Ongc Project Report

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Submitted By:

Arihant Bothra

Kuldeep Singh

Anirudh Gupta

Utkarsh Srivastava

B. Tech. PE, Final Year,

Indian School of Mines, Dhanbad

Submitted to:

Mr B. Rama Gopal,

C.E. (Directional Drilling),

ONGC, Ahmedabad

Project Reporton

Drilling of Directional Wells


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INDEX

SECTION TOPIC PAGE NUMBER

Index 2

Acknowledgement 3

Abstract 4

Aim and Objective 5

1 INTRODUCTION 6

1.1 History and Applications of Directional Drilling 6

1.2 Types of Directional Wells 12

1.3 Geometry of a Directional Well 13

2DIRECTIONAL WELL PLANNING

15

2.1 Directional Surveying 15

2.2 Survey Calculation Methods 23

2.3 Directional Well Planning 29

3 Directional Well Drilling 43

3.1 Directional Drilling Tools 43

3.2 Bottom Hole Assembly 53

4 DEFLECTION TOOLS AND METHODS 64

4.1 Drilling Tools 64

4.2 Deflection Tools and Methods 67

4.3 Measurement While Drilling 76

5 RIGSITE OPERRATIONS 865.1 BHA Weight 86

5.2 Hole Washout 89

5..3 Orientation 89

5.4 Reactive Torque 90

5.5 Magnetic and Gravity Tool Face 91

5.6 Single Shot Kick-Off/ Correction Run/ Oriented

Side Track

94

5.7 Tool Face: MTF, GTF and TFO 98

CASE STUDY: KDS WELL 108Gallery: Visit to Rig Sites 127

References 128


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ACKNOWLEDGEMENT

We take this opportunity to formally thank Mr B. Rama Gopal, C.E. (Directional Drilling),

ONGC, Ahmedabad for permitting me to work under him, and to benefit from his knowledgeand experience. Even in the short while that we have been here till now, we gained from all

the time that he gives to students, despite his own busy schedule, and the effort he puts in for

our advantage. This project, Directional Drilling in KDS Well gave us an excellent

opportunity to work on real data, and we are sure this has consolidated our theoretical

knowledge of drilling.

We extend our heartfelt thanks to Mr D. Sanyal, Head of Dilling Services, ONGC

Ahmedabad for assigning us this topic, which is as highly educative as it is practically useful,

and for allowing us the use of ONGCs excellent facilities.

We also thank Prof. AK Pathak, HOD, Petroleum Engineering, ISM, Dhanbad, for

facilitating this project.

At a different level, we thank our friends and colleagues for their help in the preparation of

this project.

Arihant Bothra Anirudh Gupta Kuldeep Singh Utkarsh Srivastava

(B.Teh. Final Year, Petroleum Engineering)

ISM, Dhanbad.


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ABSTRACT

Directional drilling is the process of directing the wellbore being drilled along a defined

trajectory to a predetermined target. Traditional drilling methods were limited to drill thevertical wells. But as it is said that Necessity is the mother of invention , when traditional

methods were not able to fulfil our need ,different techniques of drilling non vertical sites

were developed over last 2-3 decades. The first directional well was drilled in California

Hunting Beach field in 1962 using PDM and Bent sub. Today number of well trajectories of

different shapes can be drilled using recent techniques like down hole mud motors, steerable

motors, rotary steerable systems etc. and these techniques have revolutionized drilling

industry.

Ahmadabad Asset, ONGC plans drilling directional wells in Vasna, Ghamji, Jhalora,

Kalol, Nawagam. High angle Directional drilling could expand the drilling area to minimize

pressure interference among wells at same rig site as well as can expand production area over

currently in use.

One well from Ahmadabad oil field is considered for study under present dissertation

work. A detailed study will be undertaken on latest methods of planning well to its execution

from directional drillers point of view.

Currently, different computer based directional drilling software are available for

planning of well trajectory, survey calculations etc. but it is must for a directional driller to

know what is actually being calculated.


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AIM AND OBJECTIVE

Directional Drilling technology has steadily improved the ability to optimize recovery,

improve project return and lower the impact of exploration and development operations onenvironment. With technological advancements, directional drilling is gaining popularity

among clients and service companies to develop ageing oil fields.

The aims and objective of this study include:

1. Learning the basics of directional well planning: Understanding how a well plan for a

directional well is calculated. It includes:

a) Preliminary information that are required for the directional well.

b) Selection and choosing of well profile, KOP, build up rate, drop off rate and

implications from a drilling standpoint.

c) Design of the optimum well path trajectory(build up, slant and drop off sections)

2. Execution of directional plan: Methods of calculating well path trajectory from

survey points and its presentation in 3-D co-ordinate system and projection to know

whether it is on plan and if not, how far it is from target/landing point.

3. Drill string design for directional control: Calculation of side forces and lead angle of

the bit and determination of the shape of the string for a given bottom hole

configuration, performance analysis of single vs. multiple stabalizer bottomhole

assembly and design of bottomhole assembly for build-up, slant and drop-off sections

of the well trajectory.

4. Hands-on training computer software for planning well path trajectory ,calculation

and presentation of well path trajectory from survey points , analysis and design of

bottom hole assembly for different well configurations and case studies.

Overall to introduce and familiarise reader with a directional drillers job.


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Introduction

1.1 History and Applications of Directional DrillingDirectional drilling is defined as an art and science involving deflection of a well bore in a

specified direction in order to reach a predetermined object below the surface of the earth

1.1.1 Historical BackgroundMany prerequisites enabled this suite of technologies to become productive. Probably, the

first requirement was the realization that oil wells, or water wells, are not necessarily vertical.

This realization was quite slow, and did not really grasp the attention of the oil industry until

the late 1920s when there were several lawsuits alleging that wells drilled from a rig on one

property had crossed the boundary and were penetrating a reservoir on an adjacent property.

Initially, proxy evidence such as production changes in other wells was accepted, but such

cases fuelled the development of small diameter tools capable of surveying wells during

drilling.

Measuring the inclination of a wellbore (its deviation from the vertical) is comparatively

simple, requiring only a pendulum. Measuring the azimuth (direction with respect to the

geographic grid in which the wellbore is running from the vertical), however, was more

difficult. In certain circumstances, magnetic fields could be used, but could be influenced by

metalwork used inside wellbores, as well as the metalwork used in drilling equipment. The

next advance was in the modification of small gyroscopic compasses by the Sperry

Corporation, which was making similar compasses for aeronautical navigation. Sperry did

this under contract to Sun Oil (which was involved in a lawsuit as described above), and aspin-off company "SperrySun" was formed, which brand continues to this day, absorbed

into Halliburton. Three components are measured at any given point in a wellbore in order to

determine its position: the depth of the point along the course of the borehole (measured

depth), the inclination at the point, and the magnetic azimuth at the point. These three

components combined are referred to as a "survey". A series of consecutive surveys are

needed to track the progress and location of a wellbore. Many of the earliest innovations such

as photographic single shot technology and crow's feet baffle plates for landing survey tools

were developed by Robert Richardson, an independent directional driller who first drilled in

the 1940s and was still working in 2012.

Prior experience with rotary drilling had established several principles for the configurationof drilling equipment down hole ("Bottom Hole Assembly" or "BHA") that would be prone

to "drilling crooked hole" (i.e., initial accidental deviations from the vertical would be

increased). Counter-experience had also given early directional drillers ("DD's") principles of

BHA design and drilling practice that would help bring a crooked hole nearer the vertical.

In 1934, H. John Eastman ofLong Beach, California, became a pioneer in directional drilling

when he and George Failing ofEnid, Oklahoma, saved the Conroe, Texas, oil field. Failing

had recently patented a portable drilling truck. He had started his company in 1931 when he

mated a drilling rig to a truck and a power take-off assembly. The innovation allowed rapid

drilling of a series of slanted wells. This capacity to quickly drill multiple relief wells and

relieve the enormous gas pressure was critical to extinguishing the Conroe fire. (E&P,

"Making a hole was hard work," Kris Wells, American Oil & Gas Historical Society
http://en.wikipedia.org/wiki/Azimuthhttp://en.wikipedia.org/wiki/Sperry_Corporationhttp://en.wikipedia.org/wiki/Sperry_Corporationhttp://en.wikipedia.org/wiki/Sun_Oilhttp://en.wikipedia.org/wiki/Sperry_Sunhttp://en.wikipedia.org/wiki/Halliburtonhttp://en.wikipedia.org/wiki/Long_Beach,_Californiahttp://en.wikipedia.org/wiki/Enid,_Oklahomahttp://en.wikipedia.org/wiki/Conroe,_Texashttp://en.wikipedia.org/wiki/Conroe,_Texashttp://en.wikipedia.org/wiki/Enid,_Oklahomahttp://en.wikipedia.org/wiki/Long_Beach,_Californiahttp://en.wikipedia.org/wiki/Halliburtonhttp://en.wikipedia.org/wiki/Sperry_Sunhttp://en.wikipedia.org/wiki/Sun_Oilhttp://en.wikipedia.org/wiki/Sperry_Corporationhttp://en.wikipedia.org/wiki/Sperry_Corporationhttp://en.wikipedia.org/wiki/Azimuth


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Contributing Editor, 1 Nov. 2006 and "Technology and the Conroe Crater"). In a May,

1934, Popular Science Monthly article, it was stated that "Only a handful of men in the world

have the strange power to make a bit, rotating a mile below ground at the end of a steel drill

pipe, snake its way in a curve or around a dog-leg angle, to reach a desired objective."

