remove cuttings from the well, clean the bit, and remove cuttings from below the bit,
- Increase penetration rate,
- Size surface equipment such as pumps,
- Control surge pressures created by lowering pipe into the well,
- Minimize well bore pressure reductions from swabbing when pulling pipe from
the well,
- Evaluate pressure increases in the well bore when circulating the mud,
- Maintain control of the well during kicks,
To get a clear picture of the factors building up the hydraulic system and their
connection, we have to differentiate them from each others at first. Through the separation
of the elements we can distinguish the purpose of each and check the cross-effects of the
linked parameters.
2.1 Standpipe Pressure
The total system pressure which is available in the well is called standpipe pressure; its
dimension is psi in the API nomenclature system and bar in the SI system. This pressure
is generated by the mud pumps and has to overcome all of the pressure losses of the
whole system. The standpipe pressure of the system depends on the following factors:
SPP = PSurface Equipment + PDrillstring + PAnnulus + PBit (1.equation)
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It is also shown in the following figure:
1. Figure Schematic drawing of Pressure Losses and Standpipe Pressure
The first three components is caused by the friction of the drilling fluid flowing through
the well, while the pressure drop through the bit is due to the sudden conversion of
pressure energy of drilling mud into kinetic energy. The value of standpipe pressure is one
of the basic points from which the design of the drilling process starts because all of the
further pressure conditions will depend on its value. The HP mud pumps’ capacity is the
most influential of the effecting parameters, but the standpipe pressure is also adjusted by
the inner diameter of the drill string, the design of the bottom hole assembly and the total
flow area (TFA) of the bit nozzles. The value of standpipe pressure is dependent of many
various factors and has its limitations for the minimum and maximum values of it. The
effecting parameters come from different systems of the drilling rig and the formations to
be penetrated, but their combined influence will determine the final value of standpipe
pressure. One of the influencing properties is the depth (length) of the well, which
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basically determines the length of drill string and annulus and due to this the space
available for drilling mud to flow, the deeper or longer the well is the more the standpipe
pressure to be applied. The next parameter is the inside diameter of the drill pipe which
defines the space inside the drill string, an increase in the diameter of the drill pipe will
become a decrease in standpipe pressure. The composition of the bottom hole assembly
also has effect on the magnitude of standpipe pressure, because the different build-ups
will lead to different inner diameters of the BHA. The total area of bit nozzles is one of the
most influential of the effecting parameters, because it will determine the available area
for drilling mud to flow through the drilling bit. With the increase of the TFA the standpipe
pressure can be lessen, while narrowing it will lead to an increased value of SPP. The
other highly influential parameter is the pumping rate, which has a very close relation with
standpipe pressure, due to the fact that it’s directly proportional to the pumping speed of
the mud. Drilling mud parameters also effects the SPP but the detailed overview of these
impacts will be presented in a later subchapter dedicated to drilling mud properties. The
minimum value for standpipe pressure is determined by the frictional pressure losses
developed in the well, which must be equalize by the SPP. The maximum value is usually
the pressure performance of the mud pump in its fully loaded status and rarely achieved
during normal operation of the pump. It must be noted, that practically the maximum
available SPP is limited by the maximum allowable surface pressure and by the formation
fracture gradient or pressure. The standpipe pressure can change in a broad range
between these two points and is adjusted to the optimum by different principles. One of
them is to develop a sufficiently great pressure drop at the drill bit which is a basic
requirement in reaching an adequate drilling performance. The usual ratio which is
needed for the acceptable performance is between 50-65 % pressure drop on the drilling
bit and 50-35% pressure drop in the surface equipment and by friction together. The other
aspect in managing the standpipe pressure is to not overload the mud pump. The usage
of high standpipe pressure can require the application of a mud pump capable of
developing higher pressure thus increasing the general investment cost, or can lead to the
overload of a damaged or old mud pump and the failure of the complete system.
2.2 Pumping/Liquid Rate
The liquid rate means the flowing speed of the drilling mud expressed in volume over
time dimension as gallon per minute (gpm) or liter per minute (lpm). The rate of the drilling
fluid is developed by the mud pumps at surface and is not affected by the other factors out
of the mud pumps performance. The pumping rate can be changed by the pumping speed
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(considering constant piston inside diameter and length) of the mud pumps and it is
directly proportional to it.
For triplex mud pumps the yield in gpm:
(2.equation)
While the management of pumping rate depends on only one factor, it influences many
different parameters and a key-element of the hydraulic system. It has serious impact on
the standpipe pressure of the system, because the rate of the flowing fluid will develop
and manage the pressure losses in the well. The increase in pumping rate will develop
elevated standpipe pressure and thus greater pressure drop at the bit, but at the same
time, it leads to increased frictional losses as well. Due to this effect the hydraulic drilling
performance parameters can be also adjusted by the flow rate, but the maximum
improvement is limited by the frictional losses of the system. After the maximum possible
improvement of the performance factors is reached, the further increase in pumping rate
will lead to decreased drilling performance but continued rise of friction losses. The
cleaning properties of the drilling fluids are also highly influenced by the rate of the drilling
mud. The proper up-flow velocity of the drill cuttings is a basic requirement for having the
correct hole cleaning properties, but the minimum and maximum value is defined by
limitations. The rate must be sufficiently high to provide such up-flow velocity of the drilling
mud inside the annulus where the drill cuttings are transported to the surface. The
pumping rate cannot reach the point where the annular velocity of the fluid flow reaches
the turbulent region, thus causing several serious problems. Between these two points the
pumping rate could be adjusted by the mud pump and positive influence can be done on
the drilling performance and hole cleaning parameters, but the parasitic pressure losses
must be monitored and kept under 50% of the standpipe pressure. The proper adjustment
and management of the pumping rate will be one of the basic tasks of optimization
process due to its primary importance and high impact on hydraulics. The calculation of
the correct rate for every section of the well is of utmost importance because all well
section has its special requirement towards pumping rate.
The last effecting factor related to pumping rate is the condition of the well and the
requirements of the currently drilled section. Due to the always changing nature of the well
conditions (different geological formations to be penetrated), pumping rate must be
corrected and optimized at all time to fulfill its role in the system. The conditions change
along the well depth as the drilling operation continues to progress which means that the
different sections of well require different pumping rates.
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The pumping rate must be adjusted to achieve the maximum available cleaning
properties of the drilling mud in case of drilling the top hole section considering the
wellbore stability and the very high volume of cuttings to be transported out of the well. To
maximize the cleaning properties of mud the drilling crew has to use the highest possible
flow rate available in this section without causing wellbore instability. In that case the
limiting parameter for the pumping rate will be the formation strength of the penetrated
formation near the surface. Excessive fluid velocity in the annulus can cause wash outs in
the unconsolidated near-to-surface formations, which can eventually lead to the collapse
of the well. In case of top hole section the pumping rate must be adjusted according to the
formation strength, but to maintain the cleaning effect at as high as possible level. The
deeper sections of the well require other treatment than the shallow ones. The formation
strength and the level of formation consolidation is not always an issue at lower depths,
but other kind of problems can arise. The minimum pumping rate has been established as
a rule of thumb that the fluid flow velocity in the annulus has to be as high as 0.60-0.65
m/s. The maximum value on the other hand is limited by the phenomena that turbulent
flow in the open hole section of the annulus must be avoided at all time due to its
damaging effect on the mud cake and wellbore wall. The third limiting effect on the
pumping rate can be the formation fracture gradient or the formation fracture pressure.
The fluid hydrostatic pressure inside the annulus balances the formation pressure of the
currently drilled section of the well. In case when these two values are relatively close to
each other, the pumping rate and thus the ECD must be monitored closely, and rate has
to be controlled in such manner that ECD does not overcome the formation fracture
pressure. In our recent days this so called “ECD management” got very high importance
in ERD wells where the horizontal drain can reach very frequently the 3-6 km length.
Since, the hydrostatic pressure is basically the same along the horizontal section but the
ECD is growing continuously due to growing length of the “frictional” section, keeping the
static and dynamic pressure of the mud between the formation and formation fracture
pressure is another challenge. It must be noted, that in case of deep water drilling other
type of problems can occur. Among others, the width of the “window” between the
formation and formation fracture pressure is getting narrower as the water depth is
deeper, because of the reduced overburden pressure of the formations below the sea
bed.
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2.3 Annular Fluid Velocity
When the drilling mud enters the annulus, its pressure energy inside the drill string is
transformed to kinetic energy when pumped through bit nozzles. The velocity thus gained
is used to clean the wellbore by transporting the drill cuttings to the surface. The required
up-flow velocity of the drilling mud is only develops when the sufficient amount of kinetic
energy is achieved through the bit nozzles, and it is directly related to the pumping rate. In
addition to pumping rate, the mud up-flow velocity inside the annulus is affected by
several other parameters of the well and the hydraulic system. The most basic one is the
measure of the annular space, the relation between the diameter of the open hole and the
outside diameter of the drill string and Bottom Hole Assembly. The average annular
velocity in ft/sec is calculated by the following equation:
(3.equation)
The size of the annulus determines the space available for fluid flow and its value is
inversely proportional to the fluid velocity. With increasing BHA and drill string OD, the
flow area of the annulus will decrease thus increasing the flowing velocity. Because the
difference in annulus ID and BHA (drill pipe) OD is relatively small – especially in the small
diameter open hole section – the flow velocity inside the annulus must always be checked
for turbulent flow by the driller. The critical velocity for laminar flow in ft/min is calculated
by the following equation:
(4.equation)
The development of the turbulent flow in the drilling mud is depend on the diameter
difference mentioned previously, so the velocity in the annulus has to be recalculated
every time when a change in the drill string or BHA design is applied. The effect of
pumping rate has been already mentioned above, it is directly proportional to the
developed flowing velocity but the relation between the drilling mud velocity and the
pumping rate is highly complex. To reach the sufficient cleaning properties of the system
the velocity of the drilling mud flowing inside the annulus must reach the 0.60-0.65 m/s
limit. The improvement of the fluid velocity also defines the increase of the parasitic
pressure losses inside the drill string and the annulus. This effect is not severe under
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normal conditions, but becomes highly problematic in case of deep, small diameter or
ERD wells. The combined effect of greater depth and less flow area inside the annulus will
determine the minimum and maximum available pumping rate (pressure), thus limits the
achievable annular fluid velocity.
The critical flow rate for laminar flow is calculated by the following equation:
(5.equation)
The limiting values of fluid velocity in annulus are the sufficient velocity for hole
cleaning as minimum and the velocity of turbulent flow as maximum (keeping in mind all
the time that the ECD with cuttings cannot exceed the fracture pressure of the weakest
formation of the open hole). Between these two values the annular velocity can change in
a broad range and usually determined by the calculated pumping rate and flowing area
conditions.
2.4 Pressure Losses
The pressure conditions in the well are determined by the ratio of available standpipe
pressure and the losses inside the system, which has a significant impact on the drilling
performance and affected by several components of the hydraulic system. The total
pressure loss inside a well is build up from many factors and each of them has influence
on the hydraulics of the well. The three main components of the total system pressure
loss are the pressure drop inside the surface equipment, the frictional pressure loss in the
drill string and the annulus and the pressure drop at the drill bit. The sum of these
components cannot overcome the available standpipe pressure because it would mean
that the well fluid and the drilling mud are not able to reach the surface. The rate of the
frictional loss and the drop at the drilling bit is a decisive factor that determines the drilling
performance, and as a general rule the pressure loss at the bit has to make up at least
50% of the total pressure drop. This proportion will ensure that the developed pressure at
the bit provide the sufficient amount of energy that can be transformed into a high kinetic
energy, thus the high velocity jet of drilling mud will form through the bit nozzles. The total
system pressure loss is affected by many properties of the hydraulic system; the most
basic one of these components is the standpipe pressure. The standpipe pressure has a
direct impact on the pressure conditions of the well; the higher the available standpipe
pressure the greater will be the pressure loss in the well and in the surface equipment.
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The next affecting component of the hydraulics is the fluid or pumping rate, which has a
high impact in the adjustment of pressure losses. The pressure losses are dynamically
modified by and vary according to the pumping rate, due to the fact that it changes many
times during the drilling operation and has a direct effect on them. The management of the
pumping rate and the pressure losses is linked with each other, so the influence on the
pressure losses of every modification done in the pumping rate must be checked and
monitored. In cases when the pumping rate must be raised, the parasitic pressure drop
must be recalculated and checked not to overcome the pressure drop at the bit, thus
avoiding the decrease in drilling performance. The pressure drop in the surface equipment
is related to the composition of the surface components and pipes, the value of this loss is
less than 10 bar or 145 psi in most of the cases, but increases with pumping rate. The
frictional pressure losses are mostly depend on the pumping rate, but the roughness of
the inside surfaces which are in contact with the drilling fluid is also a significant factor.
The roughness of drill pipes and casing are given by the manufacturer and cannot be
changed, so the companies use the pipes with the smoothest surface available. The
roughness of the pipes and the annulus are represented as friction factor in the
calculations and their value is depends on the Reynolds-number.
If Reynolds number is less than or equal to 2100:
(6.equation)
(7.equation)
If Reynolds number is greater than 2100:
(8.equation)
(9.equation)
14
The drill string and annular pressure loss is calculated by the following equations:
(10.equation)
(11.equation)
The pressure drop at the drilling bit is caused by sudden decrease in flow area when
the drilling mud reaches the bit nozzles. The calculation for bit pressure loss:
(12.equation)
Its magnitude is the highest of all, due to the phenomena that pressure loss through the
bit is at least half of the total system pressure loss. To maintain this 50% drop in pressure,
the total flow area of the bit nozzles must be calculated correctly and the pumping rate
must be adjusted by the given properties. While the rate can be modified freely during the
operation, the TFA is pre-calculated and constant for a given section of the well
(supposing to use the same type of drill bit all the way). The selected nozzles will
determine the flow area, which will regulate the available pumping rate range, thus adjust
the pressure loss through the bit. To develop the proper pressure drop through the bit is
highly important to avoid any decrease in the drilling performance. The developed velocity
of the drilling mud enhance the work of the drilling bit by the cutting the formation with the
fluid jet, helps the cooling of the bit, prevents regrinding of cuttings and is directly
proportional to the pressure drop through the nozzles. In the optimization of the hydraulic
system, the management of the system pressure loss is a major factor which can change
between very broad ranges, depending on the available standpipe pressure, usable
pumping rate and the bit nozzles applied for different sections of the well.
