report file

TABLE OF CONTENTS :

Sr. no Topics Page no.

1 Certificate 3

2 Acknowledgement 4

3 Introduction 5-6

4 Directional drilling 6-8

5 Parameters for drilling optimization 8-10

6 Weight on Bit 11-15

7 RPM 15-18

8 GPM 18-20

9 Case Study 20-24

10 Tools used in JDIL workshop 25-39

11 Proposed solution (new technology) 40-46

12 References 47

CERTIFICATE

This is to certify that the work contained in this report titled ―“Optimization

of drilling parameters in directional drilling” has been carried out by

Hitisha Dadlani

Ketul Khambayata

Nikhil Gupta

Raj Rathod

Satyam Uppal

Shivam Misra

under supervision of Mr. Satish Jawanjal, General Manager, Directional

Drilling, JINDAL DRILLING AND INDUSTRIES LIMITED and has not been

submitted previously here as a Project.

Mr. Satish Jawanjal,

Mentor

ACKNOWLEDGEMENT

We are highly obliged to Jindal Drilling and Industries Limited and our

mentor Mr. Satish Jawanjal, General Manager, Directional Drilling, JDIL for

giving us such a wonderful platform in the form of project titled “Optimization

of drilling parameters” and necessary infrastructure to enhance our practical

learning experience. On behalf of our college/university, we express sincere

gratitude towards “Jindal Drilling and Industries Limited” for giving us an

opportunity to pursue our winter internship program in such a renowned

organization.

Next, we wish to express our gratitude to Mr. S.P. Thapliyal for providing

valuable information related to the project. We are indebted to all personnel in

Nagothane workshop who helped in our understanding and cleared all doubts

on different equipment.

We are also thankful to the entire HR team that facilitated our internship.

Also, we are grateful to Ms. Tanu Garg, Ms. Reila Chakraborty and all the

JDIL employees for helping us in learning about the business flow and

practicality of the activities that we gained during the course of internship.

Mr. Satish Jawanjal,

Mentor

INTRODUCTION

Future oilfield resource developments are subject to drill wells in cost efficient

manners. For that reason future management of oilfield drilling operations will

face new hurdles to reduce overall costs, increase performances and reduce

the probability of encountering problems. Drilling wells for energy search from

the ground has shown considerable technological advances in the recent

years. Different methods from different disciplines are being used nowadays in

drilling activities in order to obtain a safe, environmental friendly and cost

effective well construction. Communication and computer technologies are

among the most important disciplines, which can contribute to drilling

optimization.

From the very early beginning of the drilling campaigns the operators have

always been seeking to reduce the drilling costs mainly by increasing the

drilling speed. In the drilling industry, the first well drilled in a new field (a

wildcat well) generally will have the highest cost. With increasing familiarity to

the area optimized drilling could be implemented decreasing costs of each

subsequent well to be drilled until a point is reached at which there is no more

significant improvement [1]. The relationship among drilling parameters are

complex, the effort is to determine what combination of operating conditions

result in minimum cost drilling [2]. The generally accepted convention for a

proper planning of any drilling venture is to optimize operations and minimize

expenditures [3]. Another essential aspect of the optimization is to enhance

the technology and make the system effective [4]. Recently environmental

friendly activities have also started to be common practice in certain locations,

which in turn could be achieved by means of reducing the risks associated

with having technical problems.

In recent years the increasing emphasis that is being paid by the oil and gas

field operator companies towards working much efficiently at the rig sites are

based on some important reasons. The most important of all are: cost and

trouble free operations. During a peak in the cost of hydrocarbon resources,

the rig supplier and oil field service provider contractor charges are increasing,

pushing operators to work efficiently. Due to the complexity of the activities

being offshore and/or being in the form clusters operators restraining

themselves from causing a damage, which may result in destruction of more

than one well due to their proximity between each other being very close.

Directional techniques allowed drilling multiple wells from one location, thus

eliminating construction of expensive structures for each well [5]. Due to the

drilling requirements similarity of the wells located at close distances,

collecting past data, and utilizing in a useful manner is considered to have an

important impact on drilling cost reduction provided that optimum

parameters are always in effect.

Major drilling variables considered to have an effect on drilling rate of

penetration (ROP) are not fully comprehended and are complex to model [6].

For that very reason accurate mathematical model for rotary drilling

penetration rate process has not so far been achieved. There are many

proposed mathematical models, which attempted to combine known relations

of drilling parameters. The proposed models worked to optimize drilling

operation by means of selecting the best bit weight and rotary speed to achieve

the minimum cost. Considerable drilling cost reductions have been achieved

by means of using the available mathematical models.

DIRECTIONAL DRILLING

There are three basic well profiles which include the design of most directional wells:

1. Type one: Build and hold trajectory. This is made up of a kick off point, one build up section and a tangent section to target.

2. Type two: S -Shape trajectory. This is made up of a vertical section, kickoff point, build-up section, tangent section, drop-off section and a hold section to target.

3. Type three: Deep Kick off trajectory. This is made up of a vertical section, a deep kick off and a build up to target.

Another secondary type is horizontal wells. A horizontal well is a well which can have any one of the above profiles plus a horizontal section within the reservoir. The horizontal section is usually drilled at 90 degrees.

The following are methods of Kick-off:

• Jetting deflection

• Whipstock deflection

• Motor deflection

• Rotary Steerable deflection

Jetting Deflection (Badger bit)

This is an old technique which is rarely used today. It relies on hydraulics to deviate the wellbore and is therefore only effective in soft formations. A special jet bit, is often used, but it is possible to use a normal soft formation bit, using one very large nozzle and 2 small jet nozzles. The large jet nozzle is the "toolface".The fluid coming out from the large nozzle causes the maximum formation erosion and allows the well to be, effectively, deflected in the direction of the jet coming out of the big nozzle. Jetting usually causes high dogleg severities.