Eastman Whip stock, Inc., would become the world's largest directional company in 1973.

Combined, these survey tools and BHA designs made directional drilling possible, but it was

perceived as arcane. The next major advance was in the 1970s, when down hole drilling

motors ( mud motors, driven by the hydraulic power of drilling mud circulated down the drill

string) became common. These allowed the bit to be rotated on the bottom of the hole, while

most of the drill pipe was held stationary. A piece of bent pipe (a "bent sub") between the

stationary drill pipe and the top of the motor allowed the direction of the wellbore to be

changed without needing to pull all the drill pipe out and place another whip stock. Coupled

with the development ofMeasurement While Drilling tools (using mud pulse

telemetry orEM telemetry, which allows tools down hole to send directional data back to the

surface without disturbing drilling operations), directional drilling became easier.

Certain profiles could not be drilled without the drill string rotating at all times. Drillingdirectionally with a motor requires occasionally "sliding" the drill pipe, which means

stopping the pipe rotation and pushing the pipe in the hole as the motor cuts a curved section

of hole. "Sliding" can be difficult in some formations, and it is almost always slower and

therefore more expensive than drilling while rotating, so the ability to control wellbore

direction while rotating is desirable. Several companies have developed tools which allow

directional control while rotating. These tools are referred to as Rotary Steerable systems, or

RSS. RSS technology has allowed access to and/or directional control in previously

inaccessible or uncontrollable formations. Robert Zilles pioneered many of the RSS drilling

procedures for Baker Hughes Inteq and is considered the Grandfather of RSS technology. In

2010 he became the first BHI directional driller to drill a well in each of the last 7 decades.

1.1.2 Applications of directional drilling

1. Multiple wells from offshore structure: Directional drilling from a multiwall offshoreplatform is the most economical way to develop off shore oil fields. Onshore, a similar

method is used where there are space restrictions e.g. jungle, swamp, etc.

2. Relief wells: A relief well is a well drilled to intersect an oil or gas well that hasexperienced a blowout. Specialized liquid, such as heavy (dense) drilling mud followed

by cement, can then be pumped down the relief well in order to stop the flow from the

reservoir in the damaged well.
http://en.wikipedia.org/wiki/Popular_Science_Monthlyhttp://en.wikipedia.org/w/index.php?title=Downhole&action=edit&redlink=1http://en.wikipedia.org/wiki/Mud_motorhttp://en.wikipedia.org/wiki/Measurement_While_Drillinghttp://en.wikipedia.org/wiki/Mud_pulse_telemetryhttp://en.wikipedia.org/wiki/Mud_pulse_telemetryhttp://en.wikipedia.org/wiki/Electromagnetismhttp://en.wikipedia.org/wiki/Blowout_(well_drilling)http://en.wikipedia.org/wiki/Blowout_(well_drilling)http://en.wikipedia.org/wiki/Electromagnetismhttp://en.wikipedia.org/wiki/Mud_pulse_telemetryhttp://en.wikipedia.org/wiki/Mud_pulse_telemetryhttp://en.wikipedia.org/wiki/Measurement_While_Drillinghttp://en.wikipedia.org/wiki/Mud_motorhttp://en.wikipedia.org/w/index.php?title=Downhole&action=edit&redlink=1http://en.wikipedia.org/wiki/Popular_Science_Monthly


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3. Controlling vertical wells: It occurs quite often that vertical wells do not follow theirplanned trajectory. It may be because of some down hole operational problems. So to

correct their path directional drilling can be used.

4. Sidetracking: Sidetracking was the original directional drilling technique. Initially,

sidetracks were blind. The objective was simply to get past a fish in vertical hole.

Oriented sidetracks are performed to hit a specific target. It may be necessary due to anunsuccessful fishing job in a deviated well. Oriented sidetracks are most widely used.

They are often performed when , for example, there are unexpected changes in geological

configuration.


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5. Inaccessible Locations: The targets located beneath city , river or environmentallysensitive areas make it necessary to locate the drilling rig some distance away. A

directional well is drilled to reach the target.

6. Fault Drilling: Crooked holes are common when drilling vertical wells.ths is often due tofaulted subsurface formations. It is often easier to drill a directional well into such

formation without crossing fault lines.


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7. Horizontal drilling: There may be different reasons for the depletion of production in aparticular field. For a field facing problems of severe gas and water conning, has good

vertical permeability one can plan drilling a horizontal well.

8. Salt dome drilling: Salt domes have been found to be natural traps of oilaccumulating in strata beneath the overhanging hard cap. There are severe drilling

problems associated with drilling a well through salt formations. These can be

somewhat alleviated by using a salt-saturated mud. Another solution is to drill a

directional well to reach the reservoir (Figure 1-3), thus avoiding the problem of

drilling through the salt.


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9. Multiple sands from single wellbore: In this application, a well is drilled directionally tointersect several inclined reservoirs. This allows completion of the well using a multiple

completion system. The well may have to enter the targets at a specific angle to ensure

maximum penetration of the reservoirs.

10.Multilateral drilling: In this type of drilling number of re-entry wells are drilled from asingle mother bore so that production from different zones can be achieved.


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1.2 Types of Directional WellsA large number of shapes can be imagined between a given surface point and the target point.

But it is not possible to drill any shape we imagine. Therefore , the following basic well

profiles are assumed and each can be used for different situations.

Directional Patterns

Build and hold(Type I) profile

Build , Hold and Drop (S) Profile(Type II)

Deep kick off and build(J) profile (Type III)

Horizontal

_ Single

_ Extended reach well (ERW)

_ Multilateral

1.2.1. Build and hold(Type I) profile

The well is drilled at shallow depth and inclination is

locked in until the target zone is penetrated.

1.2.2. Build , Hold and Drop (S) Profile(Type II)

The well is deflected at a shallow depth until the maximum required inclination is achieved.

The well path is then locked in and, finally, the inclination is reduced to a lower value or, insome cases, the well is returned back to vertical by gradually dropping off the angle.

1.2.3. Deep kick off and build (J) profile (Type III)

The well is deflected at a much deeper position and after achieving the desired inclination

the well is locked in until target zone is penetrated.


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1.2.4. Horizontal well

The well is deflected at a deeper depth and angle of inclination is 90 degrees.

1.3

Geometry of a Directional wellA directional well is drilled from a surface point to the subsurface target point through the

shortest path. Due to irregularities in rock properties a directional well never remains in a

single plane. Its inclination and direction continuously changes.

The terms that are used in directional well geometry are defined below:

Kick off point: It is the point at which well is deviated from vertical. It can be referred

as start of build up section.

Build up section: In this section well is continuously deflected at a constant build

rate. Build rate is generally expressed in Degrees per 100 feet or degrees per 30 meter.

Tangent Section: It is also called as hold section. in this section well is drilled at

constant angle.

Inclination: It is angle of the wellbore from vertical.

Azimuth: The Azimuth or direction of the well is expressed w.r.t. some plane

generally True North.

Rotary Kelly Bushing: It is taken as reference for defining the co-ordinates of a point

in the well in the Cartesian system.


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True Vertical Depth: It is expressed as vertical distance below RKB.

Departure: IT is the distance between two survey points as projected on horizontal

plane.

Drop off section: It is the section of the well in which angle is dropped continuously

with a constant drop rate expressed in degrees per 100 feet or degrees per 30 meter.

-


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Chapter 2 DIRECTIONAL WELL PLANNING

2.1 Directional Surveying

Directional surveying can be defined as a completed measurement of the inclination and

azimuth of a location in a well, typically the total depth at the time of measurement.

