0ld_final report

DECLARATION

I hereby declare that the work presented in this dissertation entitled “TECHNICAL

STUDY ON DIRECTIONAL DRILLING MOTOR” is my original work and wholly carried

out by me. I further declare that it has not been submitted earlier in part or in

whole, to any University, Institution or Organization for the award of any degree.

Station: KAKINADA (SURESH SANAPATHI)

Date: Reg. no- 709212345011

Student’s Signature

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CERTIFICATION This is to certify that Mr. SURESH SANAPATHI, M-Tech II year student of DELTA

STUDIES INSTITUTE, Andhra University, Visakhapatnam has undergone a major

project work on the topic-

“TECHNICAL STUDY ON DIRECTIONAL DRILLING MOTOR”

From December 1st 2010 to January 1st, 2010 under the guidance of

undersigned of Mr.Sandeep Amin Lead technician , Weatherford Oil Tool M.E

Ltd.

He had been introduced to a complete gamut”TECHNICAL STUDY ON

DIRECTIONAL DRILLING MOTOR” through practical works and theoretical

lectures by the subject experts.

His involvement in the learning, studying as well as documentation was

noticeably good and his conduct during the above period was excellent. I

hope he can make better use of the knowledge and skills thus he gained.

I wish him success in his future endeavors.

Internal Guide

Prof. M. Jagannadha Rao M.Sc. (Tech), M.S. Engg. (USA), Ph.D.

Director Delta Studies Institute

College of Science and Technology Andhra University

External Guide

Mr.Sandeep Amin Lead Technician

Weatherford Oil Tool M.E. Ltd. Kakinada

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ACKNOWLEDGEMENTS I firstly offer my thanks to the one and only Almighty God for what He has done and what He has planned further for me. I thank Him for everything he provided to me. On the completion of my dissertation, I very happily take this opportunity to express my sincere thanks to venerable Mr.SACHIN ZENDE, L.W.D Coordinator, Weatherford Oil Tool M.E Ltd, Mumbai, for offering me this project and his valuable guidance and assiduous help in graciously supervising the work till its final shape. I would also very venerably thank Mr.Sandeep Amin, Lead technician, Weatherford Oil Tool M.E Ltd. for guidance on drilling motor which I feel has turned me round and brought me to the frontline in my project. I convey my deep sense of thanks for them.

I express my gratitude to Mr. UMA SHANKAR RAO, for taking special interest, guidance, encouragement and initiating me into my project work.

My heartfelt thanks are extended to MR.Vinod, MR.Vijay, who have given technical views & the entire staff of WEATHERFORD for their kind and lovely co-operation throughout the work and letting us avail the facilities for the present study. Very venerably, I present my hearty gratitude to my Parents who have always been supportive to me and fulfilling all my requisites all through the course of my academics and prayed for my success earnestly believing that I can pursue higher studies uninterruptedly. I express my deep love and respect to them through this and dedicate this work to them.

Last but not the least; I extend my thanks to my colleagues and friends at the work place Prawal, etc. who have all through been a source of strength and motivation during the period of my academics and provided a great co-operation. Their role in the work is highly acknowledged.

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Contents 1.0 INTRODUCTION .....................................................................................................................1

ABOUT THE ORGANIZATION........................................................................................................6

1.1 Objectives ..................................................................................................................................7

1.2 OIL EXPLORATION ..................................................................................................................8

1.3 DRILLING................................................................................................................................15

2. INTRODUCTION TO DIRECTIONAL DRILLING .......................................................................16

2.1 Definition of Directional Drilling...............................................................................................16

2.2 Description of Directional Drilling.............................................................................................17

2.3 Historical Development of Directional Drilling: .........................................................................17

2.4 Controlled Directional Drilling............................................................................................18

2.5 Reasons for Drilling Directional Wells... .............................................................................18

2.6 Bit Technology ........................................................................................................................21