Whipstock Deflection

The whipstock is widely used as a deflecting medium for drilling multilateral wells.It consists of a long inverted steel wedge (shute) which is concave on one side to hold and guide a deflecting drilling or milling assembly. It is also provided with a chisel point at the bottom to prevent the tool from turning, and a heavy collar at the top to withdraw the tool from the hole, Figure 11.23.

Today, whipstocks are mainly used to mill casing windows for sidetracking existing wells.

Motor Deflection

The motor is designed with an in-built bent housing below the motor section; usually the connecting rod housing. The bent housing angle is usually 0.25-1.5 degrees and is designed to tilt the axis of the bit relative to the axis of the hole.The reader should note that having only a small bit offset will create a considerable bit side force (deflecting force).

A steerable motor can be used in oriented mode (sliding) or rotary mode.In the sliding mode, the drillstring remains stationary (rotary table or top-drive is locked) while the drillbit is rotated by the motor. The course of the well is only changed when drilling in sliding mode as the drillbit will now follow the curvature of the motor bent housing. In rotary mode, the steerable motor becomes "locked" with respect to trajectory and the hole direction and

inclination are maintained while drilling. The use of steerable motors with the correct drillbit and BHA reduces the number of round trips required to produce the desired inclination/azimuth.

Single shot surveys are not usually accurate in orienting steerable motors due to the high reactive torque produced by the motor. For this reason, most steerable motor assemblies are run with an MWD (measurement while drilling) tool to provide real time survey and orientation data. A steerable motor with an MWD tool is described as Steerable System.

Steerable motors are usually used to drill complete sections of a well, from current casing shoe to next casing point.

Rotary Steerable System

These systems do not use bent subs for affecting hole angles. Changes in hole angles are brought about by the action of three pads contained within a non-rotating sleeve. The pads are kept in constant contact with the formation by internal mud powered actuators. If no angle change is required, the system is put in neutral mode by pushing the pads in every direction thereby cancelling each other.

If changes in angle and direction are required, the electronics within the instruments cause each pad to extend against the side the hole opposite the intended bias direction. The resultant action of these forces then cause the bit to build or drop angles as required. Signals can be sent from surface to the instrument downhole as is the case with most current rotary steerable systems or the hole inclination and direction are programmed into the instrument at surface and the instrument then automatically corrects the hole trajectory without driller’s intervention.

PARAMETERS FOR DRILLING OPTIMIZATION

The following are the parameters for drilling optimization:-

1. Weight on Bit

2. Revolution per minute.

3. Pump Parameters(GPM & SPM)

4. Mud Parameters

5. Rate of Penetration

Basic Definition:-

Weight on Bit:- is the amount of downward force exerted on the drill bit and is

normally measured in thousands of pounds.

Revolution per minute: - Revolutions per minute is a measure of

the frequency of rotation, specifically the number of rotation around a fixed

axis in one minute.

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

The rate of penetration increases from point a to point d with an increase in the weight on the drill bit, but a decrease in the rate of penetration is suddenly observed from point d to point e with increase in the weight on the drill bit. The rate of penetration also increases with the rotary speed while other drilling variables held constant. The rate of penetration usually increases linearly with low rotary speed, but at higher values of rotary speed the rate of penetration begins to decreases. The reason for decrease in the rate of penetration is due to poor hole cleaning. Mud Properties:-

Mud weight selection in a drilling program is a key factor in avoiding

various borehole problems. It is essential to select the correct mud

weight for drilling the individual sections. The following must be

considered when selecting mud weight:

1. A very low mud weight may result in collapse and well cleaning

problems.

2. A very high mud weight may also result in mud losses or pipe

sticking.

3. Excessive variation in mud weight may also lead to borehole

failure; as such a more constant mud weight must be aimed at.

The rate of penetration is also affected by the properties of drilling fluid

used during drilling. These properties include: rheological properties,

filtration characteristics, solids content and size distribution, and chemical

composition. The rate of penetration tends to decrease with increasing fluid

density, viscosity and solids content, and tends to increase with increasing

filtration rate. The density, solid content, and filtration characteristics of

the mud control the pressure differential across the zone of crushed rock

beneath the bit. The fluid viscosity controls the system frictional losses in

the drill string and thus the hydraulic energy available at the bit jets for

cleaning. The most important factor out of the drilling fluid properties is the

density, differential pressure tends to increase with increasing density, and

the rate of penetration decreases with increasing differential pressure.

Weight on bit (WOB)

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

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

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

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

Figure (a)

Figure (b) Figure (c)

Figure (d) Figure (e)

REVOLUTIONS PER MINUTE (RPM)

What is RPM? Revolutions per minute (abbreviated rpm, RPM, rev/min, r/min) are a measure of the frequency of rotation, specifically the number of rotations around a fixed axis in one minute. It is used as a measure of rotational speed of a mechanical component.