In both directional and straight holes, the position of the well must be known with

reasonable accuracy to ensure the correct wellbore path and to know its position in the event

a relief well must be drilled. The measurements themselves include inclination from vertical,

and the azimuth (or compass heading) of the wellbore if the direction of the path is critical.

These measurements are made at discrete points in the well, and the approximate path of the

wellbore computed from the discrete points.

The following parameters are measured in directional surveying:

Measured Depth: Measured depth refers to the actual depth of the hole drilled as

measured from the surface location, to any point along the wellbore or to the total

depth.

Inclination: Inclination is the angle of the wellbore measured from the vertical. It is

measured in degrees. An inclination of 0 degrees would mean vertical wellbore and

90 degrees would mean horizontal wellbore.

Azimuth: The azimuth of a wellbore at any point is defined as the direction of thewellbore on a horizontal plane measured clockwise form a north reference. Azimuths

are usually expressed in angles from 0-360 degrees.


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Importance of Directional Surveying:

Directional surveying is required:-

To monitor the progress of the well. Actual directional data can be used to plot thecourse of the well and that can be compared with the planned trajectory.

To plan the well path correction strategies for deviated wells.

To prevent the collision of the present well with the nearby existing wells.

To determine the actual deflection tool orientation in correct direction.

To determine the exact location of the bit as drilling progresses.

To plan and monitor relief well during event of blowout, fire accidents etc.

To calculate Dog leg severity.

2.1.1 When and how to survey:A survey can be taken while drilling is in progress or after the completion of drilling.

2.1.1.1 Surveying while drilling

Single surveys can be performed during drilling process to record the inclination and

azimuth. This is done by temporarily stopping the drilling and lowering the survey tool and

taking the survey. Now, a days, due to the development of Measurement While Drilling tools

(MWD), surveys can be taken continuously without stopping the drilling process. The

information is stored in computer memory down hole or is transmitted to the surface. At

surface this information is decoded by the surface computers and survey is continuously


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recorded on a chart recorder. Surveying while drilling allows driller to know the current

situation of the well and helps him to decide his course of action.

2.1.1.2 Surveying After Drilling

Multiple surveys are performed

after drilling has been completed.

After a long length of hole is

drilled, a survey instrument is run

into the hole and survey records

are gathered over the entire length

of the hole. Unlike single surveys,

this information is used to plot

the path the wellbore has taken toreach its reach its current

position. Inclination and azimuth

data recorded during the surveys

will be used to produce the final

survey plot.

2.1.2 Survey Instruments


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1. Acid bottle Surveying: this tool is based on simple principle that the free surface of aliquid always remains horizontal regardless of the position of the container. in this

instrument the container is a glass cylinder and liquid is acid. The instrument is

allowed to rest in an inclined position for a certain period of time(30 min.). Acid will

react with the glass surface and leave a mark on the side of the cylinder indicating

horizontal surface. The distance between the mark and acids original position, whe nthe cylinder was leveled, can be used to calculate the inclination angle. The strength

of the acid should be chosen carefully so that it can leave a distinct mark on the glass

surface. To measure the direction an additional compartment is was required

containing gelatin and a magnetic compass needle. The compass needle was free

floating and aligned itself with the magnetic north. The direction of a deviated well

can therefore be reference to the magnetic

north. The major disadvantage of this method

is that acid was unable to leave a distinct mark

on the glass surface.

2. Magnetic Single Shot: The magnetic

single shot was first used in the 1930s formeasuring the inclination and direction of a

well. The instrument consists of 3 sections:

An angle unit consisting of a magnetic

compass and an inclination measuring device.

A camera section

A timing device or motion sensor unit

The angle unit of the tool consists of a

magnetic compass and a plumb bob. When the

tool is in the correct position (near the bit) the

compass is allowed to rotate until it aligns

itself With the Earths magnetic field. The

plumb bob hangs vertical irrespective of the

Deviation from the vertical. The camera

consists of a photographic disc, which is

mounted in the tool in a

Light proof loading device, a set of bulbs

which are used to illuminate the angle unit,

when required, and a battery unit, which

provides power to the light bulbs.

The timing device is used to operate the light

bulbs when the instrument is in the correctposition. The surveyor must estimate the time

required to lower the instrument into position

and set the timer accordingly. Since it is

sometimes difficult to estimate the time

required for the tool to reach the bit, more

modern instruments

use a motion sensor unit. This electronic device

will illuminate the light bulbs when the

instrument stops moving. When the light bulbs

are illuminated a photograph image of the

plumb bob is superimposed on the compasscard.


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3. Magnetic Multi-shot surveying: The magnetic multi shot instruments are similar tothe single shot, except that a film magazine is used so that the survey data can be

recorded at a regular interval of time. Also the camera is a modified movie camera.

This instrument can be run on a wire line to land in a NMDC or simply dropped from

the surface. A continuous record is taken as the drill string is pulled out of the hole.Surveys are taken when each stand is broken off and string is stationary. Magnetic

multi shot instruments are useful for wells free from magnetic materials or magnetic

geological formations.

4. Gyro single shot: Since magnetic surveys which rely on compass readings areunreliable in cased hole, or in open hole where nearby wells are cased, an alternative

method of assessing the direction of the well must be used. The inclination of the well

can be assessed in the same way as in the magnetic tools. The Magnetic effects can be

completely eliminated by using a gyroscopic compass.

A gyroscope is a wheel which spins around one axis, but is also free to rotate about

one or both of the other axes, since it is mounted on gimbals. The inertia of the

spinning wheel tends to keep its axis pointing in one direction. In a gyro singleshot tool, a gyroscope is rotated by an electric motor at approximately 40,000 rpm.

On surface the gyro is lined up with a known direction (True North) and as the tool

is run in hole the axis of the tool should continue to point in the direction of true

North regardless of the forces which would tend to deflect the axis from a northerly

direction. A compass card is attached to, and aligned with, the axis of the gyroscope

and this acts as the reference direction from which all directional surveys are taken.

5. Measurement While Drilling: MWD is a survey tool which measures survey dataand other hole parameters while drilling. these tools are made up as a part of BHA.

They measure the survey data in the same way as wireline steering tools using

magnetometers, which measures component of earths magnetic field. and

accelerometers which measure the component of gravity. The raw data is transmitted

to the surface through mud telemetry systems (pressure pulses). These pressure pulses

represent binary 0 and 1.MWD tools are not only used to orient deflection tools but

also to take directional surveys at regular intervals while well is being drilled.

6. Wireline Steering Tool: It is a survey tool used to give continuous surface readout ofdata while drilling with a down hole motor and bent sub assembly The downhole tool

comprises of a solid state electronics probe plus spacer bars and a muleshoe. The raw

data from the probe is transmitted to the surface via the conducting wireline. A

surface computer decodes the signal and calculates the survey data. In order to have a

Wire line running-in-hole while drilling fluid is circulated , it is necessary to use

either a special circulating head or a side entry sub.7. Gyroscopic multi shot: It is a survey instrument which is not adversely affected bycasing or other magnetic influences. The gyro multi shot tool is lowered into the well

on a wire line. At fixed intervals tool is stopped to take the survey.

Inertial Navigation System: Inertial navigation is a very precise method of surveying used in

aircraft and missile guidance systems. In the late 1970s this technique was adopted for

borehole surveying in the North Sea. The FINDS tools (Ferranti Inertial Navigation

Directional Surveyor) based on an inertial platform consisting of 3 accelerometers and 3

gyroscopes mounted on gimbals was the first IN system used in borehole surveying.

Although the FINDS tool is no longer used it is the most generic type of tool and will

therefore be described On the surface the platform is automatically levelled and the N-S

accelerometer aligned with true North. As the tool is run down the hole on wireline anymisalignment of the platform is detected by the gyroscopes which send signals to the gimbals


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mechanism to restore the platform to its original position. The running procedure is to stop

the tool for 1 minute, then run for 1 minute and so on until it reaches bottom. During the 1

minute transit periods the accelerometer readings give the inertial velocity. Once back on

surface this data can be integrated to give the incremental X, Y and Z displacements for each

transit period. These distances can then be added to the previous co-ordinates to give the

trajectory of the cased borehole (Note that the FINDS tool calculates the co-ordinatesdirectly, not by measuring azimuth and inclination). The FINDS tool was generally

considered to be the most accurate surveying device available. Its accuracy was about 0.2 ft.

per 1000 ft. of hole length (i.e. it can locate a 13 5/8" casing shoe, set at 5000 ft, to within 1

foot, compared with 15 - 30 ft. using conventional gyro methods). The FINDS tool does

however have certain disadvantages :

The tool diameter was 10 5/8", and so could only be used down to the 13 3/8"

casing shoe.