15
2.5 Total Flow Area
The total flow area or TFA is the cumulative sum of the drill bit nozzles open area,
through which the drilling mud enters into the bottom of the well bore than into the annulus
between drill string and open hole (casing). The dimension of it is in2 or cm2 and the only
component which determines the value of TFA is the size of the selected bit nozzles given
in 1/32 inches. While affected by only one component of the system, the TFA has impact
on all of the hydraulic factors which are connected to the hydraulic optimization of the well.
Due to this property of the TFA, the correct calculation and selection of the necessary bit
nozzles is highly important and must be included in the design of the well.
The flow area of the nozzles is calculated by the next equation:
(13.equation)
The improper selection of the bit nozzles can lead to severe failures in safety and
drilling performance, not to mention the financial drawbacks and the increased non
productive time. Correct calculation of the TFA has primary importance because its value
cannot be changed freely during the drilling operation, given that the drill bit nozzles are
located at the low end of the bottom hole assembly. Starting from the early design of the
well, the calculations for the total flow area is closely related to the selection of pumping
rate, the determination of the pressure losses and the modeling of hydraulic performance
parameters. All of these components along with the TFA changes according to the depth
of the well and the drilled formations, which means that the adjustment of these properties
must be repeated for each section of the well. This complex relation of the total flow area
to the previously mentioned parameters makes the TFA one of the key factors in hydraulic
optimization. The lower and upper limits for the value of TFA is determined by pre-
described parameters, which means that the drill bit nozzles diameter will change
depending on the desired property of the system. The next determining factor is the
pressure losses of the system, more precisely the proportion of parasitic pressure losses
and the pressure drop through the nozzles. The TFA must be selected to enable the
development of the proper pressure drop at the bit, to ensure the cutting work of drilling
mud, thus effectively enhancing the drilling performance of the bit. Drilling performance
indicators, bit impact force, bit hydraulic power, jet velocity and HSI, are mostly adjusted
by the TFA, which means that the hydraulic performance of the system can be directly
managed by the nozzle sizes. The enhancement of the hydraulic performance is done by
16
optimizing these properties, but in most cases only one of them can be set to its optimum
depending on the pressure conditions inside the well.
2.6 Hydraulic Performance
The performance of the drilling operation is expressed by the ROP which means the
rate of penetration, but it’s just an indicator of the different contracted performance
components. The efficiency of the drilling rig can be characterized by the mechanical
performance of the drilling bit and the hydraulic and cutting performance of the drilling
mud on the formation. While the mechanical performance of the drilling bit is affected by
the properties of the formation, drilling equipment and the cleaning features of the whole
system the hydraulic performance of the mud is related to the hydraulic system design
and controlled by the drilling crew. These two components build up the ROP and their
individual effect on it is equally high, which means that the correct design of the hydraulic
system is greatly important. The hydraulic work of the mud is done by the high velocity
fluid jet which helps to cut the formation surface and makes cracks in the solid rock body,
allowing the bit cones or PDC bit to further break the formation. To attain such a high fluid
velocity, the previously mentioned pumping rate and TFA must be monitored and adjusted
in contact with each other. The hydraulic performance of the drilling bit is described by
different calculated components; these components are:
- Bit Impact Force
- Bit Hydraulic Power
- Bit Nozzle Velocity
- HSI or Hydraulic Power per Square Inch
The values of these properties are determined by the pressure drop at the bit which
depends on different system elements described before. The values of these components
are highly connected with each other and their management related to the same parts of
the hydraulic system. The main task of the drilling crew is to ensure the safety of the well
and the rig and to monitor while optimizing these performance indicators through the
whole drilling operation. The hydraulic performance of the bit depends on all of the
previously mentioned hydraulic factors. The pressure developed by the HP mud pumps
will determine the usable amount of pressure in the well, thus affecting the achievable
pressure drop at the bit. Increase in the available pressure can mean greater bit pressure
loss, and this way improvement in the hydraulic performance factors. The pumping rate
will also affect the pressure losses and through that determine the jet velocity and the
developed hydraulic forces and powers. Higher pumping rate leads to improved pressure
drop at the bit, higher developed fluid velocity and greater impact force and hydraulic
17
power. The distribution of pressure losses will highly affect the factors introduced in this
section, just like the total flow is which has an equally great impact on them. The effect of
flow rate and pressure conditions on the calculations is showed by 14. and 15. Equation:
(14.equation)
(15.equation)
(16.equation)
(17.equation)
Depending on the rate of pressure drops in system, the crew tries to maximize different
hydraulic performance factor. In case when the achieved pressure drop at the bit reaches
65% or more of the total system pressure loss, the HSI is the main performance factor
which is optimized, while if the rate between the parasitic and bit pressure drop is 50-50 or
less, then the bit impact force is the key factor. Based on the applied flow rate and the
currently drilled section diameter it could be stated that well hydraulics are optimized for
bit impact force when higher flow rate is used and the hole diameter is large, while the bit
hydraulic power is the main target when the flow rate is lower and the hole diameter is
smaller. In addition to that, when one of these two parameters is optimized, the other one
is also close to its maximum. The 2.Figure shows the connection of bit impact force and
hydraulic power to flow rate. The total flow area of the bit nozzles has serious effect on the
jet velocity and the impact forces. Increasing the TFA leads to reduced pressure drop at
the bit, thus results in lowered jet velocity and developed forces, while constricting it will
mean improved hydraulic performance. The general field practice gives target ranges for
the different performance parameters. In case of water based mud the minimum
acceptable jet velocity is 100 m/s (328 ft/s), which ensures the proper cooling of the
drilling bit, prevents the re-grinding of the cuttings and assists the drilling work of the bit.
For HSI, the generally accepted range is between 2.5-5 HP/in2, where the drilling mud
develops adequate hydraulic power on the formation and provides sufficient cutting
removal. To maintain a decent drilling performance during the drilling operation is of
primary importance, but very hard to achieve mainly because of the cross-link effects
between the many different parameters.
18
2. Figure Effect of Flow Rate on Pressure Loss and Bit Hydraulics (MI Manual)
2.7 Finishing Thoughts
Now, that the hydraulic components of the drilling system have been introduced in
details, the deeply interconnected system of well hydraulics can be overviewed and
analyzed. While the examinations of the individual factors are easier and more
expressive, in the practice they never act separately from each other which means that in
the field the engineer always have to clearly understand the thorough relation between
them. Without the required knowledge on these factors the correct management of the
well cannot be done, which leads to safety problems, failures in the drilling equipment and
can even lead to catastrophic results. Because the effect of the components depend on
each other very much, any change done on one of them will have an impact on the whole
system, thus they have to be monitored together. Before any kind of optimization will be
done on the factors, the first and most important challenge what the crew must overcome
is to find the balance between the ends. This point is reached when the required safety is
achieved, the proper hole cleaning requirements are met and a decent hydraulic drilling
performance is attained. From that point the crew can decide that which parameter will be
the target of the optimization process, based on the actual condition of the well, the
19
properties of the surroundings, the current drilling equipment and rig components and the
limitations. As previously mentioned, the limitations can come from every part of the
drilling system, including the environment, the appliances, and drilling fluid. Ignoring any
of the limitations can lead to catastrophic results, because they define the weakest points
of the system, thus problems will most likely arise at these points. When the parameters
undergo an optimization procedure, the foremost task is to reach the required safety of the
well, and achieve the proper hole cleaning properties. The optimization of the hydraulic
performance can only start when these two requirements are accordingly fulfilled. In most
cases, maintaining the safety of the well results in decreased drilling performance, while
drilling operations focusing solely on performance tends to have safety and well control
problems. The previously described parameters and the drilling mud properties together
build-up the hydraulics of the well, and their influence on the system are nearly the same.
The hydraulic optimization of the well must always include the correct management of the
drilling mud parameters, because most calculation of the hydraulic factors contains
different mud properties, thus highly affecting the system. The next section of the thesis
will cover these important mud parameters and their effect on the well hydraulics.
20
3. Drilling Mud Parameters
The hydraulic system of a well can divided into two major part, the physical
composition of equipments, including surface pumps, drill string and casing string, bottom
hole assembly, and the drilling mud system. The importance and effect of the physical
system has been highlighted in the previous section of the thesis, but the impacts of the
mud properties on the well hydraulics are haven’t been introduced yet. The final value of
the hydraulic factors will always depend on the joint work of the surface and down hole
equipment and the drilling mud properties. Due to this fact, the proper management of the
drilling mud is a highly important task of the crew, the well control requirements must be
fulfilled at all time and sufficient hole cleaning is of primary importance as well. This
chapter will present a detailed overview of the drilling mud parameters and their influence
on the hydraulic system, as well as the related calculations. While the drilling mud has
many functions and parameters which are all highly important through the whole drilling
process, the thesis will focus on the properties that are directly connected to the well
hydraulics. The complete overview of all mud parameters would be unnecessary, since
properties like pH and alkalinity has only an indirect function to hydraulics. At last, the
thesis will introduce the water based mud properties, because the drilling crew always
works with this type of mud at wells in Hungary due to legal regulations.
3.1 Mud Weight
The weight or density of the drilling mud is a basic key factor in well drilling from the
start of the drilling process till the completion of the well. It is a dimensionless number in
the SI nomenclature as specific gravity, SG and ppg (pound per gallon) in the API system.
The drilling mud is the balancing material between the surface pressure and the formation
pressure and due to this its value must be directly proportional to the pressure of the
surrounding rock body. The prevention of any kind of well control problem starts with the
proper management of the mud weight, which means that the hydrostatic pressure of the
fluid column in the annulus must overcome the formation pressure, but have to be less
than the formation strength (fracturing) pressure. As the well deepens these bounds will
get closer to each other, limiting the range where the density of the drilling mud can be
changed, thus at these elevated depths the proper adjustment of the mud weight
becomes highly difficult. The weight of drilling mud has a major role in hydraulics as the
basic parameter which influences the pressure conditions inside the well and thus
affecting the optimization process from the very beginning. The incorrect selection of the
mud weight results in serious problems, if the annular hydrostatic pressure is less than the
21
formation pressure a kick can happen and influx from the surroundings can enter the well.
If that happens at the target formation and the mud weight is kept at the insufficiently high
value then the situation can even evolve to a blowout. On the other hand, if it overcome
the formation strength gradient the current open hole section can break and leakage or
fluid loss can take place. The fluid level dropping down, thus the hydrostatic pressure is
decreasing; this event can lead also to fluid influx and finally to a blowout. The hydrostatic
pressure of the annular drilling fluid-column is directly proportional to the mud weight, as
well as the standpipe pressure. Development and management of mud density is done by
weighting materials, usually solid additives that have high density and thus increases the
weight of the fluid selected for drilling(fresh-water, synthetic base or oil). Reducing the
weight can only done by adding mix-fluid (un-weighted premix or base fluid) to the mud,
thus decreasing the weighting material concentration in it. The most common weighting
agent is the barite, a barium sulfate mineral, with a relatively high specific gravity
(SG=4.2), capable of increasing the density of the mud up to SG=2-2.2 or 16.6-18.3 in
ppg. The low cost and wide range of usability makes barite the most frequently used
weighting material, its only drawback is the solid content increasing effect when elevated
densities are required. Excessive amount of solid content can deteriorate the rheological
properties of the drilling mud and thus affect the hydraulic parameters and factors of the
whole system and increase the mechanical wear on the drilling equipment. Another
common weighting material is calcium carbonate (CaCO3), which has lower specific
gravity (SG=2.8) than barite, but its use provides additional benefits as a bridging agent
and seepage control agent. Also, it is frequently used to build Drill-In fluids in pay zone
due to its property that it can be dissolved by acidizing job while completion. The practice
in Hungary uses salts like NaCl and KCl as weighting agents when relatively low mud
density (less than SG=1.2 or 9.99 ppg) is required. These additives have and additional
inhibitive property which is a highly important factor when the well contains reactive shale
formations. It must be noted that in recent days the usage of different formates (sodium,
potassium, cesium) is coming into the general practice more and more, especially in
HTHP environments and extended reach drilling. They can be applied in wide range of SG
from 1.2 to 2.3. Their advantages (excluding their relative high price) are primarily the low
solid content (no sag), improved ECD, and high compatibility with reservoir fluids. They
can be used for drilling, completion, workover and fraccing fluids.
3.2 Rheology and Viscosity
The flowing properties of the drilling mud are indicated by the rheological parameters,
including different types of viscosities, yield point and gel strength. From the numerous
22
features of drilling mud, rheological parameters have the most serious impact on well
hydraulics. Due to non-Newtonian, tixotropic state of drilling fluids, the functions and the
hydraulic factors will entirely depend on the rheology of the mud. The difference between
the behavior of Newtonian and non-Newtonian is represented in the next figure:
3. Figure Flow Behavior difference between Newtonian Fluid and Typical Mud (MI Manual)
The related functions are the ability to carry the cuttings from the bottom to the surface;
the capability to suspend the cuttings when drilling is stopped, transferring hydraulic
power to the bottom and keeping wellbore stability. In case these requirements are not
fulfilled, the crew will experience serious hole problems and the drilling operation will
surely end in failure. The rheology of the mud depends on multiple components of the
system, but the calculations and correlations are determined by the chosen rheological
model. The petroleum industry uses three models to characterize the rheological
properties of drilling fluids, the Bingham-plastic model, the Power-Law model and the
Herschel-Bulkley model. The difference between them can be checked in the 4. Figure.