RPM in Drilling It represents the rotational speed of the drill string. With the invention of TDS; the reading is directly linked to the electronics of the unit itself. It is considered that the measurements for this parameter are accurate as long as the acquisition system set-up has been thoroughly made up.

https://en.wikipedia.org/wiki/Frequency

https://en.wikipedia.org/wiki/Rotation

https://en.wikipedia.org/wiki/Rotation_around_a_fixed_axis

https://en.wikipedia.org/wiki/Rotation_around_a_fixed_axis

https://en.wikipedia.org/wiki/Minute

https://en.wikipedia.org/wiki/Rotational_speed

https://en.wikipedia.org/wiki/Rotational_speed

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

Figure a: Effect of Drilling Rate vs Rotary Speed (RPM)

Figure b: Effect of Drilling Rate vs Rotary Speed (RPM)

The graphical representation in Fig. a and b shows the nature of drilling rate

with increasing rotary speed, from which we can conclude that ROP increases

with increasing RPM, which further depends on the type of formation as well,

Figure c : Effect of Penetration / Revolution vs Rotary Speed (RPM)

The situation containing different values for WOB can be generated to create

the cumulative effect of RPM as well as WOB as shown in fig.c, it is being

observed that with increase in rotary speed causes decrease in penetration

where the slope of the extent of the decrease depends on WOB.

Figure d : Effect of Bearing Life (HRS) vs Rotary Speed (RPM)

Figure e: Effect of Wear Rate vs Rotary Speed (RPM)

It has been observed that higher rotary speeds results in wear and damage the

bearings, the life of different equipments decreases with increase in rotary

speed. So it is very essential to optimize maximum rotary speed with

minimum wear.

Figure f: Effect of Cost of drilling vs Rotary Speed (RPM)

Finally, the ultimate aim to this approach is to accomplish maximum work in

minimum time at the cheapest possible cost, so we derive a relation between

drilling cost and RPM, which is non-linear graph, as at extremely high ROP

tools get damaged, adding up the cost.

GPM

This is one of the most important factors in maintaining the drilling ROP of

the well. GPM, simply stands for Gallons Per Minute, is a unit for flow rate

measurement; and in this case the flow rate of the drilling fluid from the mud

pumps is registered in GPM. Thus whenever we come across the term GPM, it

directly refers to the pumping in flow rate of the drilling mud from the mud

pump/s (Duplex or Triplex).

GPM is a dynamic value depending upon the pump configuration and the

pump efficiency. Apart from these, frictional losses in the transmission pipes

are also a determining factor the eventual GPM of the system.

Importance :

Hole cleaning (lifting drill cuttings): The primary GPM maintenance

depends on the hole size and depth at which the drilling is going on.

Larger and deeper wells will require a higher GPM so as to clean the

open hole section in minimum time so as to avoid any static filter cake

formation thus lowering the chances of held up and stuck ups due to

differential pressure inside the well bore against the wellbore wall.

Inadequate GPM ( lower than what is required) will result in thick mud

cake formation in deep wells and in larger hole sections resulting in

stuck ups. On the contrary very high GPM will result in high probability

of mud cut in tubulars. Thus efficient management is required in

deciding the GPM with respect to a particular well profile.

Transferring hydraulic horsepower : This is another aspect in

determining the GPM. This aspect can be studied in two ways, i.e. in the

sliding and the rotary mode respectively.

Lets discuss about the sliding mode where in the hydraulic power is to

be transferred to the power section of the SDMM assembly implying the

dependence on the rotor stator configuration of the power section. GPM

depends upon the torque required to drive the given power section, i.e.

high torque requirement implies high GPM. In the power sections, high

torque is achieved by increasing the no. of stages and number of lobes of

the rotor. Thus, for such a configuration higher GPM is required. Vice

versa for low torque configuration of the mud motor.

In the rotary motion of the string, higher GPM implies, higher hydraulic

force transfer onto the formation surface aiding in chipping through the

formation producing substantially better ROP than in a lower GPM

configuration.

Dependence on WOB- This aspect is directly related to the driving of the

power section through the transfer of hydraulic HP of the flowing drilling

mud. Whenever the WOB is increased in sliding mode, additional torque

requirement is there as a direct axial force acts upon the SDMM. To

overcome this barrier, GPM is increased so as to increase the differential

pressure across the power section which, in turn, increases the torque

delivered to the power section hence, stalling of the power section is

prevented.

Well control:- as we know, the mud circulation at a drilling rig is a closed

loop system, thus principles of conservation of energy and mass are

applicable. Thus, we can safely say, in ideal conditions, the rate at which

mud enters the wellbore should be equal to the rate at which the mud

exits. Normal filtrate losses are prevalent universally hence, the rates are

not exactly similar but, approximately comply with each other. If the

filter losses are increased due to low pressure zones or caving in of

wellbore, a substantial difference between the two rates is observed.

Hence, the GPM is increased to keep the wellbore full of mud and well

control procedures are commenced.

CASE STUDY

Case study 1:

Well Name: X

Field Name: ABC

Well profile: Deviated ‘L’ Profile

Kickoff depth: 865m

Drift: 354±50m to be achieved at 1754m TVD.

Maximum Planned inclination- 28.07°.

CSD: 858m

Observing the drilling of Hole Size 12 ¼’’.

Key observations:

Depth: 858m

Further drilling calls for the usage of the modified BHA i.e. the inclusion of the

mud motor (8” SDMM) from the casing shoe.

Directional drilling commences from CSD till 1022m without any substantial

NPT.

In the following days, Mud pump failures occurred (pump took in air, piston

failures, Screen replacements.) and POOH had to be done. Initial POOH was

smooth but tight pull observed near the CSD which were cleared by

reciprocation easily.

Mud pump maintenance had to be carried out. Upon the commencement of

drilling, a good ROP was observed till 1056m. Further, fall in ROP was

observed even when the mud pumps were supplying the adequate amount of

SPM (=110 SPM) and the RPM was recorded 45 r/min.