3.0 DRILLSTRING BASICS ................................................................................................................25

4.0 Well Planning Introduction.....................................................................................................26

4.1 Well Profile Terminology......................................................................................................30

4.2 Types of Directional Patterns .............................................................................................31

5.0 MOTOR ASSEMBLY...................................................................................................................35

5.1 MOTOR CONFIGURATION ......................................................................................................35

5.2MOTOR SELECTION ...............................................................................................................36

5.3 POWER TRANSMISSION: ..........................................................................................................39

6.0 COMPONENTS OF MOTOR.....................................................................................................44

7.0 Advances in directional drilling: ...........................................................................................51

7.1 OPERATIONAL OVERVIEW OF ROTARY-STEERABLE SYSTEM ...........................................51

7.2 Advantages of Rotary Steerable System ........................................................................54

8.0 APPLICATIONS OF DIRECTIONAL DRILLING.........................................................................55

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9.0 DRILLING COMPLICATIONS AND REMEDIES.......................................................................58

CONCLUSION: ................................................................................................................................63

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1.0 INTRODUCTION  This report concerns with Basic geological concepts involved in oil formation,

Geophysical methods involved in exploring the crude oil both onshore & offshore. This report

gives comprehensive description on the detailed design of equipment used at drill site & its

technical operation, an overview of the main processes and few complications its remedies in the

interest of overview.

ABOUT THE ORGANIZATION Weatherford International oil tool M.E Ltd. is one of the largest global providers of

advanced products and services that span the drilling, evaluation, completion, production and

intervention cycles of oil and natural gas wells. Weatherford operates in more than 100 countries

with 800 service bases and 16 technology development and training facilities.

Today’s Weatherford is a result of internal growth and innovation as well as the consolidation of

more than 250 strategic acquisitions. From a strategic standpoint, Weatherford has two key

objectives--efficiency and productivity. Weatherford strives for efficiency, both in terms of

delivering results for its clients as well as leveraging its worldwide infrastructure. The ultimate

goal in both cases is to help reduce costs and increase well productivity. As well, Weatherford

has created a portfolio of drilling services and products that make well construction safer reduce

nonproductive time and enhance reservoir deliverability.

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1.1 Objectives 

In this module you will learn the following:

1. Brief description of geology.

2. Recall the historical development of directional drilling.

3. Recognize the reasons for drilling the following types of wells: exploration, appraisal, and

development/production.

4. Identification of several features of a directional well profile & general types of directional

well profiles.

5. Detailed study on Power Section of Motor.

6. Identify descriptions and pictures of directional drilling applications.

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Petroleum literally means Rock Oil. Generally petroleum is related to hydrocarbons,

hydrocarbons are naturally occurring materials, including oil, natural gas, and tar. It is made up

of hydrocarbon molecules. Petroleum supplies almost half of our total energy requirements.

1.2 OIL EXPLORATION Oil is a fossil fuel that can be found in many countries around the world. In this section, we will

discuss how oil is formed and how geologists find it.

FORMING OIL Oil is formed from the remains of tiny plants and animals (plankton) that died in ancient seas

between 10 million and 600 million years ago. After the organisms died, they sank into the sand

and mud at the bottom of the sea. Over the years, the organisms decayed in the sedimentary

layers. In these layers, there was little or no oxygen present. So microorganisms broke the

remains into carbon-rich compounds that formed organic layers. The organic material mixed

with the sediments, forming fine-grained shale, or source rock. As new sedimentary layers were

deposited, they exerted intense pressure and heat on the source rock. The heat and pressure

distilled the organic material into crude oil and natural gas. The oil flowed from the source rock

and accumulated in thicker, more porous limestone or sandstone, called reservoir rock.

Movements in the Earth trapped the oil and natural gas in the reservoir rocks between layers of

impermeable rock, or cap rock, such as granite or marble.