It is much more expensive to run than a gyro multi-shot.

Only a limited number of tools were available.

Its major application was to provide a definitive trajectory of the hole from surface down to

the 13 5/8" casing shoe. High accuracy is required here when drilling from multi-wellplatforms where the wells are very close to each other and there is a risk of intersection. Since

the FINDS tool a number of new surveying tools were introduced. In 1986 Schlumberger,

introduced the GCT (Guidance Continuous Tool). This instrument is only 3 5/8" diameter

and it can therefore be used to survey the entire well path down to TD (minimum casing size

is 4 1/4"). The inertial platform in the GCT consists of a 2 axis accelerometer and a 2 axis

gyroscope, mounted on gimbals. The spin axis of the gyroscope is parallel with one axis of

the accelerometer and aligned with true North. Any drift of the gyro is detected by positional

sensors and corrected by the gimbal mechanism. The inclination and azimuth are calculated

from the accelerometer reading and the angle between the outer and inner gimbals. The

inclination and azimuth are given on a surface display as the tool is being run. The survey

depth is given by the wireline measurement. The accuracy of this tool is about 2.6 ft. per

1000 ft. per 1000 ft. of hole length, in the North Sea.

2.1.2.1 Classification of survey systems

The most basic classification is magnetic and gyroscopic. Magnetic survey systems have

sensors which detect the earths magnetic field and hence use magnetic north as reference.

Thus while using these systems magnetic declination must be known for the correction.

The gyroscopic systems use a gyroscope to provide a direction reference.

Survey systems can also be classified on the basis shown below.

Those which tell where the well is going

Magnetic single shot

Gyro single shot

Wireline steering tool

MWD

Those which tell where the well has gone

Magnetic multishot


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Gyro multishot

INS

2.1.2.2 Borehole Survey References

All survey systems measure inclination and azimuth at a particular measured depths (exceptINS)

These measurements must be made with respect to a fixed reference so that all the survey

data can be recorded conveniently. Following reference systems are used:

1. Depth References: Measured Depth(MD): It is the distance measured along the actual course of

the drilled hole from surface reference point to the survey point. It is also

called as Along Hole Depth.

True Vertical Depth: It is the vertical distance foem the depth reference levelto the point in the borehole. In general Rotary Kelly bushing (RKB) or Rotary

table elevation(RTE) is used as depth reference.

2. Inclination referencesInclination is the angle between the vertical and the tangent to the wellbore at the

desired point. Conventionally 0 degrees is Vertical and 90 degrees is horizontal.Vertical reference is the direction of the local gravity vector and could be indicated

by a plumb bob or measured with an accelerator.

3. Azimuth reference systemFor directional surveying three azimuth reference systems are used

Magnetic North(MN)This is the direction of the horizontal component of the Earths magnetic field lines at a

particular point on the Earths surface. A magnetic compass will align itself to these lines

with the positive pole of the compass indicating North.

True North(TN)This is the direction of the geographic North Pole. This lies on the axis of rotation of the

Earth. The direction is shown on maps by the meridians of longitude.

Grid North(GN)

The meridians of longitude converge towards the North Pole and South Pole, and

therefore do not produce a rectangular grid system. The grid lines on a map form a

rectangular grid system, the Northerly direction of which is determined by

one specified meridian of longitude. The direction of this meridian is called Grid

North. For example, in the often used Universal Transverse Mercator (UTM) co-ordinate

system the world is divided into 60 zones of 6 degrees of latitude, in which the central

meridian defines Grid North. Grid North and True North are only identical for the central

meridian. Comparison of co-ordinates is only valid if theyare in the same grid system.

To be meaningful, all azimuths must be quoted in the same reference system.This is


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usually the Grid North system. In practice, azimuths are often measured in systems other than

the Grid North system.

4. Magnetic declinationMagnetic declination is the angle between magnetic north (the direction the north end ofa compass needle points) and true north. The declination is positive when the magnetic north

is east of true north. The term magnetic variation is a synonym, and is more often used in

navigation. Isogonic lines are where the declination has the same value, and the lines where

the declination is zero are called agonic lines.

Magnetic declination varies both from place to place, and with the passage of time. As a

traveller cruises the east coast of the United States, for example, the declination varies from

20 degrees west (in Maine) to zero (in Florida), to 10 degrees east (in Texas), meaning a

compass adjusted at the beginning of the journey would have a true north error of over 30

degrees if not adjusted for the changing declination. The magnetic declination in a given area

will change slowly over time, possibly as much as 2-25 degrees every hundred years or so,depending upon how far from the magnetic poles it is. Complex fluid motion in the outer core

of the Earth (the molten metallic region that lies from 2800 to 5000 km below the Earth's

surface) causes the magnetic field to change slowly with time. This change is known as

secular variation. Because of secular variation, declination values shown on old topographic,

marine and aeronautical charts need to be updated if they are to be used without large errors.

Unfortunately, the annual change corrections given on most of these maps cannot be applied

reliably if the maps are more than a few years old since the secular variation also changes

with time in an unpredictable manner.
http://en.wikipedia.org/wiki/Compasshttp://en.wikipedia.org/wiki/True_northhttp://en.wikipedia.org/wiki/Isogonhttp://en.wikipedia.org/wiki/Isogonhttp://en.wikipedia.org/wiki/True_northhttp://en.wikipedia.org/wiki/Compass


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.

If the compass at your place is pointing clockwise with respect to the True North, declination

is positive orEAST

If the compass at your place is pointing counter-clockwise with respect to the True North,

declination is negative orWEST

2.2 Survey Calculation Methods

At the end of each successful survey (e.g. single-shot, multishot, steering tool, surface

Read-out gyro, MWD) the following data is measured: survey measured depth

wellbore inclination

wellbore azimuth (corrected to relevant North).

The above data will then enable the bottom hole location at the last survey point to be

calculated accurately in terms of:

TVD

Northing

Easting

Vertical section dog-leg severity

The calculated data is then plotted on the directional well plot (TVD vs vertical section on

the vertical plot, N/S vs E/W rectangular coordinates on horizontal plot).

2.2.1 Definitions

1. SURVEY STATION:A survey station (A or B) is any point along the well bore at which a survey is

taken.2. COURSE LENGTH:


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A course length (AB) is the measured distance between two survey stations.

3. TRUE VERTICAL DEPTH (TVD)True vertical depth (AC) is the length of line made by projecting the course length on

to a vertical plane.

TVD = Course Length x cosine of Average drift angle

4. DRIFT ANGLE (INCLINATION):Drift angle is the angle measured in degrees which a well bore makes from a

true vertical line.

5. MEASURED DEPTH:Measured depth refers to actual depth of the hole drilled as measured from surface

location to any point along the well bore.

6. HOLE DIRECTION:

It is the direction of the well bore at any point along its length. It is measured

in degrees and expressed in quadrant form (NW, SW, NE, SE)

7. COURSE DEVIATION:

Course deviation is the length of line made by projecting the course length on

to a horizontal plane. The length of the course deviation depends on drift angle andcourse length. Greater the course length/ drift angle greater is the course deviation.

Course Deviation = Course length x sine of

average drift angle

8. LATITUDE:

Latitude is defined as horizontal distance

the well bore moves from one survey station to

another in a due NORTH-SOUTH direction. It is


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the result of interaction of hole direction, drift angle and course length.

N-S coordinates = Course deviation x cosine of average direction.

9. DEPARTURE:

Departure is defined as horizontal distance the well bore moves from one

survey station to another in a due EAST-WEST direction. It is the result of

interaction of hole direction, drift angle and course length.E-W coordinates = Course deviation x sine of average direction

10.VERTICAL SECTION:

Vertical section is the horizontal distance the well bore moves in the direction

of the target from one survey station to another. It would be the result of direction of

course length vs direction of target and course deviation.

Vertical section = Course deviation x cosine of difference between target

direction and the average direction.

11.NET DIRECTION:

Net direction is the direction from surface location to the last survey station.