While all of the three model try to describe the behavior of the mud, the Herschel-Bulkley
model can establish the most reliable and realistic description of the flow behavior of the
actual mud. It’s related to the basic conception of the model, which allows the use of yield
point like the Bingham-plastic model, and uses a curve function to describe the stress-
speed relation like the Power-Law model. The viscosity parameters, gel strengths and
yield point are calculated based on this model and are all part of the optimization
procedure. The viscosity is the resistance of the drilling mud against flowing (inside
friction) expressed in unit centipoise or pascal secundum (Pa*s), and has several forms
23
like apparent, effective, plastic viscosity, Funnel viscosity, low shear rate viscosity and
yield point.
4. Figure Comparison of the different rheological models (MI Manual)
Yield point represents the ability of mud to effectively transport the drill cuttings from
the well bottom to the surface, which is a basic requirement of the drilling mud. Yield point
is the initial stress of the fluid at zero shearing speed which gives the binding force
between the mud particles. It’s an indicator of the carrying capacity of the mud and one of
the basic factors which highly affects the pressure losses inside the system. The yield
point of mud is calculated by 18.equation, and expressed in the units of lb/100ft2 in the API
system.
300-PV (18.equation)
Yield point depends on various parameter of the whole system, the temperature of the
well and the contaminant content of the fluid, but such an important property of the mud
that must be monitored at all time due to its direct impact on frictional pressure loss, ECD
and hole cleaning efficiency. Elevated temperature of the well or high solid content of the
mud results in an increased value of yield point, which is directly followed by the increase
in pressure loss by friction and equivalent circulating density. While the rise in yield point
also positively affects the cutting lifting ability of the drilling mud, the harmful
disadvantages developed this way have a significant magnitude, and because of that the
general practice is to maintain the YP at a safe and pre-calculated value. The plastic
viscosity of the mud is another basic parameter which indicates the resistance of fluid to
flow, calculated by 19.equation and expressed in cP.
600-300 (19.equation)
24
The PV is always measured and monitored in connection with the YP and a key
parameter to hydraulic optimization, due to its fundamental importance as a mud property.
The YP and PV are usually the factors, other than FANN readings, that optimization
software are containing and using for mud and hydraulic related calculations when the
Bingham-plastic model is used. In case when Power Law or Herschel-Bulkley model is
applied, the yield point and plastic viscosity parameters are replaced by the “n” and “K”
factors. Although the value of the n and K factors is depend on the FANN readings of the
mud just as YP and PV, their calculation is entirely different (20. and 21.equation) and the
property described by them is also not similar.
(20.equation)
The n factor stands for the flow index, a dimensionless parameter which defines that
the given fluid is pseudoplastic (n<1), Newtonian (n=1) or dilatants (n>1), and also affects
the flow profile of the mud in the laminar state which is represented in the following
figures.
5. Figure The effect of "n" factor on velocity and flow profile (MI Manual)
25
Drilling mud used in the practice always has an n value less than 1, but shape of the
flow profile will depend on the exact value between 0.1 and 0.9, in other words the non-
Newtonian nature of mud. As the rate of the n factor approximate zero, the flow profile will
flatten and resemble the plug flow, while if it’s near to one the profile will get similar to the
Newtonian fluid shape. The value of n will also define the shear rate-stress relation of the
fluid and through that the cleaning efficiency of the mud can be modified as well. Lower n
index will result in preferable cleaning properties of mud and also render the shear rate-
stress relationship curve flatter, on the other hand higher n index will develop a drilling
mud with lower cleaning efficiency and high evolved stress over rate. The K index is a
consistency factor which represents the mud’s suspension ability and affects the hole
cleaning properties as well.
(21.equation)
The K index is expressed in Pa*sn or P*sn-1 units and practically a viscosity value
related to a shearing speed, the higher the K index is the higher the ability of mud to
suspend cuttings and transport them to the surface. While the crew always tries to lessen
the non productive time of the drilling process, at certain times the operation have to be
stopped, and due to this fact the rotation of the drill string and BHA and the pumping is
also halted. After situation like this, the restarting of the pumping and rotation results in
elevated stress expressed onto the formation by the mud. Also, the same effect occurs
during tripping (surge/swab). This starting stress is the Gel strength, which is the needed
stress to “break” the mud and set it into rotational motion, and is a highly important factor
which must be monitored at all time. Excessive value of the gels can lead to the breaking
of the formation when the operation is restarted, causing partial or total loss of drilling mud
and resulting in failure of the drilling operation. We differentiate three types of gel strength
based on the elapsed time from the operation stop, ten second, ten minute and thirty
minute gel strength. This three stress parameter is equally important and must be
monitored and checked in regular intervals at the rig site. The ten second gel strength is
highly relevant, because this index will represent the ability of mud to form a solid
suspension and prevent the cuttings from falling to the hole bottom and settle down. If the
10 second gel strength is not high enough means that the mud does not have sufficient
suspension ability, so the transported cuttings will settle down on the well bottom and form
a cutting bed, which can cause serious stuck pipe situations and severe problems to the
crew even leading to well control situation. Due to that the 10 sec gel strength of drilling
mud must be as high as possible to ensure the proper establishment of a decent mud
26
suspension. The ten minute and thirty minute gels are higher than the ten second, but the
difference between them must be low and have to be maintained instead of a linear rise.
When the 10 sec gel strength is adequate and develops correctly the generated
suspension will halt the falling of the cuttings and thus fulfill the requirement of this
parameter. The additives of mud however will harden the mud further, which can be
clearly checked on the ten and thirty minute gels. If this hardening process does not stops
a few minutes after that the operation has stopped, the drilling mud can reach gel strength
so high, that only a very high starting stress can break the fluid which can also damage
the formation, the equipment or both. The drilling industry calls this developed state as
progressive gel. This means that the 10 min and 30 min gels must be close to each other
in value and mustn’t have a high difference compared to the 10 sec gel strength. These
requirements ensure that the proper solution of mud which has been developed after a
few minutes does not harden further and any damage to the formation or the rig
equipment is prevented. The importance of the introduced rheological parameters is
clearly represented in this section and their role in the hydraulic system is also highlighted,
but what affects them is remained to be stated. Drilling mud parameters can be modified
by several factors, the well pressure and temperature, the formation and cuttings
properties, and the mud additives. Rheology is mostly modified by viscosity control
materials such as viscosifiers, flocculants and thinners, but drilling mud additives have
impact on additional parameters besides their target property. It practically means that
many mud additives can change the rheological parameters, such as shale inhibitors, but
their influence can only come forth when the corresponding circumstances arises. Outside
the mud additives, rheology of the drilling mud can be modified by the drilled formations,
especially shale layers. The solids content is another highly important parameter, which
also has a great impact on the behavior of the drilling mud that will be covered in a
different subchapter of this section. It has to be stated is that excessive amount of solid
content of the mud has detrimental effect on the rheology parameters, because viscosity
and yield point of mud rises with the solid content. Temperature stabilizers and biocides
prevent the different mud additives like viscosifiers from breakdown, but elevated well
temperature can forbid the usage of water based mud due to the hydraulic drawbacks and
difficult management. It can be seen that the correct management of mud rheology is
depends on the additives, the well surroundings and hole conditions. Inside the limitations
by these parameters, the rheology of the mud can be changed in a broad range, and its
value depends on the hole cleaning requirements given by the crew. It has a close
connection to the well hydraulics, and the viscosity parameters are always part of the
hydraulic optimization calculation. Incorrect management of these properties can lead to
lost hydraulic power, excessive hydraulic stress expressed both on the equipment and the
27
formation and serious non-hydraulic problems. As a general rule, the viscosity of the mud
should be kept usually as low as possible, meanwhile the 6 rpm reading should be high
enough (1-1.4 x hole diameter) and the 3 rpm reading should be close to the 6 rpm
reading.
3.3 Solid content
The drilling mud is a complex system, made by the mixing of many different additives
which are usually solids. This makes the mud such a fluid, which always has a given solid
content even without any cuttings in it, and thus it must be monitored and measured
through the entire drilling process. What makes the solid content of the mud even more
essential is the feature that high volumes of solid raises the rousing stresses in the well,
the mechanical wear of the equipment grows and the frictional pressure drop of the
system increases. Also, the solid content (especially the LGS builds up) has detrimental
effect on mud cake quality making it more permeable, more thick and rigid. Excessive
amounts of drill cuttings extend the value of ECD and can also cause stuck pipe
problems. The disadvantageous properties that are listed above can result in the failure of
the entire drilling operation which must be avoided at all cost. For this, the correct
management of the solid content has high demand during the drilling process which
includes the measurement, monitoring and conditioning of the drilling mud. As it was
mentioned before, drilling mud has an initial solid content, even before the actual drilling
starts, and it keeps increasing as drill cuttings builds up the mud. For that reason, solid
content is separated into two groups as high gravity and low gravity solids. This
differentiation is necessary to distinguish the mud additives, shale content and drill
cuttings, which are belongs to the low gravity group (LGS), from the solid weighting
materials which are part of the high gravity solids (HGS). The industrial practice limits the
low gravity solid content at or below five percent, to prevent the detrimental influences of
shale and drill cuttings affecting the rheology of the mud. The high gravity solid content of
the mud is generated by the weighting material concentration, which can be detrimental if
the weighting agent is barite or other solid material and the required mud weight is above
SG=2 (16.6 ppg) or above. In these cases the weighting material extremely raises the
solid content of the mud, thus increasing the mechanical wear of the equipment (can even
cause washouts), raising the ECD of the mud and increasing frictional pressure loss. The
last portion of the solid particles in the drilling mud is the soluble parts like salt, which can
cause numerous problems to the drilling crew if solutes into the mud. While the cuttings
(larger than 5 microns) or the unnecessary amount of weighting materials can be
subtracted from the mud by the solid control system, the soluble parts and particles
28
smaller than 5 microns remain in there and can only diminished by dumping a part of the
mud and diluting the remaining portion. High solid content, especially low gravity solid,
can also deteriorate the quality and thickness of mud cake, causing high potential to get
differential sticking. Furthermore, increased solid content of the mud raise the evolved
swab and surge pressures, which can cause serious troubles in case of tripping
(RIH/POOH). While it has impact on many parameters of the drilling system, solid content
can be modified by numerous part of the system. As it is already mentioned, drilling mud
has an initial solid content which increases with the drill cuttings. The cuttings
concentration is highly depend on the rate of penetration (ROP), which means that
elevated drilling speed will result in extended cutting content of mud. The condition of the
open hole section surface is another highly important parameter, because unconsolidated
formations and layers prone to collapse can raise the solid content of mud immensely if
the required conditions are met. This could be the result of a poor mud cake or
inappropriate filtration, inadequate inhibition of the mud, wrongly determined (too high)
pumping rate or the properties of the formation itself. The hole cleaning efficiency can
seriously affect solid content of mud, thus inefficient cleaning parameters leads to
increased amount of cuttings. The complex connection of solid content to the whole
drilling process makes the parameter highly important and major part of the hydraulic
optimization process. The effects of modifications done to the hydraulic system must be
checked together with the solid content of the mud, to avoid any of the previously
mentioned matters. Optimization software contains formula for the cuttings volume and
bed height calculations and these properties have the same importance as flow rate in the
software.
3.4 Equivalent Circulating Density
The density of the drilling mud develops the hydrostatic pressure of the mud column in
the well, thus balancing the formation pressure of the different layers. Weighting materials,
mud additives and drill cuttings are the modifiers and the parts that develop mud weight.
However, the practical density of the drilling mud is more than the value measured at the
surface and depends on other parameters as well, due to well depth dependency of
density. This greater value is called equivalent circulating density or ECD, which contains
the effect of true vertical depth of the well and the frictional pressure loss (22.equation).
(22.equation)
29
Because of that, all parameters which are related to density like stresses and pressure
conditions must be calculated with the ECD to achieve correct and accurate data. It is of
primary importance because the incorrect management of the ECD can result in fracturing
of the formations if its value is too high or influx from the layers if not sufficiently high.
Among normal conditions and in case of vertical wells the ECD of the mud does not
significantly differ from the basic mud weight in case of vertical wells; it is rather affected
when the well path contains a significantly long horizontal section (Extended Reach
Drilling or ERD). On the other hand, the change of ECD can also cause these kinds of
matters if the difference between the pore pressure and the fracture gradient of the
formation is relatively small. Due to the included effect of the annular pressure loss, ECD
of the mud can elevate decently if the drill cutting and solid content of the fluid rises and
the annular flowing speed is high as well. The equivalent circulating density is a major
property of the hydraulic system which is calculated and monitored through the entire
drilling process.
3.5 Finishing Thoughts
The introduced mud parameters and the previously overviewed hydraulic factors build
up the complete hydraulic system together. The most essential task of hydraulic
optimization is to correctly manage the connected work of these two systems. Without the
sufficient balance between the properties, safety requirements of the operation can be
unperformed; the rig and well components may be damaged, reduce in drilling
performance can take place and even well control problems can arise. The optimization
process of hydraulics contains calculations for both the hydraulic factors and the mud
parameters. The engineer responsible for the optimization process must understand the
connection of the properties and dependency of them on each other. Engineers in today's
practice uses software developed by companies related to the petroleum industry, which
greatly facilitate their work. These software contain the needed calculations and
connected factors that are necessary to compute the required data. Beside the
optimization software, engineers have their optimization method which consists of
different steps for the optimization process. I used such a method during my personal
work and used an optimization software mentioned above which is presented in the
following section of the thesis. The overview of the methodology and the formulas is
necessary in order to understand the detailed presentation of the actual well parameters
which I worked with.
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4. Steps of the optimization process
The hydraulic optimization of an oil well contains numerous tasks linked together to
achieve the best possible solution for all requirements of the well and the drilling process.
The order of tasks is highly important to ensure that all the sufficient factors are taken into
consideration and none of the limitations are neglected. The optimization of hydraulics can
be done appropriately this way and all of the possible errors and problems can be
prevented. This chapter introduces the steps and gives a detailed explanation of the
process.