RPM was increased to 65 r/min but no substantial increase in the ROP was

observed and finally WOB (initially at 6-7T) was increased along with the

increased RPM. (Final WOB was recorded to be 8-10T).

S/N Depth in and

out

(m)

SP Pressure

(psi)

SPM

Mud Pump#

1

SPM

Mud Pump

#2

Flow Rate

(GPM)

ROP (mts/hr)

WOB (Ton)

RPM

Initiall

1056-1148 1600 55 55 568 8.12 6-7 45

Trial 1

1148-1315 1800 55 55 590 10.23 6-7 65

Trial 2

1315-1456 1900 60 55 598 16.48 8-10 65

Depth (m) Formation

858 - 1056 Sandstone (Soft )

1056 - 1148 Shaly Sandstone

1148 - 1315 Shale

1315 - 1456 Shale

Inferences:

Formation change from the given depth of concern is implied. A harder

formation is being drilled than the previous. RPM wasn’t sufficiently enough to

increase the ROP.

Hence WOB, was a pivotal factor in increasing the ROP.

Further, in the same well,

Depth: 1456m

Activity: Drilling

Bit Change: from TCR(18x3) to PDC(17x7).

WOB: 8-10T

Observations:

No substantial increase in the ROP was there even the TCR bit was changed to

the PDC one. POOH was carried out and the bit was changed to TCR again

with a different configuration (20x3) and the mud pumps were not able to

pump in the required SPM.

The Replaced TCR bit was accompanied with a decrease in WOB (6-7T). The

required ROP was attained.

Inference:

Lower WOB is preferred for TCR bits for Bit Life Increment.

Case Study 2 :

Well Name: Y

Block Name: Z

Well Profile: Deviated ‘L’ Profile

Kickoff: 560m MD

Drift: 480m to be achieved at 2758.7m MD.

Maximum Planned inclination 26.04°

Planned direction: 232.46°


Key observations:

Depth: 2758.7m

To drill a directional well with kick off from 560m MD up to a depth of

2758.7m MD

Cement plug was placed for side tracking

To signify the effect of RPM, a situation is taken where a soft formation is

being encountered at the depth of 1353m MD

Changes in WOB and ROP are being made in order to optimize the situation

Motor configuration used (SDMM): 7/8

Time Depth

(m) Bit

type Formation

SP Pressure

(psi)

SPM Mud

Pump

Flow Rate

(GPM)

ROP (m/h

r)

WOB (Ton)

RPM (r/mi

n)

Initial 0 PDC

soft 850-950 95 450 9.6 5-6 45

Trial 1

1317 PDC

soft 1400 -1500

110 520 1.2 5-7 45

Trial 2

1353 PDC

soft 1600 -1700

120 545 2.8 5-7 70

Inferences:

In order to optimize the situation, the WOB is decreased from 8-9 ton to 5-7

tons as it is a soft formation

While the RPM is kept at 70, comparing the values of ROP as per the above

table, all the values are equal, with different values of RPM, which gives higher

ROP corresponding to higher values of RPM.

Case study 3:

Well Name: XYZ

Field Name: ABC

Well Profile: Deviated ‘L’ Profile

Kickoff depth: 865m

Drift: 354±50m to be achieved at 1754 TVD.

Maximum Planned inclination 28.07°.

CSD: 858m


KEY OBSERVATIONS

Observations at depth 1244m –

Drilling mode- Sliding and rotary

It was observed that the initial build up was smooth till the depth of 1244m.

POOH had to be carried out for bit change, during the same, tight pull was

observed at depths of 1176, 1116, 980 and 832m. The first three conditions

were released by reciprocation but, the last one had to be released by

circulation and rotation using Kelly, thereby increasing the NPT. It was

observed that the GPM transferred by the two mud pumps was 465 g/min,

which is much lower than the standard value of 580-650 g/min for a 121/4”

hole. It was due to the inefficiency of mud pump 1, whose SPM was maximum

40, and the cumulative SPM of both pumps was below 105 strokes/min.

INFERENCE

Due to inadequate GPM, improper hole cleaning became a menace, due to

which, 4 tight pulls occurred, with 1 requiring the use of Kelly

On further drilling in the same well, in the build up section, low ROP was

being registered. The WOB was subsequently increased from 6-7 tons (initial)

to 8-10 tons (final). The cumulative SPM of mud pumps was increased to 110

strokes/min and GPM was increased from 540 to 595 g/min. On further

drilling, in sliding mode, desired ROP was attained.

ANALYSIS OF WORKSHOP TENURE

i. Down hole Mud Motors

There are two major types of down hole motors powered by mud flow;

1) The turbine, which is basically a centrifugal or axial pump and

2) The positive displacement mud motor (PDM).

Turbines were in wide use a number of years ago and are seeing some increased use lately but the PDM is the main workhorse for directional

drilling.

Four configurations of drilling motors provide the broad range of bit speeds and torque outputs required satisfying a multitude of drilling applications. These configurations include:

High Speed / Low Torque

The high speed drilling motor utilizes a 1:2 lobe power section to produce high speeds and low torque outputs. They are mostly used when drilling with a

diamond bit and tri-cone bit drilling in soft formations.

Medium Speed / Medium Torque

The medium speed drilling motor typically utilizes a 4:5 lobe power section to produce medium speeds and medium torque outputs. They are commonly used in most conventional directional and horizontal wells, in diamond bit and

coring applications, as well as sidetracking.

Low Speed / High Torque

The low speed drilling motor typically utilizes a 7:8 lobe power section to produce low speeds and high torque outputs. They are used in directional and horizontal wells, medium to hard formation drilling, and PDC bit drilling

applications.