Fig a: Geological formation of oil

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FINDING OIL The task of finding oil is assigned to geologists, whether employed directly by an oil

company or under contract from a private firm. Their task is to find the right conditions for an oil

trap -- the right source rock, reservoir rock and entrapment. Many years ago, geologists

interpreted surface features, surface rock and soil types, and perhaps some small core samples

obtained by shallow drilling. Modern oil geologists also examine surface rocks and terrain, with

the additional help of satellite images. However, they also use a variety of other methods to find

oil. They can use sensitive gravity meters to measure tiny changes in the Earth's gravitational

field that could indicate flowing oil, as well as sensitive magnetometers to measure tiny changes

in the Earth's magnetic field caused by flowing oil. They can detect the smell of hydrocarbons

using sensitive electronic noses called sniffers. Finally, and most commonly, they use

seismology, creating shock waves that pass through hidden rock layers and interpreting the

waves that are reflected back to the surface.

1 2 3

Fig b: Oil& Gas exploration on on-shore

1) Can be trapped by folding.

2) Faulting.

3) Oinching out.

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Fig c: Oil & Gas exploration on offshore using seismology

The shock waves travel beneath the surface of the Earth and are reflected back by the various

rock layers. The reflections travel at different speeds depending upon the type or density of rock

layers through which they must pass. The reflections of the shock waves are detected by

sensitive microphones or vibration detectors -- hydrophones over water, seismometers over land.

The readings are interpreted by seismologists for signs of oil and gas traps. Although modern oil-

exploration methods are better than previous ones, they still may have only a 10-percent success

rate for finding new oil fields. Once a prospective oil strike is found, the location is marked by

GPS coordinates on land or by marker buoys on water.

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 PREPARING TO DRILL Once the site has been selected, it must be surveyed to determine its boundaries, and

environmental impact studies may be done. Lease agreements, titles and right-of way accesses

for the land must be obtained and evaluated legally. For off-shore sites, legal jurisdiction must be

determined. Once the legal issues have been settled, the crew goes about preparing the land:

1. The land is cleared and leveled, and access roads may be built.

2. Because water is used in drilling, there must be a source of water nearby. If there is no natural

source, they drill a water well.

3. They dig a reserve pit, which is used to dispose of rock cuttings and drilling mud during the

drilling process, and line it with plastic to protect the environment. If the site is an ecologically

sensitive area, such as a marsh or wilderness, then the cuttings and mud must be disposed offsite

-- trucked away instead of placed in a pit. Once the land has been prepared, several holes must be

dug to make way for the rig and the main hole. A rectangular pit, called a cellar, is dug around

the location of the actual drilling hole. The cellar provides a workspace around the hole, for the

workers and drilling accessories. The crew then begins drilling the main hole, often with a small

drill truck rather than the main rig. The first part of the hole is larger and shallower than the main

portion, and is lined with a large-diameter conductor pipe. Additional holes are dug off to the

side to temporarily store equipment -- when these holes are finished, the rig equipment can be

brought in and set up.

SETTING UP THE RIG Depending upon the remoteness of the drill site and its access, equipment may be transported to

the site by truck, helicopter or barge. Some rigs are built on ships or barges for work on inland

water where there is no foundation to support a rig (as in marshes or lakes). Once the equipment

is at the site, the rig is set up. Here are the major systems of a land oil rig:

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Fig d: Anatomy of an oil rig

 Power system  Large diesel engines - burn diesel-fuel oil to provide the main source of power Electrical

generators - powered by the diesel engines to provide electrical power

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 Mechanical  system - driven by electric motors Hoisting system - used for lifting heavy

loads; consists of a mechanical winch (drawworks) with a large steel cable spool, a block-and-

tackle pulley and a receiving storage reel for the cable Turntable - part of the drilling apparatus

Rotating equipment - used for rotary drilling Swivel - large handle that holds the weight of the

drill string; allows the string to rotate and makes a pressure-tight seal on the

Hole Kelly - four- or six-sided pipe that transfers rotary motion to the turntable and drill string