Before the responsible engineer can begin any kind of optimization, vast amount of
required data must be gathered and checked about the formation. When the well path is
planned, well structure design is done, initial mud parameters are chosen and the
adequate BHA is selected the optimization process can be started. The first task of the
process is to check the lower and upper limitations of the rig and formation to see the
available and usable system pressure. This must be checked at every new section of the
well to prevent any kind error in the drilling process or even the complete failure of it. The
following steps depend on the currently drilled section of the well, as the layers and well
conditions are changing and the hole require different treatment. The next task is to
analyze the limitations on flow or pumping rate and check the window between the
minimum and maximum values. In that section of the optimization the flow rate must be
checked for numerous factors, and depending on the currently drilled section and layers
the pumping rate can be changed in a wide range. Achieving a satisfactory hole cleaning
is of primary importance and due to that this is the first minimum limit which is defined.
The second is the flow rate of the adequate annular flowing velocity which must be also
checked for turbulent flow to avoid any damage to the open hole section of the well and
thus defines one the maximum limits of the flow rate. These two values are the most
significant in the early period of the optimization, because they define the most basic
needs of the well. Other properties of the well determine further limit values of pumping
rate which have to be part of the optimization process. The performance of the surface
mud pump must be taken into consideration, which means that the highest reachable
pumping rate defines another maximum value of the flow rate. This value in most case are
so great that the well would be damaged before this flow rate is reached so the surface
pump performance practically never limits the operation. The following condition which
must be checked is the ratio of the frictional pressure losses to the total available system
pressure. Another upper border of the flow rate window is where the parasitic pressure
loss would be equal to the total hydraulics system pressure. It is highly important to
monitor that limitation because the performance of the hydraulic system is depends on the
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pressure drop distribution severely. This upper border value of the flow rate is such high
that it's never really achieved during a practical drilling operation, but knowing it assist the
optimization of the hydraulic performance factors greatly. The next step is to define the
flow rate when the cutting loaded ECD of the mud overcome the fracture gradient of the
formation. It's highly important to always monitor this parameter, thus prevent any kind of
damage to the formation. These limitations of the flow rate develop a window in the
values, in which the crew can change the pump rate without risking the safety or
performance of the well. Depending on the properties of the currently drilled section and
the rig equipment this window can be either wide or narrow, but it generally narrows in the
deeper, smaller diameter sections of the well. After the flow rate window is calculated the
responsible engineer has the range of rates where the hole cleaning properties are
adequate but the hydraulic performance factors are haven't been optimized yet. The
following steps of the optimization process focus on the enhancement of the hydraulic
performance of the well, through the selection of the proper bit nozzles. The defined
limitations of the pump rate have been calculated with the use of an initially selected set of
bit nozzles. While the proper hole cleaning have been ensured, the hydraulic performance
factors can still be developed by adjusting the pressure drop on the bit and the TFA. The
hydraulic performance of the well can be characterized by four related factor, the bit
impact force, bit hydraulic power, bit nozzle velocity and HSI. From that point the engineer
can choose from different solutions for the optimization of the hydraulic performance
considering different aspects of the drilling process. The usage of lower flow rate and a
set of bit nozzles with smaller TFA can be just as effective as the application of higher rate
with nozzles of bigger diameter. The selection can be based on numerous properties,
achieving the highest cleaning properties, attaining the best hydraulic performance,
lessening the stress on the system equipments to the minimum or establish the correct
balance between them. Having a balanced hydraulic system is the most advantageous
from all due to having a decent value of every property of the system. However, choosing
to optimize the hydraulics on performance or on well cleaning properties can provide
significant benefits under certain circumstances. In the upper sections of the well when
usually unconsolidated formations are drilled through, the optimization process focuses on
solely the hole cleaning efficiency. The flow rate is selected to be as high as possible, but
in such level that the possible wash-out of the layers are avoided thus any damage to the
near-surface formations are prevented. The cutting load of the mud usually is highest in
that section of the well, which requires the highest possible well cleaning properties and
hence the neglecting of hydraulic performance. As the well deepens, the process focuses
more on the hydraulic performance and the hole cleaning parameters are kept on a
decent level. These intermediate sections are relatively long (especially compared to the
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first section of the well), thus the optimization of drilling performance is highly needed to
time-effectively drill through them. The ECD management of the intermediate sections are
also of primary importance because the properly controlled ECD of the mud ensures the
safety of the well. In the deepest section of the well the primary target of the hydraulic
optimization is the safe penetration of the segments, particularly in case of ultra deep and
ERD wells with long horizontal section. In these sections the formation pressure and
formation fracture pressure are usually close to each other, thus the enhancement of the
hydraulic performance factors becomes highly difficult or even impossible. The most
important aspect is to keep the safety of the well by keeping the ECD in the window
between the formation and fracture pressure. The correct management of ECD can be
highly challenging in these sections and requires the complete understanding of the well
hydraulics. The sectional preferences can be seen on 6.Figure.
6. Figure Figure General well hydraulic optimization preferences
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Although the general practice described previously can be applied to every well, each
drilling process has its own criteria and limitation which has to be observed and handled
accordingly. The usage of a drill motor provides such a limitation, which has a very high
impact on both the well cleaning properties and the hydraulic performance factors. When
part of the system, the drill motor limits the minimum and maximum value of the flow rate,
leaving a small window for the optimization which is focused on the performance of the
mud motor in these cases. Having a horizontal section in the well path is also a major
factor in the optimization process, due to the different frictional loss behavior of the
horizontal section. The inclined parts of the well path requires high level hole cleaning
properties, which is difficult to achieve due to the limitations given by the drill motor when
it is used. Outside the hydraulic parameters, the optimization process contains the
management of the related drilling parameters which are the weight and the rheology of
the mud. The correct handling of the mud depends on the mud engineer working at the
rig, but the optimization process can reveal the possible improvements of the mud
parameters. The hydraulic optimization of a well have two general sections, one is prior to
the start of the drilling process itself and is called a hydraulic design of the well and the
second part which is done simultaneously with the drilling. The aim of the design part is to
establish a solid hydraulic system with balanced hole cleaning properties and hydraulic
performance. The second part of the optimization is the continuous calculation and
improvement of the parameters based on the actual field data. Although the aim of
optimization is to improve the related parameters, the final goal of the whole process is
more complex. By the continuous enhancement of the hydraulic system the optimization
can ensure the perfect condition of the wellbore, which results in higher ROP, eliminate
back-reaming requirement, decreasing the chance of the Stuck Pipe occurrence
(especially in the inclined hole section ). Furthermore, leads to excellent conditions for
cement job and casing setting. These features also ensure the "well-being" of the well for
an extended time, which is highly profitable in the long run. The hydraulic optimization has
long-term goals primarily because of the financial benefits providing such advantages
which are highly important in today's petroleum industry.
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5. Detailed analyses of the hydraulic system of well name "Dip-1"
The current section of the diploma covers the analysis of a well which was drilled in
Hungary, with the aim to explore and impound the miocene oil reservoirs and to drill and
develop a new, productive oil well. The complete analysis of the well is divided into three
sections, the first introduces the initial design of the well hydraulics, the second evaluates
the practical well data of the project and the third part consists of possible optimizations of
the hydraulic system. The first part includes the IFE Proposal and the drilling plan of the
well which introduces the starting parameters of the hydraulic system and the drilling mud
for each section of the hole. The second part evaluates the data collected from the daily
reports, logs and the geo-service cabin, and graphically visualizes the results in tables
and graphs. The last part of the section shows the possible improvements of the system
and highlights the financial and timely benefits of the correctly done optimization process.
5.1 Well structure and initial hydraulic and mud parameters
I.-II. Section (0-100m)
The conductor section of the well is consist of a 15 m deep, 20" wide and a 85 m deep,
17 1/2" wide section, where the drive pipe (20") is hammered down and the 13 3/8"
conductor casing is set into the drilled section. The plan suggests the usage of controlled
flow rate and rate of penetration to prevent losses and wash outs. The suggested flow rate
is 1800 l/min (after hydraulic calculations), which generates 17.83 m/min up-flow velocity.
The ROP is 15 m/h, the TFA of the selected nozzles (3x18) is 0.746 in2, which generates
174.1 HP bit hydraulic power with the current options. The standpipe pressure is 58 bars
in total, with 60% (35 bars) pressure loss at the nozzles, and 40% (23 bars) parasitic
pressure loss.
1. Table The drilling mud parameters of the I-II section (IFE Proposal)
35
The aim of this section is to drill down to the appointed depth without contaminating the
near-surface water deposits and preventing the possible wash-outs and fluid losses. The
layers of that section are mainly consists of sand, clay and the combination of them. The
fluid program suggests a simple spud mud with a weight of 1.05-1.10 SG for this stage
and initiates the usage of elevated viscosity, filtration control additives, CMC and shale
inhibitors for the safe drill-through of the section. The LGS content is strictly maximized at
9%, to prevent the development of too high viscosities and gel strengths. The other mud
parameters are presented in Table 1.
III. Section (100-1018m)
The third section of the well is 12 1/4" wide and consists of the combined layers of
sand, clay and clay marl. It has two sub-sections, one from 100 to 500 meter is a vertical
part and the other from 500 to 1018 meter is an inclined part. This section requires a more
complex handling both in mud technology and hydraulically than the previous, due to the
inclined segment. The aim of the vertical part is to maintain the best possible hydraulic
drilling performance while keeping the hole cleaning properties at the adequate level. For
that, the well hydraulic system is changed at some point to achieve the required
parameters. For the vertical section the plan suggests the flow rate to be between 1600-
2600 l/min, but 1800 l/min is the optimal value based on the calculations, which develops
27.7 m/min annular flowing velocity. Rate of penetration is elevated to 20 m/h, while the
TFA is decreased to 0.589 in2 and the nozzles sizes changed from a 3x18 to a 3x16 set.
With these properties, the standpipe pressure of the system is 70 bars, from which the
pressure drop at the bit is 57% (40 bars) and the parasitic pressure loss is 43% (30 bars),
thus the pressure conditions develops 161 HP bit hydraulic power. The inclined part of the
well requires different handling, which is caused by the mud motor. From 500 meter
depth, the flow rate is raised to 2200 l/min, developing 36.7 m/min up-flow velocity and the
nozzles are changed to a 3x20 set with 0.920 in2 as TFA. The inclination of the section is
low (16.39 degree at maximum), thus the pressure conditions and the hydraulic
performance parameters remain the same despite the changes in the hydraulic system.
The fluid plan initiates the same for the vertical and the inclined section, which is a
spud/polymer mud with a 1.10-1.16 mud weight and elevated viscosity. Solid content, and
especially the LGS content of the mud, is still strictly prohibited to be higher than 9%. For
that, the program suggests the continuous usage of centrifuges and flocculation unit with
the surface solid control system and the application of Hi-Vis sweeps at regular intervals.
The additional mud parameters are collected in the next table:
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2. Table The drilling mud parameters of the III. section (IFE Proposal)
IV. Section (1018-1859m)
This section is 8 1/2" wide and has a constantly increasing inclination from 16.39
degree to 20.39 degree. The layers of this segment consist mostly of the combination of
clay and clay marl, but it includes sand and other components as well in small portions.
The presence of CH reservoirs is expected at the lower points of the section, near to the
well bottom. Since the whole section is drilled with the mud motor, various parameters of
the hydraulic system are highly limited and the optimization focuses on the performance of
the mud motor. It results in decreased hydraulic performance factors, limited flow rates
and insufficient pressure conditions for optimization. The suggested flow rate range is
1300-1800 l/min, from which the optimal is 1600 l/min based on the calculations, which
results in 49.76 m/min annular fluid velocity. The bit nozzles are changed to a 3x18 set,
with a TFA of 0.746 in2, which develops 68.2 HP bit hydraulic power. The standpipe
pressure of the section is 90 bars, from which the bit pressure loss 23% (21 bars) and the
parasitic pressure loss is 77% (69 bars). The rate of pressure losses clearly shows the
effect of the mud motors presence in the hydraulic system, which hamstrings the
performance optimization. The drilling mud is also changed in this section to a KCL/K2CO3
based GLYDRIL mud, which has better inhibition against clay and improved rheology. The
suggested mud weight is between 1.08-1.12 for the section, with lower viscosity
parameters than previous sections muds. The LGS content is limited down further to 5%
as maximum, and the fluid program suggests the use of Hi-Vis sweeps regularly. The
most important property of the mud in this section is the inhibition and solid content, which
has to be in the required range at all time. The other parameters are presented in the
following table.
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3. Table The drilling mud parameters of the IV. section (IFE Proposal)
5.2 The sectional overview and analyses of the hydraulic and mud parameters
The well structure changed drastically during the drilling process due to the
unsuccessful penetration of the productive zone of the Miocene layers in the region. The
plan was to find the pay-zone of the Miocene reservoirs at 1700-1800 m depth, which was
proven to be productive by previous wells. The first stage of the project which is described
in the previous chapter has ended in failure, thus the company had to change the initial
well path. The second stage started from 1413 m (TVD) with higher inclination than the
first stage and was aimed at the same Miocene layer. This section has an additional shoe
compared to the plan, which is 7” at the 1778 m true vertical depth. Below this shoe, the
project reached the productive target formation of the Miocene layer, between 1780-1800
m true vertical depth. Due to the inclination of the well the productive zone is 40-50 m
thick, and situated at the same vertical depth which was suggested by the initial plan
despite that the well path is 300 m longer. This change in the structure resulted in different
hydraulic parameters compared to the planned, and required a careful and throughout
optimization process. The hydraulic parameters of the sections are calculated from the
field data and analyzed by Halliburton’s WELLPLAN software. The complete calculation
process of the software can be checked in Appendix A. The evaluation of the hydraulic
system is summarized in tables and graphs for the easier overview and understanding.
The first two sections have a short review because the well hydraulics and the
optimization process cannot express much potential in these sections, while the deeper
segments have a long evaluation due to the complex hydraulic system. The next figure
shows the finalized state of the well.