Net direction = Tan -1 (departure/ latitude)

2.2.2 Calculation Techniques

There are several methods for calculation of directional surveys. However, only four of these

methods are presented here. Those are:


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Average angle method

Tangential method

Balanced Tangential method

Radius of Curvature method

Minimum Curvature method

Symbols Used:

1& 2 = angle at upper & lower stations respectively

1 & 2 = azimuth at upper & lower stations respectively

avg= average azimuth

t = target azimuth

L = Distance between upper & lower stations

V = Incremental TVD between two stations

CD = Course Deviation between two stations

N = Incremental distance along North between two stationsE = Incremental distance along East between two stations

2.2.2.1 Average angle method

This method assumes a straight line between survey stations A and B. The

inclinations and directions are averaged. The objective is to calculate the following

for the survey point B in the diagram below:

- TVD

- North Co-ordinate

- East Co-ordinate

- Vertical Section (VS)- Dogleg Severity (DLS)

This method assumes only one

straight line that intersects both

upper and lower Stations. The

straight line is defined by averaging

the inclination and azimuth at both

stations.

V = L x Cos(1 + 2) /2

CD = L x Sin(1 + 2) /2

N/S = L x Sin(1 + 2) /2 x Cos(1+ 2) /2

E/W = L x Sin(1 + 2) /2 x Sin(1+ 2) /2

This is very popular method since it

yields accurate results and is fairly simple to use with the aid of a hand calculator . For

this reason it is often used at well site provided the survey stations are not far apart.


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2.2.2.2 Tangential method

In this model the wellpath is assumed

to be a straight line defined by the

inclination and azimuth at the lowersurvey station. The angles measured at

the upper station are not used in the

analysis

V = L x Cos2

CD = L x Sin2

N / S = CD x Cos2

E / W = CD x Sin2

Drawback:Clearly this method gives large error in wellbore position when the trajectory is

changing significantly between stations. This method of calculation is not

recommended.

2.2.2.3 Balanced Tangential Method

This method assumes that the actual well

path can be approximated by two straight

line segments of equal length. The upper

segment is defined by

1 & 1, while lowersegment is defined by 2 & 2.

The length of each segment = L/2

V = L/2 x Cos1 + L/2 x Cos2

= L/2 x (Cos1 + Cos2)

CD = L/2 x Sin1 + L/2 x Sin2

= L/2 x (Sin1 + Sin2)

N/S = L/2 x Sin1 x Cos1 + L/2 x Sin2 x Cos2

= L/2 x (Sin1 x Cos1 + Sin2 x Cos2)

E/W = L/2 x Sin1 x Cos1 + L/2 x Sin2 x Cos2

= L/2 x (Sin1 x Sin1 + Sin2 x Sin2)

This method is more accurate than tangential method since it does take in to account both sets

of survey data.

2.2.2.4 Radius of Curvature Method

This method assumes that well path is not a straight line but a circular arc . The arc is

tangential to the inclination and azimuth at each survey station . The well path can be

described as an arc in the plane, which is wrapped around a right vertical cylinder.


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V = L/(2 -1) x (180/) x (Sin2 -

Sin1)

CD = L/(2-1) x (180/ ) x (Cos1 -

Cos2)

N/S = L/(2-1) x (180/)2 x(Cos1 -

Cos2) x (Sin2 - Sin1)/ (2 - 1)

E/W = L/(2-1) x (180/)2 x (Cos1 -

Cos2) x (Cos1 - Cos2)/ (2 - 1)

This method provides better results than

average angle method in section of the

hole where path is closer to circular arc.

(e.g. during Kick-off). However it

assumes a constant radius which may

not be true over longer intervals. In straight sections of the hole there are computational

problems due to division by zero.

2.2.2.5 Minimum Curvature Method

This method is an extension of balanced tangential method. This method assumes well path

by circular arc instead of straight lines. For this a ratio factor is used which is based on the

amount of bending in the well path between the two stations. This is called dog-leg angle

which can be calculated from

DL = Cos-1[Cos1 x Cos 2 + Sin 1 x Sin 2 x Cos(2 - 1)]

and ratio factor F is given as

F = 2/ DL x (180 / ) x Tan DL / 2

This ratio factor is applied to the results of V , N / S , E /W , as in balanced tangential method

.


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V = F x L / 2 x (Cos 1 + Cos 2)

N/S = F x L / 2 x (Sin1 x Cos 1 + Sin2 x Cos2)

E/W = F x L / 2 x (Sin1 x Sin 1 + Sin2 x Sin2)

This method is most often adopted for directional surveying calculations. Due to morecomplicated mathematics involved, this method is more suitable for computer techniques.

Comparison of above techniques

2.3 DIRECTIONAL WELL PLANNING

The careful planning of a directional well prior to commencement of the actual operations is

probably the most important part of the project. Each directional well has a specific objective.

Care must be taken that all aspects of the well are tailored to meet those objectives at the

planning. Directional well drilling basically involves drilling a hole from one point in space

(surface location) to another point in the space (target location) in such a way that the drilled

well meets its objectives.

The planning of a directional well requires the following information:

1.Surface and Target Co-ordinates: UTM, Lambert or geographical.

2. Size of and shape target(s).

3. Local Reference Co-ordinates: For multi-well sites, these must include template,

platform centre and slot location.

4. Required well inclination when entering the target horizon.

5. Prognosed Litho logy: including formation types, TVD of formation tops, formationdipand direction.


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6. Offset well bit and BHA data: Required for bit walk, building tendencies of BHAs.

7. Casing programme and drilling fluid types.

8. Details of all potential hole problems which may impact the directional well plan or

surveying requirements.

9. A listing of definitive survey data of all near-by wells which may cause a collision

risk. For offshore drilling, this listing should include all wells drilled from the same

platform template or near-by platforms and all abandoned wells in the vicinity of

the new wells.

2.3.1 Factors Involved in well planning:

1. Target size and shape:

The smaller the target zone the greater the number of correction runs necessary to hit the

target. It results in longer drilling times and higher drilling cost .

The target zone should be as large as the geologist or the reservoir engineer can allow.

The job of directional driller is then to place the well bore with in the target at minimum

cost.

2. Formation characteristics (KOP & Lead )

Hard formations may give poor response to deflection tool resulting in long time and

several bit runs while soft formation may result in large washouts. A soft-medium

formation provides a better opportunity for a successful kick-off. Formations exhibit a

tendency to deflect the bit either left or

to right. The directional driller can

compensate this effect by allowing some

lead angle when orienting the deflection

tool.

3. Walking Tendencies

Under normal rotary drilling the bit will

tend to walk to the right. Sometimes the

bit may also turn towards left. R.H. walk is more at higher WOB and lower inclinations R.H.

walking decreases with:

Increase in RPM Low WOB and High inclination


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4. Optimum Surface Location For The Rig

It is essential to select an optimum surface location for the rig taking advantage of natural

formation tendencies. The bit tends to drill at right angle (up-dip) to the dipping formations

if dip angle 45o.

Effect Of Formation Attitude:

Likewise, the formation attitudes also have effect on directional tendencies. If proposed

direction is due up dip, it follows the natural bit tendencies and drift angle can be readily

built.

But if the proposed direction is left of up dip the bit will tend to turn to the right. And if the

proposed direction is right of up dip, the bit will deviate to the left. The rotation of DHM

force the bit to turn to the left.

5. Hole Size: Larger diameter holes are easier to control directionally than smaller diameter

holes. As slim hole requires smaller drill collars and pipes which limits the range of weight

available.

6.Casing And Mud Programme:

Most directional wells follow the same casing program as used in straight hole drilling. Mud

control is extremely important in reducing the torque and drag in directional hole.

7. Location Of Adjacent Well Bores:

To avoid collisions directly below the platform KOPs for adjacent wells are chosen at varying

depths to give some separations. Outer slot is allocated to a target having large horizontal

displacement with shallower KOP while wells having less inclination are allocated to center

of the platform with deeper KOP.

8. Choice Of Build Up Rate:

If BUR is very high, severe dog-legs can occur. These dog-legs can cause difficulty in

running tubular and wear on the pipe. If BUR is very less it will consume more drilling depth

and time. Hence gradual BUR of1.5/100 to 3/100 is commonly used.


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9. Experience Gained From Drilling Previous Directional Wells:

A review of previous drilling practices and problems will give better guide lines for future

wells. Depending on all these factors KOP,BUR and DOR are selected.

2.3.2 Well Profile Definitions

2.3.2.1Inclination angle

The inclination angle of a well at any point is the angle the wellbore forms between its axis

and the vertical.

2.3.2.2Measured Depth

Measured depth (MD) is the distance measured along the well path from one reference point

to the survey point. Measured depth is also known as Along Hole Depth and is measured with

the

pipe tally or by a wire line.