Components

All drilling motors consist of five major assemblies:

Dump Sub Assembly Power Section Drive Assembly Adjustable Assembly

Sealed or Mud Lubricated Bearing Section.

The gear reduced drilling motor contains an additional section, the gear reducer assembly located within the sealed bearing section. Some other motor

manufacturers have bearing sections that are lubricated by the drilling fluid.

Dump Sub Assembly

As a result of the power section, the drilling motor will seal off the drill string ID from the annulus. In order to prevent wet trips and pressure problems, a dump sub assembly is utilized. The dump sub assembly is a hydraulically actuated valve located at the top of the drilling motor that allows the drill string to fill when running in hole, and drain when tripping out of hole. When the pumps are engaged, the valve automatically closes and directs all drilling

fluid flow through the motor.

In the event that the dump sub assembly is not required, such as in underbalanced drilling using nitrogen gas or air, its effect can be negated by simply replacing the discharge plugs with blank plugs. This allows the motor

to be adjusted as necessary.

Power Section

The drilling motor power section converts hydraulic power from the drilling fluid into mechanical power to drive the bit. The power section is comprised of two components; the stator and the rotor. The stator consists of a steel tube that contains a bonded elastomer insert with a lobed, helical pattern bore through the centre. The rotor is a lobed, helical steel rod. When the rotor is installed into the stator, the combination of the helical shapes and lobes form sealed cavities between the two components.

When drilling fluid is forced through the power section, the pressure drop across the cavities will cause the rotor to turn inside the stator. This is how

the drilling motor is powered.

It is the pattern of the lobes and the length of the helix that dictate what output characteristics will be developed by the power section. By the nature of

the design, the stator always has one more lobe than the rotor.

The second control on power section output characteristics is length. A stage is defined as a full helical rotation of the lobed stator. Therefore, power sections may be classified in stages. A four stage power section contains one more full rotation to the stator elastomer, when compared to a three stage. With more stages, the power section is capable of greater overall pressure

differential, which in turn provides more torque to the rotor.

As mentioned above, these two design characteristics can be used to control

the output characteristics of any size power section.

In addition, the variation of dimensions and materials will allow for specialized drilling conditions. With increased temperatures, or certain drilling fluids, the stator elastomer will expand and form a tighter seal onto the rotor and create more of an interference fit, which may result in stator elastomer damage. Special stator materials or interference fit can be requested for these

conditions.

Drive Assembly

Due to the design nature of the power section, there is an eccentric rotation of the rotor inside of the stator. To compensate for this eccentric motion and convert it to a purely concentric rotation drilling motors utilize a high strength jointed drive assembly. The drive assembly consists of a drive shaft with a sealed and lubricated drive joint located at each end. The drive joints are designed to withstand the high torque values delivered by the power section while creating minimal stress through the drive assembly components for extended life and increased reliability. The drive assembly also provides a point in the drive line that will compensate for the bend in the drilling motor

required for directional control.

Adjustable Assembly

Most drilling motors today are supplied with a surface adjustable assembly. The adjustable assembly can be set from zero to three degrees in varying increments in the field. This durable design results in wide range of potential build rates used in directional, horizontal and re-entry wells. Also, to minimize the wear to the adjustable components, wear pads are normally located

directly above and below the adjustable bend.

Sealed or Mud Lubricated Bearing Section

The bearing section contains the radial and thrust bearings and bushings. They transmit the axial and radial loads from the bit to the drill string while providing a drive line that allows the power section to rotate the bit. The bearing section may utilize sealed, oil filled, and pressure compensated or mud lubricated assemblies. With a sealed assembly the bearings are not subjected to drilling fluid and should provide extended, reliable operation with minimal wear. As no drilling fluid is used to lubricate the drilling motor bearings, all fluid can be directed to the bit for maximized hydraulic efficiency. This provides for improved bottom-hole cleaning, resulting in increased

penetration rates and longer bit life. The mud lubricated designs typically use tungsten carbide-coated sleeves to provide the radial support. Usually 4% to 10% of the drilling fluid is diverted pass this assembly to cool and lubricate the shaft, radial and thrust bearings. The fluid then exits to the annulus

directly above the bit/drive sub.

Hydraulics

The use of a PDM in the drill string changes the hydraulic calculations and should be considered. Various factors have to be taken into account. These

are:

1. Range of flow rates allowable: Each size and type of PDM is designed to take a certain range of volumes of fluid.

2. No-load Pressure Loss: When mud is pumped through a mud motor which is turning freely off-bottom (i.e. doing no work) a certain pressure loss is needed to overcome the rotor/stator friction forces and cause the motor to

turn. This pressure loss and motor RPM are proportional to flow rate.

3. Pressure Drop across the Motor: As the bit touches bottom and effective WOB is applied, pump pressure increases. This increase in pressure is normally called the motor differential pressure. Motor torque increases in direct proportion to the increase in differential pressure. This differential pressure is required to pump a given volume of mud through the motor to

perform useful work. For a multi-lobe motor, it can be 500 psi or even more.

4. Stall-out Pressure: There is a maximum recommended value of motor differential pressure. At this point, the optimum torque is produced by the motor. If the effective WOB is increased beyond this point, pump pressure

increases further. This is known as stall-out condition.

Studies have shown that the power output curve is a parabola and not a smooth upward curve, as originally thought. If the PDM is operated at 50%-60% of the maximum allowable motor differential pressure, the same performance should be achieved as when operating at 90% of differential. The former situation is much better however there is a much larger ‘cushion’

available before stall-out.