Turntable or rotary table - drives the rotating motion using power from electric motors

Drill string - consists of drill pipe (connected sections of about 30 ft / 10 m) and drill collars

(larger diameter, heavier pipe that fits around the drill pipe and places weight on the drill bit)

Drill bit(s) - end of the drill that actually cuts up the rock; comes in many shapes and materials

(tungsten carbide steel, diamond) that are specialized for various drilling tasks and rock

formations

Casing - large-diameter concrete pipe that lines the drill hole, prevents the hole from collapsing,

and allows drilling mud to circulate

Circulation system - pumps drilling mud (mixture of water, clay, weighting material and

chemicals, used to lift rock cuttings from the drill bit to the surface) under pressure through the

kelly, rotary table, drill pipes and drill collars

• Pump - sucks mud from the mud pits and pumps it to the drilling apparatus

• Pipes and hoses - connects pump to drilling apparatus

• Mud-return line - returns mud from hole

• Shale shaker - shaker/sieve that separates rock cuttings from the mud

• Shale slide - conveys cuttings to the reserve pit

• Reserve pit - collects rock cuttings separated from the mud

• mud pits - where drilling mud is mixed and recycled

• mud-mixing hopper - where new mud is mixed and then sent to the mud pits

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Fig e: Drill-mud circulation system

Blowout preventer - High-pressure valves (located under the land rig or on the sea floor) that

seal the high-pressure drill lines and relieve pressure when necessary to prevent a blowout

(uncontrolled gush of gas or oil to the surface, often associated with fire)

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1.3 DRILLING The crew sets up the rig and starts the drilling operations. First, from the starter hole, they

drill a surface hole down to a pre-set depth, which is somewhere above where they think the oil

trap is located. There are five basic steps to drilling the surface hole:

1. Place the drill bit, collar and drill pipe in the hole.

2. Attach the Kelly and turntable and begin drilling.

3. As drilling progresses, circulate mud through the pipe and out of the bit to float the rock

cuttings out of the hole.

4. Add new sections (joints) of drill pipes as the hole gets deeper.

5. Remove (trip out) the drill pipe, collar and bit when the pre-set depth (anywhere from a few

hundred to a couple-thousand feet) is reached.

Once they reach the pre-set depth, they must run and cement the casing place casing-pipe

sections into the hole to prevent it from collapsing in on itself. The casing pipe has spacers

around the outside to keep it centered in the hole.

The casing crew puts the casing pipe in the hole. The cement crew pumps cement down

the casing pipe using a bottom plug, a cement slurry, a top plug and drill mud. The pressure from

the drill mud causes the cement slurry to move through the casing and fill the space between the

outside of the casing and the hole. Finally, the cement is allowed to harden and then tested for

such properties as hardness, alignment and a proper seal.

Drilling continues in stages: They drill, then run and cement new casings, then drill again. When

the rock cuttings from the mud reveal the oil sand from the reservoir rock, they may have

reached the final depth. At this point, they remove the drilling apparatus from the hole and

perform several tests to confirm this finding:

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2. INTRODUCTION TO DIRECTIONAL DRILLING

Introduction

Fig a: Drilling platforms

Directional drilling has become a very important tool in the development of oil and gas deposits.

Current expenditures for hydrocarbon production have dictated the necessity of controlled

directional drilling to a much larger extent than previously.

Probably the most important aspect of controlled directional drilling is that it enables

producers all over the world to develop subsurface deposits that could never be reached

economically in any other manner. In this module a number of topics will be covered that must

be understood by the directional driller. The various types of wells and applications of

directional wells will be touched upon along with well profiles and well planning.

Directional Drilling

2.1 Definition of Directional Drilling

Controlled directional drilling is the science and art of deviating a wellbore along a planned

course from a starting location to a target location, both defined with a given coordinate system.