2.3.2.3True vertical depth (TVD) is the vertical distance measured from a reference point

to the survey point. TVD is usually referenced to the rotary table, but may also be referenced

to

mean sea level.

2.3.2.4Kick-off point

The kick off point is defined as the point below the surface location where the well is

Deflected from the vertical. The position of the kick off depends on several

parameters including: geological considerations, geometry of well and proximity of other

wells.

2.3.2.5 Build up rate and Drop off rates

The maximum permissible build up /drop off rate is normally determined by one or more of

the following:

The total depth of the well Maximum torque and drag limitations Mechanical limitations of the drill string or casing

Mechanical limitations of logging tools and production strings. Formation of Key seats in the kick off regions.


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The optimum build up and drop off rates in conventional directional wells are in the range of

1.50 to 30 per 100 ft, although much higher build up rates are used for horizontal and

Multi-lateral wells.

2.3.3 Types of well profiles

If the position of the surface location is known and given the location of the target, its TVD

and rectangular coordinates, it is possible to calculate the best well profile that fits the

coordinates of the surface and the bottom hole target that fit this data.

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, kick- off 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 and therefore the extra maths involved is quite simple as we only need

the measured length of the horizontal section to calculate the total well departure and total

measured depth. The hole total TVD usually remains the same as the TVD of the well at the

start of the horizontal section. However, if the horizontal section is not drilled at 90 degrees

or there are dip variations within the reservoir, then the total hole TVD will be the sum of the

TVD of the horizontal section and the TVD of the rest of the well.

2.3.3.1 Type I

To carry out the geometric planning for a Type I well, Figure 11.13, the following

information is required:

Surface Co-ordinates

Target Co-ordinates

TVD of target

TVD to KOP

Build-up rate


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where = maximum inclination angle at end of build up section

3. Vertical length of build-up section:

4. Horizontal displacement (departure) at end of build-up section:

Tangent Section

5. Measured length of tangent section:

6. Vertical length of tangent section:

7. Horizontal displacement at end of tangent section:

8. Total measured depth for type I wells:

2.3.3.2 'S' TYPE WELL DESIGN

To carry out the geometric planning for a type II well the following information is required:

Surface Co-ordinates

Target Co-ordinates

TVD of target

TVD at end of drop-off (usually end of well)

TVD to KOP

Build-up rate

drop-off rate

Final angle of inclination through target

Because these wells have two curves, two radii need to be calculated and compared with the


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total departure D3. These quantities are then used to calculate the maximum possible

inclination angle at end of build up curve.


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Design Procedure for S Type Well

1. Radius of curvature (R1) of build-up section:

where BUR = build-up rate, degrees/100ft

2. Radius of curvature of drop-off section:

where DOR = Drop off rate, degrees/100ft

The total departure, D3 (or horizontal displacement) of the target is calculated.


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First Case D3 > R1 + R2, Figure 11.14

If the S well returns to vertical at end of drop off section at point D, Figure 11.14, then the

maximum inclination angle is given by:

Second Case D3 < R1 + R2, Figure 11.16

The maximum allowable inclination angle is determined by:

The above equation is only valid if the well returns to vertical at point D,


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For S well that do not return to vertical, first calculate D3,


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For S-wells that partially drop angle and maintain a certain inclination to target V3 is given

by:


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Measured depth at end of a partial drop section where the angle of inclination is maintained

to target is given by:

Total measured depth at end of an S well where the angle of inclination is maintained totarget is given by:


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2.3.3.3 Type III Trajectory

This type of trajectory is used for salt dome drilling and for planning appraisal wells to

assess the extent of the discovered reservoir.

The following data is required:

Surface Coordinates

Target Coordinates

Then one other parameter from:

Maximum inclination angle

TVD to KOP

Build-up rate

Final inclination angle is give by:

Then, Horizontal, vertical and Measured depths can be calculated as before.


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Chapter 3 DIRECTIONAL WELL DRILLING

3.1 Directional Drilling Tools

In search of alternative to conventional rotary drilling where the entire drill string is

rotated from the surface, various types of downhole motors have been proposed. Drill

string rotation can be eliminated by having a motor place down hole to drive the bit

hydraulic power. After second world war, Smith tool co. developed a down hole motor

known as positive displacement motor(PDM).Similarly a turbine motor is also used for

drilling. In such down hole motors hydraulic power of mud that is continuously

circulated inside a wellbore and the hydraulic power of mud in terms of pressure and flow

rate is converted into mechanical power at the bit in terms of rotational speed and torque.

4.1.1 Down hole MotorsDown hole motors are powered by mud flow. The two major type of down hole motors

are:

Turbine

Positive Displacement Motor(PDM)


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The operating principles of turbo-drill and PDM are shown in the above figure. Though their

operating principle is same, their designs are totally different. Turbo-drills were widely used

some years ago.But, due to improvements in PDM turbodrills are used in special applications

today.

3.1.1.1 Turbo Drill

The turbine motor consists of a multistage blade-type motor and stator sections, a thrust

bearing section and a drive shaft. The number of rotor/stator section may vary from 25 to

250. The stator remains stationary and its function is to deflect the mud to the rotor

blades. The rotor blades are attached to the drive shaft, which in turn is attached to the bit.

Mud under high pressure is pumped down the drill string to the motor section, where it is

deflected by stator blades to the rotor blades. This, then, imparts rotation to the rotor and ,

in turn to the drive shaft and drill bit.


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3.1.1.2 POSITIVE DISPLACEMENT MOTORS (PDM)

3.1.1.2.1 Design of PDM

A positive displacement motor (PDM) consists of:

Power section (rotor and stator)

By-pass valve

Universal joint

Bearing assembly

1.Power Section

The PDM consists of a helical steel rotor fitted inside a

spirally -shaped elastomer moulded

stator. Mud flowing under pressure fills the cavities

between the dissimilar shapes of the

rotor and stator and under the pressure of mud, the rotor

is displaced and begins to rotate, the rotor actually

moves in an elliptical shape. This eccentric movement is


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converted to true circular motion by a universal joint assembly.

The magnitude of rotation produced is proportional to the volume of mud pumped through

the motor. The torque generated by the PDM is proportional to the pressure drop across the

motor and is also a function of WOB. An increase in WOB will create more torque and will

in turn increase the differential pressure required across the power module, eventually stalling

the motor due to lack of pressure. Hence, an increase in WOB will cause an increase in

pumping pressure due to the increased differential pressure across the power section. This

fact must be taken into account in drilling operations where only a limited pumping pressure

is available.

2. Lobes

The available rotation and torque from a PDM depend on the pitch angle and number of lobes

in the stator and rotor. The stator always has one lobe more than the rotor.The rotor/stator

configurations (or lobe ratio) currently in use are: 1/2, 3/4, 5/6, 7/8 or 9/10. Configuration 1/2

gives the highest speed and is only suitable for PDC and natural diamond bits. The greater the

number of lobes, the higher the motor torque and the lower the output RPM. Common mud

motors from Baker Hughes Inteq are the Mach 1 which is a 5/6 lobe ratio motor and is

compatible with compatible with tri-cone bits. The Mach 2 is a 1/2 lobe ratio motor and is

used with PDC or diamond bits when high rotation is required.

3. By-Pass valve

This valve allows the drilling fluid to by-pass the mud motor allowing the

drill string to fill during tripping in and drain when making a connection

or pulling out of hole. The valve operates by spring which holds a piston

in the upper position. In this position, ports in the by-pass valve are open

allowing mud to flow in or out of the drill string. At 30% of

recommended flow rate, the piston is forced down, closing the ports and

directing flow through the mud motor.


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4.Universal Joint:

A Connecting Rod Assembly is attached to the lower end of the rotor. It transmits the

torque and rotational speed from the rotor to the drive shaft and bit. Universal joints

convert the eccentric motion of the rotor into concentric motion at the drive shaft.

These are now being replaced by titanium alloy flex shafts.

5.Bearing and Drive Shaft Assembly

The drive shaft is a rigidly-constructed hollow steel component. It is supported within

the bearing housing by radial and axial thrust bearings. The bearing assembly

transmits drilling thrust and rotational power to the drill bit. Most of the mud flows

straight through the centre of the drive shaft to the bit.

3.1.1.2.2 Mud Motor Hydraulics

1. Range of flow rates allowable: Each size and type of PDM is designed to take acertain range of volumes of fluid. Multilobe motors have a broader flow rate range

and a much higher maximum allowable flow rate than 1:2 lobe PDM of the same OD.

This gives better hole cleaning capability- useful when ROP is high.