38
7. Figure Finalized well structure of Dip-1 well
39
I-II. Section
The first 100 m of the well is practically unsuitable for optimization, due to the
numerous requirements of the unconsolidated, near-surface formations. Both hole
cleaning and hydraulic performance is highly limited in this section, because the crew
cannot use sufficient flow rates and pressures. The applied pumping rate is 1800 l/min,
which is close to the required flow rate for the adequate hole cleaning, but further increase
is harmful to the wellbore wall and could lead to excessive increase in cuttings load. The
ROP is also controlled and kept at 13-15 m/h rate, to avoid the previously mentioned
elevated cuttings load. Hydraulic performance in the well is negligible and it's practically
impossible to develop decent value of the performance parameters due to the limitations
given by the formation.
III. Section 12 ¼” (100-500 m)
The vertical part of the third well section still contains unconsolidated formations which
limits the drilling speed which was 20 m/hr, and the applicable flow rates. The
requirements and limitations of the section can be computed through the hydraulic
optimization calculations, which is the basis of the correct selection of the adequate flow
rate and flow area. The first step is to determine the minimum flow rate for the sufficient
hole cleaning and the required pumping rate to achieve 36 m/min annular up-flow velocity.
The acceptable hole cleaning properties can be attained at 1600 l/min flow rate (8.Figure),
while the required flow rate is 2500 l/min for the mentioned annular velocity. These values
will give the lower limit of the acceptable flow rate window, however we have to take into
consideration the consolidation level of the present formations. In this case, the rate
requirement of the up-flow velocity is too high to be applied as the limit, thus the 1600
l/min flow rate is the lower margin. The next step is to determine the upper limits of the
system, which are the flow rate for transient flow, maximum surface pump capacity and
unacceptable amount of parasitic pressure loss. The maximum flow rate output of the
pump is 2900 l/min with the applied cylinder and SPM, which defines the upper margin of
the flow rate window due to its lower value than the requirement of the transient flow and
the abruptly high parasitic pressure loss. The result is a wide range of acceptable flow rate
(9.Figure), between 1600-2900 l/min, from which the crew has to select the most ideal
based on the hydraulic parameters and the formation properties. From this range, the
applied pumping rate is 1800 l/min, which fulfills the minimum hole cleaning requirement,
but unable to establish a favorable hydraulic performance or attain the 36 m/min annular
up-flow velocity. The developed standpipe pressure is 64.5 bar from which the pressure
loss at the bit is 38 bar, which means that the rate between bit and parasitic pressure loss
is 59-41 %.
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8. Figure Flow Rate requirement for hole cleaning of 12 1/4" vertical section
This would be ideal for optimizing the well hydraulics for bit impact force, but the
current conditions makes it impossible to do so. The applied nozzles are a 3X16 set with
0.589 in2 TFA, thus the system develops 2605.1 N Bit Impact Force, 152.8 HP Bit
Hydraulic Power, 1.3 HP/in2 HSI and 78.94 m/s Bit Nozzle Velocity. The hydraulic
performance of this section is poor, as it is indicated by the hydraulic performance factors.
Despite the favorable pressure drop ratio, both impact force and hydraulic power are low,
and HSI and jet velocity are out of the acceptable range. Because these parameters are
directly depend on the flow rate and the TFA any kind of improvement is related to the
elevation of flow rate or the setting of smaller nozzles. Due to this, the sections depth and
pressure conditions limit the range of flow rate increase and define the maximum
enhancement of the hydraulic performance parameters. Excessive increase of pumping
rate must be avoided because of the presence of unconsolidated formations in the upper
parts of the section. The upper limit for that can be only defined at the time of the
operation by practically applying various flow rates and checking its effect on the
formations. Harmful value of flow rate can lead to wash-out of the formation, which results
in excessive cutting load and instable open hole section. The section is drilled with simple
41
Spud Mud, which has 1.10 SG weight. The mud is treated to develop rheology with high
carrying capacity and suspension ability, in order to prevent any kind of problem related to
high cutting load.
9. Figure Acceptable Flow Rate Window of 12 1/4" vertical section
For that, yield point of mud is 24 lb/100 ft2, plastic viscosity is 16 cP, 10 second and 10
minute gel strengths are 10/23 lb/100 ft2 respectively. Due to the low flow rate and the
shallow depth of the section, ECD of the mud is close to the static density, thus problems
related to the circulating density cannot arise in this part of the well.
III: Section 12 ¼” (500-1020 m)
The inclined section of the well starts from 500 m depth and reaches its end at 1022 m
with a 16.42 ° inclination where the next casing shoe is set. The applied penetration rate
was 15 m/hr. Deviation of the well defines new limits in the acceptable flow rate window,
which has to be recalculated for the section. Due to the presence of mud motor or PDM
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(Positive Displacement Motor) in the BHA, both minimum and maximum margin will have
a limit related to it (10.Figure). For the successive penetration of the segment, the flow
range of the PDM will be the most influential, because the satisfactory performance of the
mud motor is the most important in that section beside hole cleaning. If required, other
parameters could even deteriorate for the sake of correct PDM performance, but the
usable range is usually wide enough for further optimization. Pre-determination of the
applied flow rate is highly important for the correct setting of the MWD (Measuring While
Drilling) tool. Using pumping rate out of the pre-calculated window results in the
decreased quality of MWD results which is advised to be avoided if possible. Using the
mud motor out of its operating flow rate range leads to severally deteriorated drilling
performance, and must be prevented as suggested by the contractor responsible for
directional drilling. Thus the minimum margin for the flow rates are the following, 1136
l/min required by the PDM, 2300 l/min is the limit for the favorable hole cleaning properties
(11.Figure) and 2500 l/min is required to attain the 36 m/min annular up-flow velocity.
10. Figure Acceptable Flow Rate Window of 12 1/4" inclined section
43
As it is indicated by the values, the minimum requirement of the PDM is relatively low
compared to the pumping rate margin for the hole cleaning. This value is insufficient and
fails to fulfill the basic needs of the current well section, not to mention the impact on the
hydraulic performance parameters. Regardless of its possible negative effects of its usage
on the well hydraulics, the lower limit of flow rate will be the minimum requirement of the
mud motor which is 1136 l/min. The following step is to set the upper margin of the flow
rate window and describe the maximum limits of the system. The maximum acceptable
pumping rate of the PDM is 3407 l/min, which means that mud motor has a wide variety in
case of flow rate, thus allows further optimization. Due to the same diameter of the
section, the transient flow develops at the same 4200 l/min rate as in the vertical part,
which is unacceptable because of its greater value than the PDM maximum limit.
11. Figure Flow Rate Requirement for Hole Cleaning of 12 1/4" inclined section
The limit of excessive parasitic pressure loss is 3600 l/min, which is slightly more than
the mud motors limit, thus the pressure conditions never reaches the unfavorable state in
the section. The surface pump capacity is 2900 l/min, which defines the upper margin of
the usable flow rate window, resulting in 1136-2900 l/min total range. Compared to the
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vertical part of the section, the inclined segment has a wider range of flow rates, but only
the minimum margin got lowered which does not benefit the operation. The crew selected
2050 l/min as flow rate, which is in the operating range of the PDM, but fails to fulfill the
requirement for proper hole cleaning or adequate annular fluid velocity. This leads to
increased amount of suspended cuttings volume, which due to the lower up-flow velocity
forms a small amount of bed height in the well (12.Figure). The aim of the sufficient hole
cleaning is to eliminate the presence of bed height in the well, which can have harmful
effects and cause problems. Low bed height does not lead to immediate problems, but
leaving it untreated is not an option.
12. Figure Cuttings Volume and Bed Height with Applied and Suggested Flow Rate
If the treatment is not done with hydraulic parameters, then the usage of high viscosity
sweeps are suggested, as it was initiated in the mud program of the section. With the
selected 2050 l/min flow rate and 3X16 + 1X14 nozzles with 0.739 in2 TFA, the system
develops 119 bar standpipe pressure from which the pressure drop at bit is 32 bar. The
ratio of parasitic and useful pressure drop is 73-27 %, which is highly unfavorable for
hydraulic performance optimization. The reasons for that area the presence of mud motor
which causes high parasitic loss and the relatively large total are of nozzles. The TFA is
selected on the request of the service company responsible for directional drilling, and
45
designed to allow the improved control of the mud motor. Unfortunately the system
parameters results in poor hydraulic performance, which is clearly indicated by the
performance factors. The bit impact force is 2765.3 N, the bit hydraulic power is 147.2 HP,
the developed HSI is 1.2 HP/in2 and the jet velocity is 71.63 m/s. All of the performance
parameters are low, considering the depth, standpipe pressure and flow rate, the reason
for that is the mud motor and the large TFA. In case when the pressure conditions does
not allow the enhancement of hydraulic power or impact force, the crew can try to
maximize (not optimize) the jet velocity of the mud. The section was drilled down with the
same spud mud as the vertical section, but with increased (1.13 SG) mud weight. The
viscosity and gel strengths of the fluid is remained the same, thus the ECD of the mud is
still close to the static density and related problems are unable to develop. By the
calculations, the combined performance of the hydraulic system with the current
parameters fails to fulfill some of the requirements, but actually the section was drilled
down without any kind of problem which means that the well hydraulics done satisfactory
work.
IV. Section 8 ½" (1022-2003 m)
The 8 ½” part was designed to be the last section of the well with 1800 m depth and
20° inclination but the target formation was unproductive. To reach the productive zone of
the target formation, the company decided to drill a side track, starting from 1441 m
measured depth with greater inclination. My work analyzes the successful; second state of
the section which covers the 1022-2003 m part of the well what was drilled down with a 10
m/hr average ROP. Due to the changes in the initial plan, some of the mud properties and
the applied flow rates have also been recalculated and changed. It also has to be noted
that the designed deviation of the well in the side track is very high and reaches the critical
range where hole cleaning properties deteriorates. This effect must be counted in the
optimization calculations and its impact can be seen in the requirements and the result as
well. The directional drilling requires the presence of PDM, which defines primarily
important flow rate margins of the system. The BHA contains an MWD tools as well and
thus additional limitations related to the pumping rate are present in the section. The
diameter of the section is 8 ½”, which results in smaller available flowing area, thus the
developed pressure conditions is less favorable for optimization. Considering all of the
limitations given by the system the acceptable flow rate range is very small, and the
possible hydraulic improvements are similarly restricted. The analyzes of the minimum
margins of the acceptable flow rate window shows, that the section has relatively low
requirement for the adequate up-flow velocity and for the mud motor.
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13. Figure Flow Rate Requirement for Hole Cleaning of 8 1/2" section
Proper annular velocity is reached at 1000 l/min pumping rate, due to the diameter
reduction of the annulus. This parameter is highly important and deeply connected to the
proper hole cleaning parameters of the well, but its correct value does not ensure the
satisfactory level of hole cleaning. The flow rate of favorable well cleaning is reached at
2150 l/min (13.Figure), which is relatively high compared to the previous sections, but the
reason for that is the very high inclination of the well section. Though the application of the
flow rate for proper hole cleaning is always suggested, but due to the current conditions
this flow rate is hardly applicable. Required minimum flow rate of the PDM is 1136 l/min
while the maximum acceptable is 2272 l/min, which means that the applicable window of
the mud motor decreased from the previous section. Despite the reduction in the
maximum flow rate margin of the PDM, it is still higher than the maximum acceptable
pumping rate for parasitic pressure loss, which is reached at 2217 l/min rate. The parasitic
pressure drop in that case would be equal with the total system pressure, which results in
zero pressure drop at bit and thus zero hydraulic performance. This scenario or
approaching it must be avoided at all cost, to prevent serious decrease in drilling
performance. By the manual of the contractor responsible for directional drilling, with the
presence of mud motor in the BHA the bit pressure drop should be between 14-84 bar.
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Unfulfilling the minimum requirement can result in deteriorated hydraulic performance and
can cause other non-hydraulic problems as well.
14. Figure Acceptable Flow Rate Window of 8 1/2" section
Exceeding the maximum value can lead to insufficiently high developed pressures and
should be avoided. The further maximum limits of flow rates are all unacceptable due to
their higher value than the parasitic pressure loss limit, as the pump capacity is still 2900
l/min and the transient flow is reached at 2000 l/min. Overstepping the margin of transient
flow does not carry any problem for the hydraulic system, but the flow rate should be
monitored closely not to cross the border of turbulent flow. Defining the upper and lower
limits develops the usable pumping rate window, which is 1136-2217 l/min based on the
PDMs minimum and the parasitic pressure loss maximum value (14.Figure). In case if the
hole cleaning requirement is set as the minimum margin, the window would be 2150-2217
l/min, which is unusable for any kind of parameter management. The crew applied various
48
flow rates between 1500-1600 l/min and used a set of 3X16 nozzles with 0.589 in2 TFA,
thus the developed standpipe pressure is 127 bar from which the parasitic pressure loss is
77% (98 bar) while the bit pressure drop is 23% (30 bar).Reason behind the poor rate of
useful and parasitic pressure loss is the mud motor, causing high increase (20-30 bar) in
parasitic loss. With these conditions, the hydraulic system develops 2039.6 N bit impact
force, 106.3 HP hydraulic power, 1.9 HP/in2 HSI and 70.2 m/s jet velocity at the bit. Due to
the selected flow rate, the optimization calculations reveals that the highly inclined section
of the well will be subjected to high cutting load, and the development of bed height is also
probable. For that reason, the mud program advices the frequent use of cleaning pills of
high viscosity fluid. The developed hydraulic performance in the section is low and, given
the current conditions, possible improvements are very limited. Applied drilling mud weight
is 1.10 SG in that section, with nearly constant yield which is 19 lb/100 ft2 point but varying
plastic viscosity. The variation in plastic viscosity occurred when the well path changed
from the original, and the drill-down of the side track started. At 1441 m depth the PV
increased from 15 to 23 cP and remained at that level until 1753 m depth, where it
decreased to the original 15 cP value. Between 1441-1753 m the standpipe pressure is
also increased steeply, and reached 142 bar at 1705 m depth. Given the low mud weight
and low solid content of mud, the emergence of ECD related problems are improbable in
this section, just like in all the previous parts of the well. Though the optimization software
indicates that the well hydraulics in this section are out of the satisfactory range in
performance and hole cleaning properties, the 8 ½” part of the well was drilled down
without any noticeable problem.