5. Rotor Nozzle: Most multi-lobe motors have a hollow rotor. This can be blanked off or jetted with a jet nozzle. When the standard performance range for the motor matches the drilling requirements, a blanking plug is normally fitted. The selection of the rotor nozzle is critical. Excessive bypass will lead to a substantial drop in motor performance and, consequently, drilling efficiency.

If a rotor nozzle is used at lower flow rates, the power of the motor will be

greatly reduced.

DRILLING JAR

Basic Definition:

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

vibrational loading associated with drilling.

Bico Jars

Mechanical jars operate using a series of springs, lock and release mechanisms. Hydraulic jars operate using the controlled passage of hydraulic fluid. Hydro mechanical jars are a hybrid of designs, usually hydraulic up and

mechanical down.

The jars of three different sizes are being used by Jindal Drilling: 43/4 in,

61/2 in, 8 in.

Hydraulic Mechanical Jar Components:

1. Mandrel 2. Pressure Cylinder 3. Upper Flex Joint 4. Kelly Stabilizer 5. Kelly Mandrel 6. Drive Cylinder 7. Bottom Sub 8. Connector Sub 9. Lower Flex Joint

10. Knocker

MEASUREMENTS WHILE DRILLING(MWD)

As early as the 1960’s, companies were experimenting with ways to log formations during drilling, but, technologically, it was difficult to build tools that could withstand the harsh down hole environment and transmit reliable data. A spinoff of the effort to overcome the problem was recognition that inclination, direction, and tool face angle could be measured during drilling and the data could be transmitted to the surface. This leads to the

development of MWD tools.

Various transmission methods were used- such as electromagnetic, acoustic, pressure pulse, pressure-pulse modulation, or cable and drill pipe. Of all the transmission methods, the pressure-pulse and pressure-pulse modulation methods have evolved into commercial systems often used by the directional

drilling community.

The main benefits of MWD are- (1) Borehole navigation. (2) Drilling efficiency and safety.

(3) Geological information in real time.

BASIC MWD THEORY

Telemetry Systems

Commercial MWD Systems use Mud Pulse Telemetry to transmit survey data during tool operation. In Mud Pulse Telemetry (Figure 4.14) the mud pressure in the drill string is modulated to carry information in digital form. Pressure pulses are converted to electric voltages by a transducer installed in the pump discharge circuit (Figure 4.15). Then this information is decoded by the surface equipment. Tool measurements are digitized downhole. The measured values are transmitted to the surface as a series of zeros and ones. The

surface panels recognize these as representations of tool measurements

MWD Process Schematic MWD Pressure Transducer

There are three telemetry systems in common use today. Positive pulse telemetry uses a flow restrictor which when activated increases stand pipe pressure. Negative pulse tools have a diverter valve that vents a small amount of mud flow to the annulus when energized. This decreases standpipe pressure momentarily. Standing (or continuous) wave pulses, also known as mud sirens, use rotating baffled plates which temporarily interrupt mud flow, creating a pressure wave in the standpipe. Changes in relative rotation speed of the plates changes the wave phasing. These phase changes are identified at

the surface and decoded.

Advantages

Positive Pulse Systems are commonly used in current MWD & LWD. This may be because the generation of significant sized negative pulse requires pressure drop across BHA, which reduces hole cleaning capacity of fluid.

Simplicity over other methods. No special drill pipe is required. No complication due to wire line in the hole.

Only minor alterations to normal drilling practices are necessary.

Disadvantages

The pressure pulses travel through mud column at around 4000 -5000 ft/sec, but there is limit to the amount of information that can be sent in real time.

It does not work in compressible fluids.

MWD Telemetry

MWD Tool Features Efficient Economical Retrievable and Reinsert able Modular Design Short radius application Standard Non Magnetic Drill Collars (NMDC) Power Conversation Efficient Encoding/decoding Safe Area System

Components of MWD tool Dummy switch Electronic module Centralizer Battery Gamma ray tool Pulsar driver

Stinger Assembly

Dummy Switch It is the up hole end component of the MWD tool. It helps in lowering down the tool and retrieving the tool when stuck up takes place. The MWD tool can be retrieved with the help of an overshot assembly.

Dummy Switch Electronic Module

Electronic Module

The electronic module is also known as direction and inclination module. The Directional Sensor is made up of electronic printed circuit boards, a Tensor Tri-Axial Magnetometer and a Tensor Tri-Axial Accelerometers, and Temperature sensor. These modules are configured into a directional probe and are run in the field mounted in a nonmagnetic drill collar. The Directional Sensor provides measurements, which are used to determine the orientation of the drill string at the location of the sensor assembly. The Directional Sensor measures three orthogonal axis of magnetic bearing, three orthogonal axes of inclination and instrument temperature. These measurements are processed and transmitted by the pulser to the surface.