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2. No-Load Pressure Loss: When mud is pumped through a mud motor which is turningfreely off-bottom, a certain pressure loss is needed to overcome rotor/stator friction

forces and cause the motor to turn. This pressure loss and motor RPM are

proportional to flow rate. Their values are known for each size and type of PDM. The

no-load pressure loss is usually greater than 100 psi.

3. Pressure Drop Across the Motor: As the bit touches the bottom and effective WOB isapplied, pump pressure increases. This increase in pressure is normally called motor

differential pressure. Motor torque increases in direct proportion to the increase in

differential pressure. This differential pressure is required pump a given volume of

mud through the motor to perform useful work. It is also called as pressure drop

across the motor.

4. Stallout Pressure: There is a maximum recommended value of motor differentialpressure. At this point, the optimum torque is produced by the motor. If the effective

WOB is increased beyond this point, pump pressure increases further. The pressure

across the motor increases to a point where the lining of the stator is deformed. The

rotor/stator seal is broken and the mud flows straight through without turning the bit

(blow-by or slippage). The pump pressure reading jumps sharply and does not vary asadditional WOB is applied. 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. This should result

in significantly longer motor life. The greater the wear on the motor bearings, the

easier it is to stall-out the motor. It is useful to deliberately stall out the PDM briefly

on reaching bottom. It tells the directional driller what the stall-out pressure is. He

may want to operate the motor at about 50% of stall-out differential pressure. In any

case, he must stay within the PDM design specifications. It is obvious that, if the

pump pressure while drilling normally with a mud motor is close to the rigs

maximum, stalling of the PDM may lead to tripping of the pop-off valve. This

should be taken into account in designing the hydraulics program.

5. Rotor Nozzle: Most multi-lobe motors have a hollow rotor. This can be blanked off orjetted 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

6. Pressure Drop at the Bit: For a given mud weight and flow rate, the TFA(tool faceangle) of the bit nozzles determine the pressure drop across the bit. The smaller the

TFA, greater the bit pressure drops. This affects the volume of the mud diverted to

cool the bearings. The greater the percentage of the mud diverted the greater the wear

on the bearings. For ANADRILL multi lobe motors, pressure drop across the bit must

be in the range of 500-1500 psi.

Because of their design, multi lobe motors have significantly higher flow rate limits

than 1:2 designs. Higher flow rates lead to faster ROP and better hole cleaning. The


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higher pressure drop across the motor means increased WOB should be used. The

higher pressure drop across the bit means smaller nozzles can be used.

3.1.1.2.3 Hydraulic Thrust

In all PDMs, back pressure from the flow of mud through the motor and bearing assembly

creates a downward axial hydraulic thrust(Wt).

During motor drilling, the weight applied to the bit and formation creates an upward thrust.

The difference between the two thrust forces is supported by the thrust bearing assembly and

transmitted to the body of the motor.

Wt< WOB means OFF-BOTTOM bearings are loaded

Wt=WOB means BALANCED

Wt> WOB means ON-BOTTOM bearings are loaded

For extended bearing life, Wt and WOB should be balanced as closely as possible. In many

extended-interval programs, it is desirable to match bit hydraulics with the weight on the bit

in order to achieve the best drilling results. This is not easily achievable in practice. When

Pbit is high, the WOB required to balance the hydraulic thrust may exceed that recommended

for the PDM and the bit. Hydraulic thrust data and graphs are available to help in optimizing

bearing life.

3.1.1.3 Steerable Drilling Systems

A steerable drilling system allows directional changes (azimuth and/or inclination) of the

well to be performed without tripping to change the BHA, hence its name. It consists of: a

drill bit; a stabilized positive displacement steerable mud motor; a stabilizer; and a directional

surveying system which monitors and transmits to surface the hole azimuth, inclination and

toolface on a real time basis. The capability to change direction at will is made possible by

placing the tilt angle very close to the bit, using a navigation sub on a standard PDM. This tilt

angle can be used to drill in a specific direction, in the same way as the tilt angle generated by

a bent sub with the the drillbit being rotated by the mud motor when circulating. However,

since the tilt angle is much closer to the bit than a conventional bent sub assembly, it

produces a much lower bit offset and this means that the drill bit can also be rotated by

rotating the entire string at surface (in the same way as when using a conventional assembly).

Hence the steerable assembly can be used to drill in a specific direction by orienting the bent

sub in the required direction and simply circulating the fluid to rotate the bit (as in the bent

sub assembly) or to drill in a straight line by both rotating and circulating fluid through the

drillstring. When rotating from surface we will of course be circulating fluid also and


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therefore the rotation of the bit generated by the mud motor will be super-imposed on the

rotation from surface. This does not alter the fact that the effect of the bit tilt angle will be

eliminated by the rotation of the entire assembly. When using the navigation sub and mud

motor to drill a deviated section of hole (such as build up or drop off section of hole) the term

oriented or sliding drilling is used to describe the drilling operation. When drilling in a

straight line, by rotation of the assembly, the term rotary drilling is used to describe the

drilling operation. The directional tendencies of the system are principally affected by the

navigation sub tilt angle and the size and distance between the PDM stabilizer and the first

stabilizer above the motor. The steerable drilling systems are particularly valuable where:

changes in the direction of the borehole are difficult to achieve; where directional control is

difficult to maintain in the tangent sections of

the well (such as in formations with dipping

beds) or where frequent changes may be

required.

The steerable systems are used in

conjunction with MWD tools which contain

petrophysical and directional sensors. These

types of MWD tools are often called Logging

Whilst Drilling, LWD tools. The

petrophysical sensors are used to detect

changes in the properties of the formations

(lithology, resistivity or porosity) whilst

drilling and therefore determine if a change

in direction is required. Effectively the

assembly is being used to track desirable

formation properties and place the wellbore

in the most desirable location from a

reservoir engineering perspective. The term

Geosteering is often used when the

steerable system is used to drill a directional

well in this way.

Components

There are five major components in a Steerable Drilling System (Figure 11). These

components are:


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(a) Drill Bit

(b) Mud Motor

(c) Navigation Sub

(d) Navigation Stabilizers

(e) Survey System

(a) Drill Bit

Steerable systems are compatible with either tricone or PDC type bits. In most cases, a PDC

bit will be used since this eliminates frequent trips to change the bit.

(b) PDM

The motor section of the system causes the bit to rotate when mud is circulated through the

string. This makes oriented drilling possible. The motors may also have the navigation sub

and a bearing housing stabilizer attached to complete the navigation motor configuration.

(c) Navigation Sub

The navigation sub converts a standard Mud motor into a steerable motor by tilting the bit at

a predetermined angle. The bit tilt angle and the location of the sub at a minimal distance

from the bit allows both oriented and rotary drilling without excessive loads and wear on the

bit and motor. The design of the navigation sub ensures that the deflecting forces are

primarily applied to the bit face (rather than the gauge) thereby maximizing cutting

efficiency.

Two types of subs are presently available for steerable Systems:

The double tilted universal joint housing or DTU and

The tilted kick-off sub or TKO.

The DTU and TKO both utilize double tilts to produce the bit tilt required for hole deflection.

The DTUs two opposing tilts reduce bit offset and sideload forces, and thereby maintaining

an efficient cutting action. The TKO has two tilts in the same direction that are close to the

bit.


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(d) Navigation Stabilizers

Two specially designed stabilizers are required for the operation of the system and influence

the directional performance of a steerable assembly. The motor stabilizer orUpper Bearing

Housing Stabiliser, UBHS is an integral part of the navigation motor, and is slightly

undergauge. The upper stabilizer, which defines the third tangency point, is also undergauge

and is similar to a string stabilizer. The size and spacing of the stabilizers also can be varied

to fine-tune assembly reactions in both the oriented and rotary modes.

(e) Survey System

A real time downhole survey system is required to provide continuous directional

information. A measurement while drilling, MWD system is typically used forthis purpose.

An MWD tool will produce fast, accurate data of the hole inclination, azimuth, and the

navigation sub toolface orientation. In some cases, a wireline steering tool may be used for

this purpose.

3.1.1.4 Rotary Steerable system:

A rotary steerable system is a new form of drillingtechnologyused indirectional drilling. It

employs the use of specialized downhole equipment to replace conventional directional tools

such asmud motors.They are generally programmed by theMWDengineer or directional

driller who transmits commands using surface equipment (typically using either pressure

fluctuations in the mud column or variations in the drill string rotation) which the tool

understands and gradually steers into the desired direction. In other words, a tool designed to

drill directionally with continuous rotation from the surface, eliminating the need to slide

asteerable motor.