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2.2 Description of Directional Drilling

Drilling a directional well basically involves drilling a hole from one point in space (the

surface location) to another point in space (the target) in such a way that the hole can then be

used for its intended purpose.

A typical directional well starts off with a vertical hole, then kicks off so that the bottom

hole location may end up hundreds or thousands of feet or meters away from its starting point.

With the use of directional drilling, several wells can be drilled into a reservoir from a single

platform.

2.3 Historical Development of Directional Drilling:

Directional drilling was initially used as a remedial operation, either to sidetrack around

stuck tools, bring the wellbore back to vertical, or in drilling relief wells to kill blowouts. Interest

in controlled directional drilling began about 1929 after new and rather accurate means of

measuring the hole angle were introduced during the development of the Seminole field,

Oklahoma, USA.

The first application of oil well surveying occurred in the Seminole field of Oklahoma

during the late 1920’s. A subsurface geologist found it extremely difficult to develop logical

contour maps on the oil sands or other deep key beds. The acid bottle inclinometer was

introduced into the area and disclosed the reason for the problem; almost all the holes were

crooked, having as much as 50 degrees inclination at some check points.

Fig b. Directional Drilling

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 2.4 Controlled Directional Drilling The science of deviating a wellbore along a planned course to subsurface target whose

location is at a given lateral distance and direction from the vertical, at a specified vertical depth.

Drilling a wellbore with planned deviation from vertical to pre-determined target(s).

Figure c: Controlled directional drilling

2.5 Reasons for Drilling Directional Wells... • Surface reasons

• Subsurface reasons

• Special needs

Surface Reasons...

• Surface obstructions (rig/well positioning problems)

• Restrictions (health, safety or environmental)

• Economics of rig positioning

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Fig d: surface obstructions

Surface Obstructions

• Unsuitable terrain (sloped ground, marsh, forest, sand dunes, etc)

• Proximity to other wells, pipelines, oilfield facilities

• Populated area (city or rural area, farmhouse, Industrial facility)

• Proximity to power lines

• Airports, radar or radio stations

• Access road and site preparation difficulties

Sub-surface Reasons...

• Collision risk with existing wells

• Multiple targets to open for production

• Horizontal drain(s) needed

• Re-entering producing formations

• Drilling extended reach wells (ERD) to remote target(s)

Sub-surface Reasons...

Geological problems exist

• Faults

• Floating Blocks,

• Salt Domes

» Known natural deviation tendencies caused by significant formation dip

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» Sidetracking (lost) down hole objects

» Relief well required

 SPECIAL NEEDS 

Formation Dip Effects

Laminar formation dipping 45°or less :

• Each layer fractures perpendicular to

• bedding planes

• Bit tilt is significant contributor

• Bit is forced to up dip

• Formation strike

• Laminar formation dipping > 45°

• Bit follows the formation plane

Note : dip angle is measured from horizontal ! Fig e: Formation effects

Fig f: side tracking when object is lost Fig g: Relief well required

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2.6  Bit Technology 

Rolling Cutter Rock Bits

The primary drilling mechanism of the rolling cutter bits is intrusion, which means that

the teeth are forced into the rock by the weight-on-bit, and pulled through the rock by the rotary

action. For this reason, the cones and teeth of rolling cuttings rock bits are made from specially,

case hardened steel.

One advantage of a rolling cutter bits is the three bearing design located around the journal of the

bit. Heel bearings are roller bearings, which carry most of the load and receive most of the wear.

Middle bearings are ball bearings, which hold the cone on the journal and resist thrust in either

direction. The nose bearing consists of a special case hardened bushing pressed into the nose of

the cone and a male piece, hard faced with a special material, to resist seizure and wear.

Although rock bits have been continually improved upon over the years, three developments

remains outstanding:

(1) The change in water course design and the development of the “jet” bit,

(2) The introduction of the tungsten carbide insert cutting structure, and

(3) The development of sealed journal bearings.