V. Section 6" (2003-2100 m)
The last section of the well is 6” wide and 100 m deep, which is the productive part of
the target formation and the finishing point of the project. Because of the small diameter
and length of the section, the hydraulic parameters of the well are hardly can be optimized
in this part and rate of penetration is also kept at a low level of 2 m/hr. Limitations from the
PDM remained and its effect even increased, leading to a narrow acceptable flow rate
window. Due to the small diameter of the segment, hole cleaning requirement grew bigger
than the maximum allowable flow rate of the mud motor which is clearly visible in the
15.Figure. Other upper or lower margins are also can be neglected in this section,
because the only limit which is subjected on to the system is the minimum and maximum
acceptable pumping rate of the PDM. This range is between 379-947 l/min (16.Figure),
the smallest flow rate window of all and the first which does not contain the optimum value
of flow rate. However, the flow requirement of the 36 m/min up-flow velocity is within the
range and reached at 500 l/min flow rate. Despite the adequate annular velocity of the
49
mud, hole cleaning could be still unreached as it is happens in that case. Other than the
small diameter, high inclination of the well causes the deterioration of hole cleaning
properties. From the designated range, the applied flow rate is 760 l/min, which generates
135 bar standpipe pressure with the usage of 3X12 nozzles and 0.331 in2 TFA. This
installation developed low hydraulic performance, 825.6 N impact force, 36.3 HP hydraulic
power, with 1.3 HP/in2 as HSI and 59.25 m/s as jet velocity. The effect of the previously
mentioned deteriorating features of the section can be seen in these values.
15. Figure Flow Rate requirement for hole cleaning of 6" section
The drilling mud of the section is the same KCl/K2CO3/Glydril mud as it was in the
previous section, with 1.10 SG weight. The plastic viscosity of the mud increased to 21 cP
while the yield point remained at 20 lb/100 ft2. The suggested values of the program
indicates that the crew should experience hole cleaning problems or the BHA can even
stuck, but the field results show no such experience. It means that the applied flow rate
was enough for the safe penetration of the section, and the crew successfully avoided
drilling problems.
50
16. Figure Acceptable Flow Rate Window of 6" section
5.3 Summary of the practical well data
The first and primarily important fact of the well is that the project was successful and
reached the productive zone of the target formation, without serious error in the drilling
activity. Formation damage was also minimized through the entire operation and well
control event did not happened. The well was planned to be drilled down and completed in
23 days, but due to the change of course, operation time increased to 56 days. This
excessive rise in project time is not just the result of the drilling performance of the rig, but
the unsuccessful reach of the pay-zone with the initial plan. Several days was spent with
logging and coring which also increase the overall time of the project, as well as the costs
of the well. Though the problems were avoided, the parameters of the well hydraulics and
ROP were not perfect and could have been improved further. Reason behind that is the
overall performance utilization was not the fullest and possible improvements were not
51
applied despite their availability. The condition of the rig and its components has a
deteriorating impact on the attainable performance and limits the hydraulic parameters of
the system. The surface pumps pressure capability is 185 bar with the applied cylinder,
but is limited to 150 bar by the company due to its old age.
17. Figure Flow Rate Margins with Inclination and Stanpipe Pressure
This limitation has a high impact on the overall pressure condition of the well, moreover
limits the achievable hydraulic performance. The bit in the 12 ¼” section contains stuck
nozzles, which cannot be changed, but due to the fairly good condition and usability of the
drill bit, it remained part of the BHA. Unfortunately, it brings a limitation to the system
because the TFA cannot be changed which results in decreased chances for further
optimization.
4. Table Summarized hydraulic parameters of the well
12 1/4"
100-500 m
12 1/4"
500-1022 m
8 1/2"
1022-2003 m
6"
2003-2100 m
Flow Rate [l/min] 1800 2050 1600 760
Nozzles [1/32"] 3X16 1X14 3X16 3X16 3X12
TFA [in^2] 0.589 0.739 0.589 0.331
Bit Impact Force [N] 2605.1 2765.3 2039.6 825.6
Bit Hydraulic Power [HP] 152.8 147.2 106.3 36.3
HSI [HP/in^2] 1.3 1.2 1.9 1.3
Jet Velocity [m/s] 78.94 71.63 70.2 59.25
Standpipe Pressure [bar] 64.5 119 127-142 135
52
The fact which must be stated, that throughout the entire project the available
standpipe pressure was never used in the fullest because it carries the chance of
overloading the surface pump according to the company. It has the same limiting effect
which was stated above, and results in the same decreased chance for optimization. The
overall success of the well does not mean the optimal execution of the project. When the
possibility for optimization is present, the crew should attain the best possible parameters
and complete the drilling with them. Usage of the optimum properties leads to satisfactory
safety, well cleaning, hydraulic performance and wellbore condition, which is the aim of
every drilling operation. The optimization of the above described and overviewed sections
are performed with the same software (WELLPLAN) which is used for the previous
analyzes. It has to be noted, that the software operates with a certain amount error, which
has an acceptable rate, given by the company, up to 10 %. Also, the optimized value
given by the program is not fully adaptable to the drilling operation, due to the difference
between the actual field conditions and the calculated and estimated conditions. This
difference could make the software results usability questionable, but in reality, the
calculations of the process contain estimations based on field data collected by the
software’s developer. In conclusion, the computed parameters are not 100 % accurate but
still highly usable in the drilling project, and give a solid basis to the field engineer for
further selection.
5.4 Possible improvements of the sections
The results from the well data shows clearly that the applied drilling system left chance
for further possible optimization, which contains the change in flow rate, nozzles,
rheological parameters or all of them. The calculations prove that these modifications
develop significant improvement in the well hydraulics which is more favorable for the rig
equipment and for the well conditions as well. The improvements include the
enhancement of hole cleaning properties and hydraulic performance parameters.
Changes in the rheological parameters result in the shift of acceptable flow rate window
and hole cleaning properties, which leads to further possibilities. Modifying the hydraulic
system has a connected effect on the pressure conditions, hole cleaning and performance
parameters and due to that changes in the system requires the recalculation of these
parameters. The following section analyzes these possible modifications for the different
well sections and evaluates the results of the available improvements of the system in
tables and graphs. It has to be stated, that the results of these calculations are theoretical,
and their acceptable usage in the practice is not proven. Each section is optimized in
three ways compared to the original state. First when the existing nozzles are not
53
changed but the flow rate of the system is selected to fully utilize the available system
pressure. The second option of improvement is when the flow rate of the original state
remains the same, but the nozzles are set to exploit the total pump pressure capacity. The
last option contains changes in both the flow rate and the nozzle sizes and also utilizes
the full available pressure of the system. The first two and the stable part of the third
section are not analyzed for further optimization, due to the consolidation level of the
formations in these sections. Thus, the analysis starts from the kick off point of the third
section which is at 500 m depth.
The 12 ¼” sections inclined part was originally drilled with 2050 l/min flow rate and
0.739 in2 TFA with 1X14 and 3X16 nozzles. The analysis contains three options, first the
flow rate is maximized, next the TFA is adjusted and lastly both flow rate and nozzles are
changed. In the first option applied flow rate is changed to 2730 l/min, while the TFA
remained at the initial value of 0.739 in2. This modification in the system results in high
improvement of the hydraulic performance of the well and fulfills additional requirements
of the system. Compared to the original state, bit impact force increased to 4904.2 N,
hydraulic power elevated to 347.5 HP, thus the developed HSI is 2.9 HP/in2 and the jet
velocity is 95.38 m/s. With this change in the hydraulic systems both HSI and jet velocity
elevates to the sufficient level, while bit impact force and hydraulic power increases
greatly. This drastic change is due to the greater pressure drop at the bit which increased
to 56.96 bar from 32.12 bar, which also means a high difference in the pressure drop
distribution of the system. The newly applied flow rate meets the requirement of the
proper hole cleaning and the 36 m/min up-flow velocity without overstepping the maximum
boundary of 2900 l/min. Thus, our system now has adequate hole cleaning properties plus
proper annular velocity to bring the drill cuttings to the surface and the developed
performance factors have improved highly and their value now is in the acceptable range.
There is clear benefit in rising the flow rate and utilize the performance of the surface
pumps, which also enable the application of higher ROP and thus the quicker finishing of
the section. Though the improvements achieved this way are significant, the other
possible ways of parameter enhancement are also worthy of examination. The following
option is includes the modification of bit nozzles and TFA, while using the original flow rate
of 2050 l/min. With the applied set of 1X14 and 3X16 nozzles and the practical standpipe
pressure, the system was not able to develop adequate hydraulic performance. In case
the TFA is reduced to 0.428 in2 and the bit nozzles are changed to 3X11 and 1X14, the
hydraulic parameters of the well undergo a high improvement. The performance factors of
the section are the following, bit impact force is increased to 4820.6 N, the bit hydraulic
power elevated to 447.2 HP, HSI is 3.8 HP/in2 and jet velocity increased to 124.86 m/s.
54
The changes in parameter values are considerably high, even if it is compared to the
improved parameters of the previous option, not to mention the huge difference to the
original values. The surface pumps pressure capability is fully utilized, which results in
greater pressure distribution along the well and appropriate, 98 bar (53 %) pressure drop
at the bit for impact force optimization. This option focuses only on the hydraulic
performance of the system, thus hole cleaning efficiency is not improved with this change.
However, the high jet velocity and hydraulic power enhances the cooling of the bit,
prevents the re-grinding of the cuttings and greatly helps to break the formation. To attain
these parameters the flow area must be decreased significantly, by 0.315 in2 which means
nearly 43 % reduction. The reduced diameter of the newly selected nozzles can lead to
the choking of the smallest nozzle, and thus result in unfavorable conditions and can
cause serious problems. The possible best optimization method for this section is to
modify both the flow rate and the nozzle sizes and utilize the surface pumps maximum
capability to develop adequate hole cleaning and hydraulic performance. In that case, the
pumping rate is increased to 2500 l/min and the TFA is reduced to 0.624 in2 with the
usage of 3X14 and 1X15 nozzles. This combination of these options enables the
development of the advantages of both the elevated flow rate and the decreased TFA and
leads to optimal condition of the hydraulic system. The performance parameters are
different than the results of the previous methods, but their increase is still significant
especially compared to the original state. The developed parameters are the following; bit
impact force elevated to 5056.9 N, hydraulic power at the bit is 403.5 HP, the HSI is 3.4
HP/in2 and the evolved jet velocity is 107.4 m/s. Comparing the three method with each
other reveals that the developed bit impact force is highest if the last option is used, while
the other parameters have a value in the acceptable range as well. Due to the depth and
diameter of the section the most advantageous is the optimization of bit impact force and
the application of high flow rate which is both present in the third method.
5. Table The comparison of optimization methods of the 12 1/4" section
Original state of systemSame nozzles, modified
flow rate
Same flow rate,
modified nozzles
Modified flow rate and
nozzles
Applied Flow Rate [l/min] 2050 2730 2050 2500
Applied Nozzles [1/32"] 1X14 3X16 1X14 3X16 1X14 3X11 1X15 3X14
TFA [in^2] 0.739 0.739 0.428 0.624
Standpipe Pressure [bar] 119.1 184.4 184.5 184.9
Bit Impact Force [N] 2765.30 4904.2 4820.6 5056.9
Bit Hydraulic Power [HP] 147.2 347.5 447.2 403.5
HSI [HP/in^2] 1.2 2.9 3.8 3.4
Jet Velocity [m/s] 71.63 95.38 124.86 107.4
55
With the increased pumping rate, the system fulfills the requirement of the adequate
up-flow velocity and thus improves the hole cleaning properties of the well. The higher
flow rate and the change in TFA develops the best impact force, but it must be stated that
the reduction of flow area is much smaller compared to the second option thus the related
problems are prevented. The developed HSI of the system is between the values of the
above described two methods, but nearly three times greater than the original and due to
that the effect on hydraulic performance is much higher.
18. Figure Rate of improvement in case of the different optimization methods in 12 1/4" section
Jet velocity now exceeds the 100 m/s margin, thus has a high improver impact on well
bottom cleaning, and greatly helps the cooling and drilling work of the bit.
19. Figure Acceptible ROP range based on Hole Cleaning
56
While the performance of the well hydraulics is optimized with this method, the usage
of this option carries other advantages. The applied pumping rate is higher than the
original but achieve better hole cleaning, low enough to avoid the damaging or wash-out
of the formation and prevent the extreme increase in ECD. Also, the pumping rate is lower
than it was in the first optimization option, thus the surface pumps are not so heavily
loaded and the wear on them is reduced. As it is clearly visible, the modifications done to
the system are not as severe as in the previous cases, but the results prove that this
installation provides the best possible solution and enables the increase of ROP up to 20-
25 m/hr, as it is shown in the 19. Figure.
The optimization of the next, 8 1/2" diameter section is based on the same pattern and
contains three possible options for the enhancement of the hydraulic system parameters.
The original state of the system contained 1600 l/min flow rate and 0.589 in2 TFA, with the
usage of 3X16 nozzles. The first option includes the increase of applied flow rate up to
1935 l/min while using the original set of nozzles and the utilization of the pumps
maximum capacity. Increase of the pumping rate leads to better hydraulic performance of
the system and more importantly better hole cleaning properties, which is highly required
in that section because of the great inclination level. The improvement of the parameters
can be checked in 6. Table and is clearly indicated by the growth in the values, which are
now inside the suggested acceptable range or close to it. The elevated HSI of this
installation reaches the satisfactory margin which results in better drilling performance.
Moreover, the raised jet velocity approaches the 100 m/s minimum border thus leads to
better cooling of the bit and increased cleaning of the well bottom. Lastly, the improved bit
impact force and hydraulic power develops better hydraulic drilling performance and
significantly helps the work of the bit. The most important effect of this installation is the
advantages gained in hole cleaning properties due to the critical inclination of the section.