The advantages of this technology are many for both main groups of users: geoscientists &

drillers. Continuous rotation of the drill string allows for improved transportation of drilledcuttings to the surface resulting in better hydraulic performance, better weight transfer for the

same reason allows a more complex bore to be drilled, and reduced well bore tortuositydue

to utilizing a more steady steering model. The well geometry therefore is less aggressive and

the wellbore (wall of the well) is smoother than those drilled with motor. This last benefit

concerns to geoscientists because the measurements taken of the properties of the formation

can be obtained with a higher quality.
http://en.wikipedia.org/wiki/Technologyhttp://en.wikipedia.org/wiki/Technologyhttp://en.wikipedia.org/wiki/Technologyhttp://en.wikipedia.org/wiki/Directional_drillinghttp://en.wikipedia.org/wiki/Directional_drillinghttp://en.wikipedia.org/wiki/Directional_drillinghttp://en.wikipedia.org/wiki/Mud_motorhttp://en.wikipedia.org/wiki/Mud_motorhttp://en.wikipedia.org/wiki/Mud_motorhttp://en.wikipedia.org/wiki/Measurement_while_drillinghttp://en.wikipedia.org/wiki/Measurement_while_drillinghttp://en.wikipedia.org/wiki/Measurement_while_drillinghttp://en.wikipedia.org/w/index.php?title=Steerable_motor&action=edit&redlink=1http://en.wikipedia.org/w/index.php?title=Steerable_motor&action=edit&redlink=1http://en.wikipedia.org/w/index.php?title=Steerable_motor&action=edit&redlink=1http://en.wikipedia.org/wiki/Tortuosityhttp://en.wikipedia.org/wiki/Tortuosityhttp://en.wikipedia.org/wiki/Tortuosityhttp://en.wikipedia.org/wiki/Tortuosityhttp://en.wikipedia.org/w/index.php?title=Steerable_motor&action=edit&redlink=1http://en.wikipedia.org/wiki/Measurement_while_drillinghttp://en.wikipedia.org/wiki/Mud_motorhttp://en.wikipedia.org/wiki/Directional_drillinghttp://en.wikipedia.org/wiki/Technology


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3.2 BOTTOM HOLE ASSEMBLY

The bottom hole assembly refers to the drill collars, HWDP, stabilizers and other accessories

used in the drill string. All wells whether vertical or deviated require careful design of the

Bottom hole assembly (BHA) to control the direction of the well in order to achieve the

target objectives. Stabilizersand drill collarsare the main components used to control hole

inclination.

3.2.1

There are three ways in which the BHA may be used for directional control:

1. Pendulum Principle

2. Fulcrum principle

3. Packed hole stabilization principle

3.2.1.1 Pendulum Technique

The pendulum technique is used to drop angle especially on high angle wells where it is

usually very easy to drop angle.The pendulum technique relies on the principle that the force

of gravity can be used to deflect the hole back to vertical.The force of gravity is related to the

length of drillcollars between the drill bit and the first point of tangency between the

drillcollars and hole. This length is called the active length of drillcollars and can be resolved

into two forces: one perpendicular to the axis of the wellbore and is called


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the side force and one acts along the hole. Increasing

the active length of drillcollars causes the side force to

increase more rapidly then the along hole component.

The side force is the force that brings about the

deflection of the hole back to the vertical. Some

pendulum assemblies may also use an under gauge

near-bit stabilizer to moderate the drop rate. High

WOBs used with a pendulum assembly may bend the

BHA and cause the hole angle to build instead of drop.

Also pendulum assemblies have a tendency to walk to the right depending on the type of bit

used and since they are flexible they will follow the natural walk of the drill bit.

3.2.1.2 Fulcrum Principle

This is used to build angle (or increase hole inclination) by utilising a near bit stabiliser to act

as a pivot or a fulcrum of a lever. The lever is the length of the drillcollars from their point of

ontact with the low side of the hole and top of the stabiliser.The drillbit is pressed to the high

side of the hole causing angle to be built as drilling ahead progresses.Since the drillcollars

bend more as more WOB is applied, the rate of angle build will also increase with WOB.

The build rate also increases with:

distance from near bit stabilizer to first stabilizer in the BHA

reduction in RPM

increase in hole angle

reduction in drill collar diameter


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3.2.1.3 Packed Hole Stabilization Principle

This is used to hold or maintain hole inclination and direction

and are typically used to drill the tangent section of a well. The

packed BHA relies on the principle that two points will contact

and follow a sharp curve, while three points will follow a

straight line. Packed BHA have several full gauge stabilizers in

the lowest portion of the BHA, typically three or four

stabilizers. This makes the BHA stiff and hence it tends to

maintain hole angle and direction.

3.2.2 Standard BHA Configurations

Using the three principles of BHA control discussed above, there are five basic types of

BHAs

which may be used to control the direction of the well

1. Pendulum assembly

2. Packed bottom hole assembly

3. Rotary build assembly

4. Rotary drop assembly

5. Steerable assembly

6. Mud motor and bent sub assembly

1. Pendulum AssemblyThe pendulumassembly makes use of the gravitational effects acting on the bit and lower

portion of the BHA to maintain vertical hole or drop angle back to the vertical. In this

assembly, the first string stabiliser is placed approximately 30, 40 or 60 feet above the bit.

The assembly is commonly used as an angle reducing assembly on deviated wells but is

difficult to control.


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2. Packed AssemblyA packed assembly typically uses a near-bit stabiliser and string stabilisers a further 30 and

60 feet from the bit, Figure 11.30. A tightly packed assembly incorporates a further string

stabiliser normally located 15 feet from the bit. This type of assembly is often run where

formation dip cause angle building tendency and is also used to maintain vertical hole when

higher weights (WOB) are used. This BHA is typically used in 12" and 8" hole sections

on vertical well and in tangent sections of deviated wells to maintain the hole inclination.

3. Rotary Build AssembliesA rotary build assembly is based on the fulcrum principle and is used to build hole angle

after initial steering runs on deviated wells. Rotary build assemblies are usually used after

the initial kick-off to eliminate the need for further use of a mud motor.The BHA consists of: near bit stabiliser, two drillcollars, a first string stabiliser located a

further 60 feet from the bit, DC and a further string stabiliser 30 feet above.

During drilling operations, application of WOB causes the two drillcollars above the near bit

stabiliser to be bent and consequently cause the drillbit to loaded on the high side of the hole

thereby causing increases in hole angle as the hole is drilled.

4. Steerable AssembliesSteerable assemblies include the use of the following:

Bent motor housing tool and MWD tool

Double tilted U-joint housing (DTU) and MWD tool

The above BHAs are run stabilised and can be used to drill the build and tangent sections of

a hole. When used in steering mode, a steerable system can be used to correct both hole angle

and direction. In rotary mode, a steerable system is used to maintain hole direction. When

using a steerable system it is essential to determine its directional characteristics in rotary

mode. Where possible, once the main build has been completed, 2 stands should be drilled

in rotary mode to determine the inclination and azimuth tendencies to enable the tangent

section to be drilled without the need for numerous corrections. From experience, it has been

found that numerous small corrections can lead to micro doglegs and severe increases in

torque when drilling deep or extended reach wells.


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5. Mud Motor And Bent SubThis assembly is typically run for performing the initial kick-off and build up sections of

deviated wells, Figure 11.24. It is then pulled prior to running a packed BHA for drilling the

tangent sections. This BHA may also be used for correction runs.

3.2.3 Design Criteria

Design criteria are general guidelines based on equipment specifications and

operating experience for building the bottom hole assembly (BHA). BHAs should be

designed for maximum efficiency. Assembly efficiency is a measure of how well the

assembly does its design function during drilling. This depends on operation, deviation, and

stabilization tools, as well as formation dip, hardness, and drill ability. Computer programs

can aid in the design process. BHAs can be exposed to extremely harsh operating conditions,

depending upon the angle and number of bends and turns, depth, and related factors. They

have a larger diameter and are stronger than the drill pipe string, so tensile strength usually is

not a factor. The simplest BHA, the limber assembly, is a string of drill collars with a bit on

bottom. Larger, full-sized drill collars should be placed in the lower part of the assembly, and

worn, smaller collars should be located in the upper part. Stabilizers and other equipment

should be connected in various combinations to the drill collars for building different

assemblies. The diverting equipment should be placed in the lower section of the assembly,

where it has the most influence on directional control. Small variations in tool spacing may

have a large effect on BHA efficiency.

Ongc Project Report

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