The surface computer then uses this data to calculate parameters such as inclination, azimuth, high-side tool face, and magnetic tool face. The sensor axes are not perfectly orthogonal and are not perfectly aligned, therefore, compensation of the measured values for known misalignments are required in order to provide perfectly orthogonal values. The exact electronic sensitivity, scale factor and bias, for each sensor axis is uniquely a function of the local sensor temperature. Therefore, the raw sensor outputs must be adjusted for thermal effects on bias and scale factor. Orthogonal misalignment angles are used with the thermally compensated bias and scale factors to determine the compensated sensor values required for computation of precise directional parameters. Centralizer

Centralizer

It provides electrical conductivity between the electronics, battery and pulsar driver. It helps in keeping the tool inside the Monel and also prevents excessive lateral vibration. They are used in multiple MWD tool. BATTERY

Battery

Lithium-thionyl chloride is commonly used. It provide stable voltage source until the very near end of their service life, don’t require complex electronics to condition supply. It is safer at lower temp., if heated above 1800C, can go a violent, accelerated reaction, and explode with significant force. These batteries are efficient over their service life, are not chargeable, and disposal is subject to strict environmental regulations. Gamma Tool

Gamma Tool

The gamma tool is optional i.e. it is used only if it is required. It consists of Scintillation counter which is made up of thallium activated sodium iodide crystal. The gamma rays are multiplied by photo multiplier. All of earth’s rock formations exhibit varying degrees of radio activity. The gamma ray log is a measurement of the natural radioactivity of the formations. Gamma rays are emitted by radioactive elements such as isotopes of potassium, thorium and uranium. These elements are found more commonly in shale than in other rocks. Thus by measuring the gamma-ray emission from a sequence of rocks it is therefore possible to identify the shale zones. To be most effective in detecting changes of lithology, the gamma ray sensor should be positioned as close to the bit as possible, so that only a few feet of new formation are drilled before the tool responds.

Pulser Driver

Pulser driver

The pulser driver has a screen housing at the down hole end because of which it can be identified in MWD. The pulser driver system uses DC motor which is controlled by electronic module through the electrical pin connections present in the various components of the MWD tool. The up hole end connection of the pulsar driver system have 6 male pins connection while the down hole end is connected to the stinger assembly. Pulser driver system is divided into three major sections:

Snubber assembly: It consists of the electric circuits. Oil field housing: It houses the DC motor and capacitor bank. Screen Housing: Consists of the bellow, servo shaft and servo poppet.

Stinger assembly

Stinger Assembly

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

OUR PROPOSED SOLUTION:- DUAL DRILL STRING (DDS) In order to improve the cost efficiency of petroleum exploration and production, it is required to develop improved technology. Hence, a completely fresh drilling method has been developed, the prime new concept being the use of a conventional drill string with a special inner string to form a concentric dual drill string (DDS). It highly extends the capabilities beyond conventional drilling. It allows the fluid and cuttings from the bottom of the well to return to the surface through the inside of the drill string. It enables improved hole cleaning, reduced possibility for washouts and improved downhole pressure control. It has unique features for managed-pressure drilling (MPD) and extended-reach drilling (ERD). ARRANGEMENT SCHEMATICS Figure gives a schematic description of the arrangement for the process. This arrangement is based on conventional drilling; however, the following new

components are used:

• The Dual Drill String (DDS) facilitates a closed loop circulation of the drilling fluid. The cuttings are transported to the surface by the drilling fluid through the center pipe, leaving the wellbore annulus free of cuttings. The current size used consists of 6⅝-in. drill pipe adapted with 3.5-in. inner pipe that has

been fitted with stab-in inner string connectors.

• The Top Drive Adapter (TDA) is a dual conduit swivel facilitating rotation of drill string, accommodates discharge and return conduits and slip-ring for

power and data transmission.

• The Dual Float Valve (DFV) enables downhole pressure isolation of the well

and facilitates controlled pressure drilling and pressure less pipe connections.

• The Piston can be used to pump the BHA in the horizontal section of the well. The Piston provides hydraulic WOB and gives the ability to push the ERD

limits.

The unit is equipped with pressure and flow sensors both on the drilling fluid

inlet and the return lines. A computer is used for annulus behind the piston.

• The Flow Control Unit (FCU) is a control valve arrangement for the active drilling fluid to assure constant downhole pressure during drilling and pipe connections. The unit is equipped with pressure and flow sensors both on the drilling fluid inlet and the return lines. A computer is used for control and monitoring of the status of the well. An annular Control Unit is used to keep a

constant pressure in the annulus behind the piston.

A main difference compared to conventional drilling is the circulation flow path of the drilling fluid. For conventional drilling, the fluid returns through the wellbore annulus, whereas in this case, the drilling fluid returns to surface through the inner pipe of the DDS. It is based on pumping the drilling fluid into DDS annulus via the TDA. The drilling fluid flows down DDS annulus to the DFV. The DFV terminates the DDS at the top of a conventional Bottom Hole Assembly (BHA). Drill cuttings are transported back to surface by the drilling fluid in the well bore annulus outside the BHA up to the return entrance ports in the DFV. From this point the cuttings are then transported back to surface via the inner string, securing clean hole conditions at any time. The DFV blocks both inflow and return flow when circulation is stopped. This isolates the wellbore pressure, and allows for internal circulation immediately above the DFV. DFV will open when the pressure above it

balances the wellbore pressure.

The sliding Piston provides hydraulic Weight On Bit (WOB), which is especially advantageous for drilling long horizontal sections. The hydraulic force results from pressurizing the fluid behind the piston in the annulus between the drill

string and the casing.

Flow from the surface

Flow from swivel

and top drive

Midflow mechanism

Bottomhole valve mechanism

Potential for Extended Reach Horizontal Wells/Directional Drilling

The DDS allows for drilling horizontal wells in a new way compared to conventional drilling. The new arrangement can give significant improvements on several of the challenges of long reach horizontal wells, such as:

1. Solve the hole cleaning challenge

An important factor when drilling long horizontal sections with conventional drilling, is the hole cleaning. Since the cuttings tend to deposit in the low side of the hole it is important to rotate the drill string to avoid cuttings accumulations in the hole. For example, if the drilling fluid circulation is stopped, it is possible that local cuttings bed avalanches in the curved section of the well, which can result in high local cuttings accumulations that will increase the risk for plugging of the hole and consequently lead to stuck pipe situations.