The suggested flow rate of the proper hole cleaning is 2150 l/min, given by program after
the calculations. However, this rate is unattainable due to pressure capacity of the surface
pumps with the applied cylinder, which means that the maximum possible rate is most
suitable for the operation. The solutions could be the change of pump cylinders for
increased pressure capacity or the change of nozzles for bigger TFA. The related
problems are the decreased pumping rate capacity in the first solution and the decreased
hydraulic performance of the second solution. The field experience proves that the
originally applied 1600 l/min provided satisfactory hole cleaning, thus the elevated 1935
l/min develops improved cleaning properties while the hydraulic performance also greatly
increases. The second option of optimization is to use the originally applied flow rate, but
the TFA is changed to utilize the maximum pressure capacity of the surface pumps. The
57
growth in performance factor values are clearly noticeable in Table 6, especially the HSI
and jet velocity parameters, which increased severely compared to the original state.
Their increase has an advantageous effect on the performance and well bottom cleaning
properties, but this high improvement requires the drastic decrease of flow area. The
original TFA decreased by 40%, which carries the increased possibility of nozzle plugging
and the related problems of it.
6. Table The comparison of optimization methods of the 8 1/2" section
In case the aim is to lessen the load of the surface pumps, this method is an effective
way of improving the hydraulic performance of the system, but otherwise the high
reduction of TFA carries possible harmful effects which are advised to be avoided.
20. Figure Rate of improvement in case of the different optimization methods in 8 1/2" section
Original state of systemSame nozzles, modified
flow rate
Same flow rate,
modified nozzles
Modified flow rate and
nozzles
Applied Flow Rate [l/min] 1600 1935 1600 1810
Applied Nozzles [1/32"] 3X16 3X16 1X13 2X12 1X15 2X13
TFA [in^2] 0.589 0.589 0.351 0.430
Standpipe Pressure [bar] 127.9 184.2 181.9 184.7
Bit Impact Force [N] 2039.80 2983.1 3427.6 3573.2
Bit Hydraulic Power [HP] 106.3 188.1 300.3 288.5
HSI [HP/in^2] 1.9 3.3 5.3 5.1
Jet Velocity [m/s] 70.17 84.86 117.92 108.67
58
The best option is to modify the flow rate and the bit nozzles together and exploit the
maximum capability of the surface pumps. The applied TFA comes from a 1X15 and 2X13
set of nozzles, which installation together with the adequate flow rate provides the
sufficient cooling for the bit, increase the cutting sweep from the well bottom and helps the
drilling work of the bit. The HSI is nearly the same as it was in the previous option, but the
higher flow rate of this method provides better conditions. The advantages of this method
are the same as it was in the previous section, the overall optimization of the total system
including both hole cleaning and performance. The application of the suggested flow rate
for proper hole cleaning is not included, but the previously mentioned limiting conditions of
the pumps makes this option the best of the possibilities. If the selection is based on
solely the hole cleaning efficiency, the second best option is the first method where the
maximum acceptable flow rate is used, but both methods enable the increase of
penetration rate up to 20 m/hr (21.Figure).
21. Figure Acceptible ROP range based on Hole Cleaning
The last section of the well is relatively short (100 m) and has a small diameter of 6",
which makes the optimization highly challenging. The possible modifications of the system
overviewed in the same way as it was done in the case of the previous two sections and
the results are summarized in Table 6. This section is especially susceptible to changes in
the system, because the small diameter causes quick shifts in the standpipe pressure
after every modification. Considering this property of the section, the first option is to raise
the flow rate up to 935 l/min, near to the maximum acceptable margin. With this
modification the pressure capability of the surface pumps are utilized to their fullest, which
results in elevated hole cleaning and hydraulic performance of the system. The
improvement of the hydraulic performance in this section is secondary, because the first
59
target of the optimization in this section is to attain proper hole cleaning properties.
Though the installation limits the applicable flow rate, usage of the highest possible
pumping rate is highly suggested as it leads to significant improvement of the hole
cleaning parameters and the hydraulic performance, as the values are indicating. The
improvements of the parameters are clearly visible, but the current installation enables
further optimization of the section. The next possible way is to decrease the TFA to 0.191
in2 and change the nozzles to a 1X11 and 2X8 set. This modification causes high
improvement of the performance factors as bit impact force increases to 1432.4 N and bit
hydraulic power elevates to 109.4 HP. The HSI of the system also increases to 3.9 HP/in2
and the jet velocity to 102.8 m/s and with these changes both parameter reaches the
acceptable range. However, the reduction of the flow area is not suggested in that section,
due to the already low TFA and the increased probability of problems related to the small
nozzles in case of further reduction. The third option is to increase the flow rate to 835
l/min and slightly reduce the TFA down to 0.230 in2 and change the nozzles to a 3X10 set.
This installation leads to acceptable values of performance factors and also improves the
hole cleaning parameters.
7. Table The comparison of optimization methods of the 6" section
The combined effect of the modifications again leads to the best results of the
possibilities, but the selection of the most suitable method does not depends solely on the
hydraulic performance parameters in that section. The application of the highest possible
flow rate is carrying more advantageous effects and prevents the need of TFA reduction
thus avoids the problems related to it. Both the first and third method enables the increase
of ROP, but in that case the higher flow rate is more advisable due to the increased
cuttings load. Though the field results shows that the used flow rate with the applied set of
nozzles developed sufficient hole cleaning, the system failed to achieve acceptable
hydraulic performance which is indicated by the very low rate of penetration. The third
Original state of systemSame nozzles, modified
flow rate
Same flow rate,
modified nozzles
Modified flow rate and
nozzles
Applied Flow Rate [l/min] 760 935 760 835
Applied Nozzles [1/32"] 3X12 3X12 1X11 2X8 3X10
TFA [in^2] 0.331 0.331 0.191 0.230
Standpipe Pressure [bar] 136.4 184.1 179.3 183.7
Bit Impact Force [N] 825.60 1249.6 1432.4 1435.1
Bit Hydraulic Power [HP] 36.3 67.7 109.4 100
HSI [HP/in^2] 1.3 2.4 3.9 3.5
Jet Velocity [m/s] 59.25 72.9 102.8 93.75
60
option carries the chance of hole cleaning improvement and performance increase without
extreme modifications.
22. Figure Rate of improvement in case of the different optimization methods in 6" section
Although the section is just 100 m deep, it contains the pay-zone of the target formation
and thus the best option for well is to drill down this part with the optimal achievable
properties and parameters. The other aspect is the required time which, despite the low
depth of the section, was two days due to the 2 m/hr applied ROP. With the above
mentioned methods the chance of ROP increase is possible (23.Figure), even up to 10
m/hr, which can shorten the drill time and thus lessen the cost of the well.
23. Figure Acceptible ROP range based on Hole Cleaning
61
The last part of the well optimization is the improvement of the drilling mud parameters,
a highly challenging and difficult task. The difficulty of it comes from the high level of
interconnection between the mud parameters which make it impossible to modify the
properties of mud individually. Also, due to the large volume of actively used drilling mud,
the modification of the properties takes a lot of time and additive, thus increases the costs
of the well. From the many properties of the mud, the viscosity has the biggest impact on
the well hydraulics which makes it primarily important to achieve the sufficient and most
suitable viscosity values. The LSRV and the 10 sec gel strength of the mud must be high
enough to ensure the adequate level of suspension in case the drilling activity is stopped.
When these parameters reach the acceptable range, the international practice suggests
that the viscosity parameters should be as low as possible. This way the applicable flow
rates are higher due to the lower developed standpipe pressure and frictional losses.
However, further reduce in the viscosity can result in diminished suspension ability and
can lead to different kind of serious problems. In case of the currently analyzed well, the
viscosity parameters of the mud were satisfactory and in general the mud fulfilled its roles
appropriately. In conclusion, main objective of the mud in the optimization process is to
provide the sufficient base for further optimization. The mud engineer must always work
on achieving and sustaining the adequate parameters, to aid the optimization of the well
and this ways ensure the successfulness of the whole project.
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6. Conclusions
Based on the observations and facts written above, it can be stated the hydraulic
optimization of the wells have an extremely important role in every drilling project. The
proper management of the hydraulic parameters is always required to complete safely
and successfully the drilling of a well. Although the drilling project can be finished without
the optimal hydraulic parameters, the aim of the optimization process is to present the
most suitable properties which have high advantages for both safety and drilling
performance. Furthermore, the usage of optimal parameters provide the best solution
between system load and required power, thus lessen the wear on the system
components. Last but not least, the optimization of the hydraulic system of the well carries
timely and financial benefits, which is highly important for every company related to oil
well drilling. The effective optimization of a well drilling leads to fast and safe activity,
which is highly advantageous for the company, for the drilling rig and results further
benefit for the penetrated formations during completion and production. Also, this is the
way to avoid or reduce the risk of any environmental pollution or impairs.
My thesis clearly presents the highly cross-linked and complex system of well
hydraulics. Through the detailed analyses of Dip-1 well, it is clearly visible that the rig
installation always carries a lot of potential for hydraulic optimization, and the responsible
engineer have a lot of option to choose from. Based on the current requirement of the rig,
the formations or any of the many system components, the engineer can modify the
system to achieve the most advantageous method. The most important of all is the hole
cleaning property of the well, which must be maximized throughout the entire project. The
second is the hydraulic performance which aids the work of the drilling bit and enables the
appliance of higher ROP. From the analyzes of Dip-1 well, the impact of applied flow rate
and TFA on the hole cleaning and hydraulic performance is clearly visible. The effect of
flow rate on hole cleaning is much higher than on hydraulic performance, while the
modification of TFA can extremely improve the performance of well hydraulics. However,
the most important is always the fulfillment of the given requirements by providing the
most suitable installation and hydraulic parameters. The impact of the drilling mud
properties is also significant, because the mud is the active component of the hydraulic
system. The optimization of the fluid properties is always prior to the hydraulic
components, because it gives the basis of further improvement of the parameters.
The most important achievement of a proper hydraulic optimization is the increase of
ROP, which directly affects the amount of time required to completely drill down the well
and thus the overall cost of it. It is highly difficult to predict the exact amount of saved
expenses, but a day or two reduction in drill time means millions of Hungarian Forints for
63
the company. In case of my personally analyzed well, the increase of ROP is possible with
the optimized hydraulic system which means that the drill time of Dip-1 well could have
been reduced. While the theoretical optimization of the well hydraulics results in favorable,
improved values, the field experience proves that the effect of the well conditions and the
formation properties change the circumstances in a high level. Because of that, the
software can under- or overestimate the different required flow rate margins.
The optimization software cannot take the formation properties into consideration, and
due to that gives more preferable, but inaccurate results. The outcome of the theoretical
optimization always contains error to some degree, and the engineer must handle these
results with caution. The hydraulic optimization of every well should contain two steps, first
the calculation and optimal design of the hydraulic system should be done, and after that
the field engineer should test the recommended installation for practical results and give
feedback to the optimization engineer. This way, the effect of the practical field conditions
can be evaluated and the optimization process can be upgraded to a more precise level
Because of that, the most advisable method to ensure the proper hydraulic optimization
of the well is to establish a direct channel between the optimizing and the field engineer
and provide a system based on constant feedback. Nowadays, the usage of PWD
(Pressure While Drilling) tool is getting more and more frequent, which provides real-time
data on the annular and bore pressure of the well. The acquired data of the PWD can be
the basis of the constant, online optimization of every well in the future.
64
Acknowledgments
First and foremost I would like to thank to Tibor Szabó Dr. for his dedicated work and
helpful advices.
I also would like to thank to Attila Gurka Dr. my advisor from Mol Plc for the valuable time I
spent in Algyő and his guidance he provided throughout the entire paper.
I also owe special thanks to Mircea Subonj for the great deal of information they provided
for me during my thesis project and their immense field experience helped me overcome
on every difficulty I have encountered.
I owe a debt of gratitude to every faculty member of Mol Plc’s Algyő Facility for their
helpful advices and assistance throughout my entire work.
This thesis paper could not have been written without the generous help from University of
Miskolc Petroleum Engineering Department and Mol Plc.
65
References
1 Manual of Landmark’s WELLPLAN™ Software
Copyright © 2004 by Landmark Graphics Corporation
2 Drilling Fluids Engineering Manual Version 2.1
MI-SWACO LLC. 2007.
3 IFE PROPOSAL "Dip-1" Drilling Fluids Program
MI SWACO LLC. 2013
4 Daily Reports of "Dip-1" well
MOL Plc 2013
5 End Of Well Report of "Dip-1" well
MOL Plc 2013
6 Drilling Program of "Dip-1" well
MOL Plc 2013
7 Geotechnical Plan of Dip-1 well
MOL Plc 2013
8 Kien Ming Lim and G.A.Chukwu: Bit Hydraulics Analysis for Efficient Hole Cleaning
(SPE 35667, 1996)
9 A. Saasen and G. Løklingholm: The Effect of Drilling Fluid Rheological Properties
on Hole Cleaning
(SPE 74558, 2002)
Appendix A
1. Backreaming Rate (Maximum) Calculation
1.1
Where:
BRmax = Maximum backreaming rate (ft/hr)
ROPmax = Maximum rate on penetration (ft/hr)
Qcrit = Critical flow rate (gpm)
Qmud = Mud flow rate (gpm)
DP = Drill pipe ID (inch)
2. Bingham Plastic Rheology Model
Shear Stress – Shear Rate Model
2.1
Average Velocity in Pipe
2.2
Average Velocity in Annulus
2.3
Apparent Viscosity for Annulus
2.4
Apparent Viscosity for Pipe
2.5
Modified Reynolds Number for Annulus
2.6
Modified Reynolds Number for Pipe
2.7
Pressure Loss in Annulus
if Ra > 2000, then
2.8
if laminar flow, then
2.9
Pressure Loss in Pipe
if Rp > 2000, then
2.10
if laminar flow, then
2.11
Critical Velocity and Flow in Annulus
2.12
2.13
Critical Velocity and Flow in Pipe
2.14
2.15
Where:
D = Pipe inside diameter (ft)
Dp = Pipe outside diameter (ft)
DH = Annulus diameter (ft)
K = Consistency factor (lb/ft2 secn)
Vp = Average fluid velocity for pipe (ft/sec)
Va = Average fluid velocity for annulus (ft/sec)
Vca = Critical velocity in annulus (ft/sec)
Vcp = Critical velocity in pipe (ft/sec)
L = Section lenght of pipe or annulus (ft)
P = Pressure loss in pipe or annulus (lb/ft2)
Q = Fluid flow rate (ft3/sec)
Qca = Critical flow rate in annulus (ft3/sec)
Qcp = Critical flow rate in pipe (ft3/sec)
= Shear rate (1/sec)
= Shear stress (lb/ft2)
= Density of fluid (lb/ft3)
Rp = Reynolds number for pipe
Ra = Reynolds number for annulus
PVaa = Apparent viscosity for annulus (cp)
PVap = Apparent viscosity for pipe (cp)
PV = Plastic viscosity (cp)
PVx = Plastic viscosity (lb sec/ft2) = (PV/47880.26)
YP = Yield point (lb/100ft2)
YPx = Yield point (lb/ft2)
3. Bit Hydraulic Power
Bit Hydraulic Power is calculated using the flow rate entered int he input section of
the Rate dialog.