Polycrystalline Diamond Compact Bits

In the early days of oil well drilling, fishtail/drag bits were used extensively throughout

the oilfields. In 1976, the cutting structure of the polycrystalline diamond compact (PDC) has

made the drag bit competitive with the conventional roller cone and diamond bits.

PDC Drill Blanks

These drill blanks consist of a layer of synthetic polycrystalline diamond bonded to a

layer of cemented tungsten carbide using a high-temperature, high-pressure bonding technique.

The resulting blank has the hardness and wear resistance of diamond which is complemented by

the strength and impact resistance of tungsten carbide. PDC blanks are self-sharpening in the

sense that small, sharp crystals are repeatedly exposed as each blank wears, and because they are

polycrystalline these blanks have no inherently weak cleavage planes, which can result in

massive fractures as in the large, single crystal diamonds in the diamond bits.

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Diamond Bits

Diamond core bits were introduced into the oilfield in the early 1920's and were used to

core extremely hard formations.

The Diamond Bit A diamond bit (either for drilling or coring) is composed of three parts:

• Diamonds

• Matrix &

• Shank.

The diamonds are held in place by the matrix which is bonded to the steel shank. The

matrix is principally powdered tungsten carbide infiltrated with a metal bonding material. The

tungsten carbide is used for its abrasive wear and erosion resistant properties (but far from a

diamond in this respect). The shank of steel affords structural strength and makes a suitable

means to attach the bit to the drill string.

Uses of Diamond Bits

• Deep, small holes: Roller cone bits that are 6-inch and smaller have limited life due to the space

limitations on the bearing, cone shell thickness, etc. Diamond bits being one solid piece often last

much longer in very small boreholes.

• Directional drilling: Diamond side tracking bits are designed to drill “sideways” making it a

natural choice for “kicking off” in directional drilling situations.

• Coring: The use of diamond bits for coring operations is essential for smooth, whole cores.

Longer cores are possible with increased on bottom time and cores “look better” because of the

cutting action of diamond bits as compared to those of roller cone bits.

Fig h: Roller cutting bit Fig i: PDC bit Fig j: Diamond bit

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Torque

Torque indications are very useful as a check on smooth operation. No absolute values

have been set up, but a steady torque is an indication that the previous three factors are well

coordinated.

Bit Stabilization

A diamond is extremely strong in compression, but relatively weak in shear, and needs

constant cooling when on bottom. The bit is designed and the rake of the diamonds set, so that a

constant vertical load on the bit keeps an even compressive load on the diamonds, and even

distribution of coolant fluid over the bit face. If there is lateral movement or tilting of the bit, an

uneven shear load can be put on the diamonds with coolant leakage on the opposite side of the

bit. Any of the standard “stiff-hookup” or packed hole assemblies are suitable for stabilization

when running diamond bits. It is recommended that full gauge stabilizers be run near the bit, and

at 10 feet and 40 feet from the bottom.

Drilling

After the bit has been started, rotary speed should be increased to the practical limit

indicated by rig equipment. The drill pipe, hole condition, and depth should also be taken into

consideration. Weight should be added as smoothly as possible in 2000 pound increments.

Observations of penetration rate after each weight increase should be made to avoid overloading.

As long as the penetration rate continues to increase with weight, then weight should be

increased. However, if additional weight does not increase the penetration rate, then the weight

should be reduced back 2000 to 3000 pounds, to avoid packing and balling-up of the space

between the diamonds. Drilling should be continued at this reduced weight. After making a

connection, be sure to circulate just off bottom for at least five minutes, as cuttings in the hole

could damage the bit. The time spent here may lengthen the life of the bit by many hours.