The DDS solves the hole cleaning problem by cleaning the well from the bottom. The cuttings are transported back to the surface through the inner string, rather than through the annulus of the well. Thus there are no cuttings in the annulus of the well, hence the chance for cuttings accumulations that can lead to circulation stoppage and stuck pipe is eliminated.

2. Solve the ECD challenge

When drilling long horizontal wells it is important to keep the well pressure within a certain pressure window for hole stability reasons. This pressure window may be quite small, maybe in the range of 10 bar. Conventional drilling requires a pressure gradient in the horizontal section of the well, for the annular fluid to flow back to the surface. The Equivalent Circulating Density (ECD) is the additional friction pressure loss, i.e. the difference between the annulus well pressure in the start and the end of the horizontal section. The maximum horizontal reach for conventional drilling is in this case achieved when this dynamic ECD component is equal to the allowed pressure window, subject to minimum allowed flow rate and fluid rheology requirements.

The DDS solves the above issue due to the elimination of the dynamic ECD component. The dynamic ECD component represents the difference between the annulus well pressure in the start and the end of the horizontal section. For DDS, there is a short section between the drill bit and the DFV where the

fluid flows in the well annulus. However, this section is short and the pressure gradient here is of little importance in a long horizontal section. In the well annulus behind the DFV there is normally little or no flow, and thus the ECD in this horizontal section is eliminated. Therefore RDM provides a drilling solution, where the ECD as defined above is no longer a limiting factor for the horizontal drilling reach.

3. Solve the WOB challenge

For drilling long reach horizontal wells it is often a challenge to provide sufficient and stable Weight On Bit (WOB). This leads to poor rate of penetration and time consuming operations. This problem is very significant when trying to drill long horizontal sections in shallow reservoirs, because of the short vertical section. This is solved by DDS by built in feature where one can pressurize to the volume behind the Sliding Piston which will drive the bit forward, independent of gravity. This allows to maintain hydraulic WOB in very long horizontal sections. The available additional WOB force from the Sliding Piston is dependent on the piston size and the differential pressure across the piston.

4. Reduce drill string buckling problems

Buckling of the drill string occurs when the drill string is in compression, due to the WOB and downhole frictional forces. This buckling leads to additional friction and problems to transfer sufficient WOB force to the drill bit. For conventional horizontal drilling, this buckling occurs along the whole well path from the neutral point in the vertical section down to the drill bit. The DDS arrangement reduces the buckling problems by the following:

- If the Sliding Piston is positioned in the horizontal section of the well, the drill string in front of the Sliding Piston will be in compression and be prone to buckling. However, the drill string along the whole well path behind the piston can be held in tension. Thus the buckling and high friction forces especially in the curved section of the well can be avoided.

- Conventional drilling relies on the use of limited or small drill string diameter to avoid high ECD. DDS has the advantage of using a large diameter drill string downhole without causing high ECD, since the return flow is contained inside the drill string and not in the well annulus. As the buckling resistance is strongly increasing with increasing drill string diameter, the use of a large diameter drill string will also reduce buckling problems significantly.

5. Improve downhole conditions

When drilling long horizontal wells, the mechanical transfer of forces through the drill string is subjected to high friction and dynamic loads. For long and relatively small diameter drill strings this can result in downhole drill string vibrations and stick-slip behavior on the drill bit. Such situations will cause strongly reduced rate of penetration, and may lead to costly drill string failure.

RDM improves the downhole conditions to avoid the above mentioned problems by using a larger than normal diameter drill pipe.

For example the rotational stiffness will typical be more than 3 times for a 6 5/8” drill pipe compared to a 5” drill pipe. The larger pipe will increase the torsional stiffness thereby, reducing the onset of vibrations and stick-slip, and avoid downhole fatigue problems.

The torque and drag are challenging aspects of drilling long horizontal wells. Torque and drag is created from the friction between the drill string and the wall of the wellbore along the well path. The torque and drag values are typically dominated by the friction in the curved and horizontal section. The presence of cuttings along the hole will increase this friction, and can cause problems in the case of cuttings bed accumulations. Cuttings bed accumulation can occur when drilling with high rate of penetration and by settlements in critical zones, especially during stops in circulation. DDS enables the drilling to be performed with no cuttings in the well annulus, since the cuttings are transported back to the surface inside the drill string, rather than in the well annulus. The additional torque and drag from the cuttings can therefore be eliminated. Larger diameter pipe has also normally improved torque rating compared to smaller diameter pipe.

REFERENCES

Directional drilling training manual, Schlumberger (unpublished work)

Baker Hughes training manual, 750-500-072 Rev. July 1998

Applied drilling engineering, SPE, Richardson, TX, 1991.

Drilling operations manual by IDT, ONGC

Operating manual ofgriffit double acting hydraulic mechanical jars.

www.bicodrilling.com – Bico corporate brochure.

https://sites.google.com/site/directionaldrillingclub/downhole-mud-motors

SPE Paper-68088

Kerr et.al. “New Approach to Improve the Horizontal Drilling Reach”, SPE 138521, Calgary, Aug 2015.

Egorenkov and Vestavik, “Deployment of DDS in a Shale Gas Field in Canada”, SPE 148169, Aberdeen, Sept. 2015.

Walker M. “Extended Reach Drilling-new solution with a unique potential”, IADC/SPE 171046, San Diego, Mar. 2015.

Tarek Ahmed, “Reservoir Engg. Handbook” Woburn, MA, 2001.

Heriot Watt Petroleum Dept. “Heriot Watt University Drilling Engg.” 2001.

report file

Documents