Bit Hydraulic Power can be used to select nozzle sizes for optimal hydraulics. Bit
Hydraulic Power is not necessarily maximized when operating the pumps at the
maximum pump horsepower. Bit Hydraulic Power is calculated using the following
equation:
3.1
Where:
Q = Circulation (pump) rate (gpm)
Pb = Pressure drop across bit nozzles (psi)
4. Bit Pressure Loss Calculations
Bit pressure drop represents the pressure losses through the bit.
4.1
Where:
= Fluid density (lb/ft3)
V = Fluid velocity (ft/sec)
Cd = Nozzle coefficient (0.95)
gc = 32.17 (ft/sec)
P = Pressure (lb/ft2)
5. Derivations for PV, YP, 0 Sec Gel and Fann Data
Derive PV, YP and 0 – sec Gel from Fann Data
5.1
5.2
5.3
Derive Fann Data from PV, YP and 0 – sec Gel
5.4
5.5
5.6
6. ECD Calculations
6.1
6.2
6.3
Where:
ECD = Equivalent Circulating Density (ppg)
Wmud = Fluid weight (density, ppg)
Ph = Hydrostatic pressure change to ECD point (psi)
Pf = Frictional pressure change to ECD point (psi)
= Change in pressure per lenght along the annulus
section (psi/ft) This is a function of the pressure loss
model chosen
DTVD = True vertical depth at the point of interest (ft)
= Annulus section lenght (ft)
0.052 = Conversion constant from (ppg)(ft) to psi
7. Hole Cleaning Methodology and Calculations
The hole cleaning model is based on a mathematical model thet predicts the critical
(minimum) annular velocities/flow rates required to remove or prevent a formation of
cuttings beds during a directional drilling operation. This is based ont he analysis of
forces acting ont he cuttings and its assiciated dimensional groups. The model can be
used to predict the critical (minimum) flow rate required to remove or prevent the
formation of stationary cuttings. This model has been validated with extensive
experimental and field data.
By using this model, the effects of all the major drilling variables on hole cleaning
have been evaluated and the results show excellent agreement between the model
predictions and all experimental and field results.
The variables considered for the hole cleaning analysis include:
Cuttings density
Cuttings load (ROP)
Cuttings shape
Cuttings size
Well path
Drill pipe rotation rate
Drill pipe size
Flow regime
Hole size
Mud density
Mud rheology
Mud velocity (flow rate)
Pipe eccentricity
Calculations and equation coefficients to describe the interrelationship of these
variables were derived from extensive experimental testing.
Calculate n, K, and Reynold’s Number
7.1
7.2
7.3
7.4
Concentration Based on ROP in Flow Channel
7.5
Fluid Velocity Based on Open Flow Channel
7.6
Coefficient of Drag around Sphere
if Re < 225 then
7.7
else,
7.8
Mud Carrying Capacity
7.9
Settling Velocity in the Plug in a Mud with a Yield Stress
7.10
Where:
a = 42.9-23.9n
b = 1-0.33n
Angle of Inclination Correction Factor
7.11
Cuttings Size Correction Factor
7.12
Mud Weight Correction Factor
if ( then
7.13
else
7.14
Critical Wall Shear Stress
7.15
Where:
a = 1.732
b = -0.744
Critical Pressure Gradient
7.16
Total Cross Sectional Area of the Annulus without Cuttings Bed
7.17
Dimensionless Flow Rate
7.18
Where:
a = 16
b = 1
Critical Flow Rate (CFR)
7.19
Correction Factor for Cuttings Concentration
7.20
Cuttings Concentration for a Stationary Bed by Volume
7.21
Where:
DB = Bit diameter
DH = Annulus diameter
DP = Pipe diameter
DTJ = Tool joint diameter
DC = Cuttings diameter
= Mud yield stress
Gfa = Power law geometry factor
RA = Reynold’s number
= Fluid density
= Cuttings density
Va = Average fluid velocity for annulus
VR = Rate of penetration (ROP)
VCTV = Cuttings travel velocity
VSO = Original slip velocity
VSV = Slip velocity
VCTFV = Critical transport fluid velocity
VTC = Total cuttings velocity
K = Consistency factor
n = Flow behavior index
a, b, c = Coefficients
YP = Yield point
PV = Plastic viscosity
QC = Volumetric cuttings flow rate
Qm = Volumetric mud flow rate
Qcrit = Critical flow rate for bed to develop
Qo = Cuttings feed concentration
CD = Drag coefficient
Cm = Mud carrying capacity
CA = Angle of inclination correction factor
CS = Cuttings size correction factor
Cmud = Mud weight correction factor
CBED = Correction factor for cuttings concentration
Cbonc = Cuttings concentration for a stationary bed by volume
Usp = Settling velocity
Us = Average settling velocity in axial direction
Umix = Average mixture velocity int he area open to flow
= Wellbore angle
= Bed porosity
= Apparent viscosity
= Plug diameter ratio
g = gravitational coefficient
r0 = Radius of wich shear stress is zero
rp = Radius of drill pipe
rh = Radius of wellbore or casing
Pgc = Critical frictional pressure gradient
= Critical wall shear stress
8. Bit Impact Force
Impact force is calculated using the flow rate entered in the input section of the Rate
dialog. Impact force is a parameter that can be used to select nozzle sizes for optimal
hydraulics. Impact force is calculated using the following equation:
8.1
Where:
= Fluid density (lb/ft3)
Q = Circulation rate (ft3/sec)
gc = Gravitational constant, 32.17 (ft/sec2)
V = Velocity through the bit (ft/sec)
9. Nozzle Velocity
Velocity is calculated using the flow rate entered in the input section of the
Rate dialog. This is not necessarily the maximum velocity that can be achieved through
the bits.
Nozzle velocity is a parameter that can be used to select nozzle sizes for optimal
hydraulics. Velocity is calculated using the following equation:
9.1
Where:
Q = Circulation rate (gpm)
A = Total Flow Area of bit (TFA – in2)
Optimization Planning Calculations
Although the Graphical Analysis and Optimization Planning analysis modes both
optimize bit hydraulics, the method used are different. Because the methods are
different, the results may also be different.
The following steps outline the general procedure used to perform an Optimization
Planning.
1. Determine the optimum flow rate
2. If the optimum flow rate is below the minimum annular velocity specified on the
Solution Constraints dialog, increase it until all annulus section have a velocity
greater than or equal to the minimum allowed.
3. If turbulent flow is not allowed (as specified ont he Solution Constraints dialog) and
any annulus section is in turbulent flow, decrease the optimum flow, so that no
annulus sections are in turbulent flow regime.
4. Select the actual bit jets from the optimum TFA and the number of nozzles and
minimum nozzle diameter specified on the Solution Constraints dialog. This will
almost always result in a TFA greater than the optimum.
5. If the total system pressure drop is less than the maximum pump pressure specified
on the Solution Constraints dialog, increase the flow rate to use 100% of the allowed
pump pressure. If the increase will violate the annular flow regime, it is ruled that
the increase is not allowed. The flow regime is controlling.
10. Optimization Well Site Calculations
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
Calculate parasitic pressure loss for optimum power
10.10
Calculate parasitic pressure loss for impact force
10.11
Calculate pressure loss allowed for bit at optimum flow rates
10.12
10.13
Calculate bit total flow area (TFA) for each bit pressure loss at optimum flow rates
10.14
10.15
Using the maximum number of nozzles and the minimum nozzle size,
determine the number and size of the nozzles equal the two total flow area values.
Where:
QL = Low flow rate (ft3/sec)
QH = High flow rate (ft3/sec)
QHP = Flow rate at optimum horse power (ft3/sec)
QIF = Flow rate at optimum impact force (ft3/sec)
A = Bit TFA used for the pressure test (ft2)
AHP = Bit TFA for optimum horse power (ft2)
AIF = Bit TFA for optimum impact force (ft2)
= Fluid weight (density – lbm/ft3)
C = Shape factor – 0.95 for bit
gc = Gravitational constant (ft/sec2)
S = Power law exponent for parasitic pressure loss
K = Power law coefficient for parasitic pressure loss (lbf/ft2)(sec/ft3)S
max = Maximum allowed total system pressure loss (lbf/ft2)
para = Parasitic pressure loss at specific flow rate (lbf/ft2)
sys = Total system pressure loss at specific flow rate (lbf/ft2)
bitH = Bit pressure loss at pressure test high flow rate (lbf/ft2)
bitL = Bit pressure loss at pressure test low flow rate (lbf/ft2)
paraH = Parasitic pressure loss at pressure test high flow rate (lbf/ft2)
paraL = Parasitic pressure loss at pressure test low flow rate (lbf/ft2)
paraHP = Parasitic pressure loss at flow rate QHP (lbf/ft2)
paraIF = Parasitic pressure loss at flow rate QIF (lbf/ft2)
11. Power Law Rheology Model
Rheological Equation
11.1
Flow Behavior Index
11.2
Consistency Factor
11.3
Average Velocity in Pipe
11.4
Average Velocity in Annulus
11.5
Geometry Factor for Annulus
11.6
Geometry Factor for Pipe
11.7
Reynold’s Number for Pipe
11.8
Reynold’s Number for the Annulus
11.9
Critical Reynold’s Number for Pipe
Laminar Boundary = 3470 – 1370n
Turbulent Boundary = 4270 – 1370n
Critical Reynold’s Number for Annulus
Laminar Boundary = 3470 – 1370n
Turbulent Boundary = 4270 – 1370n
Friction Factor for Pipe
Laminar
11.10
Transition
11.11
11.12
11.13
11.14
Turbulent
11.15
11.16
11.17
Friction Factor for Annulus
Laminar
11.18
11.19
11.20
11.21
11.22
Turbulent
11.23
11.24
11.25
Pressure Loss in Pipe
11.26
Pressure Loss in Annulus
11.27
Where:
D = Pipe inside diameter (ft)
DP = Pipe outside diameter (ft)
DH = Annulus diameter (ft)
Vp = Average fluid velocity for pipe (ft/sec)
Va = Average fluid velocity for annulus (ft/sec)
L = Pipe or annulus section lenght (ft)
P = Pipe or annulus pressure loss (lb/ft2)
Q = Fluid flow rate (ft3/sec)
= Shear stress on walls (lb/ft2)
n = Flow behavior index
K = Consistency factor
= Fluid density (lbm/ft2)
RP = Reynold’s number for pipe
RA = Reynold’s number for annulus
RL = Reynold’s number at laminar flow boundary
FP = Friction factor for pipe
FP = Friction factor for annulus
GP = Geometry factor for pipe
GA = Geometry factor for annulus
PV = Plastic viscosity
YP = Yield point
gc = Acceleration due to gravity (32.174 – ft/sec2)
12. Pressure Loss Analysis Calculations
The following general analysis steps are used to determine pressure losses in
the various segments of the circulating system. The annular velocity or critical velocity
calculations are performed within the pressure loss calculations.
1. The first step is to calculate PV, YP, 0 – sec Gel and Fann data as required. The
Bingham Plastic and Power Law pressure loss calculations require PV/YP data. If
Fann data is input, PV/YP/0 – sec Gel can be calculated. Herschel-Bulkley model also
requires Fann data. If Fann data not is input on the Fluid Editor, it can be calculated
from PV/YP/0 – sec Gel data.
2. Calculate work string and annular pressure losses based ont he rheological model
selected using the Bingham Plastic rheology model calculations, Power Law rheology
model calculations or Herschel-Bulkley rheology model calculations.
3. Calculate the bit pressure loss.
4. Calculate tool joint pressure losses, if required as specified ont he Rate Dialog or the
Rates Dialog.
5. Determine mud motor or MWD pressure losses as input ont he Mud Motor Catalog
or the MWD catalog.
6. Calculate the pressure losses int he surface equipment using the pipe pressure loss
equations for the selected rheological model.
7. Calculate the total pressure loss by adding all pressure losses together.
8. Calculate ECD if reuired.
13. Pump Power Calculations
If more than one pump are in use the maximum pump power should be
calculated as follows,
13.1
Where:
N = 1 to number of HP mud pumps
Pmin = Minimum pump pressure of all maximum pump discharge
pressure ratings for pumps active in the system and the
surface equipment
Pmax = Maximum pump pressure rating for each pump, 1 thru n
HPS = Maximum pump horse power for the system
14. Pump Pressure Calculations
If there are more then one active pump specified on the Circulating System,
Mud Pumps tab, the Maximum Pump Pressure will be set equal to the minimum value
entered for Maximum Discharge Pressure for any of the active pumps.