Selection Guideline

Because formations of the same age and composition change in character, with depth,

and drill differently, no universal bit selection guide can be prepared. However, general

guidelines include:

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Soft formations

Sand, shale, salt, anhydrite or limestone require a bit with a radial fluid course set with

large diamonds. Stones of 1-5 carats each are used, depending on formation hardness. This type

of bit should be set with a single row of diamonds on each rib and designed to handle mud

velocities ranging from 300-400 fps to prevent balling.

Medium formations

Sand, shale, anhydrite or limestone require a radial style bit with double rows of

diamonds on each blade or rib. Diamond sizes range from 2-3 stones per carat. Mud should be

circulated through these bits at a high velocity. Good penetration rates can be expected in

interbedded sand and shale formations.

Hard, dense formations

Mudstone, siltstone or sandstone usually requires a crowsfoot fluid course design. This

provides sufficient cross-pad cleaning and cooling and allows a higher concentration of

diamonds on the wide pads. Diamond sizes average about 8 stones per carat.

Extremely hard, abrasive or fractured formations

Schist, chert, volcanic rock, sandstone or quartzite’s require a bit set with small diamonds

and a crowsfoot fluid course to permit a high concentration of diamonds. The diamonds (about

12 per carat) are set in concentric “metal protected” ridges for perfect stone alignment, diamond

exposure and protection from impact damage.

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3.0 DRILLSTRING BASICS 

Introduction

Drill pipe and collars are designed to satisfy certain operational requirements. In general,

down hole tubular must have the capability to withstand the maximum expected hook load,

torque, bending stresses, internal pressure, and external collapse pressure. Other concerns, such

as the presence of H2S, must also be considered in the selection process. Drill Pipe Yield

Strength and Tensile Strength If drill pipe is stretched, it will initially go through a region of

elastic deformation. In this region, if the stretching force is removed, the drill pipe will return to

its original dimensions. The upper limit of this elastic deformation is called the Yield Strength,

which can be measured in psi. Beyond this, there exists a region of plastic deformation. In this

region, the drill pipe becomes permanently elongated, even when the stretching force is removed.

The upper limit of plastic deformation is called the Tensile Strength. If the tensile strength is

exceeded, the drill pipe will fail. Tension failures generally occur while pulling on stuck drill

pipe. As the pull exceeds the yield strength, the metal distorts with a characteristic thinning in the

weakest area of the drill pipe (or the smallest cross sectional area). If the pull is increased and

exceeds the tensile strength, the drillstring will part. Such failures will normally occur near the

top of the drillstring, because the top of the string is subjected to the upward pulling force as well

as the downward weight of the drillstring.

YIELD STRENGTH = Yield Strength x π/4 (OD^2—ID^2)(in pounds)(in psi)

Fig a: Drill String

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4.0 Well Planning Introduction There are many aspects involved in well planning, and many individuals from various

companies and disciplines are involved in designing various programs for the well (mud

program, casing program, drill string design, bit program, etc. This section will concentrate on

those aspects of well planning which have always been the provinces of directional drilling

companies.

1. Target Size and Shape:  The objective of a oil well is to reach the target: pay zone However there may be other objectives

in drilling a well inn additions to intersecting the pay zone:

• Defining the geological features such as pinch outs or faults.

• Defining reservoir structures.

• Intersecting another well as in relief well drilling.

The point to be penetrated is called target and area around the target is the target zone. This

allows the directional driller some tolerance in the final positioning of the well. A radius of 50

meters is commonly used as a target zone. However, this depends on particular requirements.

• 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.

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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

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

formation tendencies.

Effect of formation attitude – • Like wise, 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 forces the bit to turn to the left.

4. Hole size:  Larger diameter holes are easier to control directionally then smaller diameter holes. As

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

5. Casing and Mud Programming:  Most directional wells follow the same casing program used in straight hole drilling. Mud

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

6. Location of Adjacent Wells:  On offshore platforms, distance between adjacent conductors is small. In this situation

precise control is required. Therefore, kick off points for adjacent wells are chosen at varying

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depths to give some separations to avoid collisions directly beneath the platforms and problems

of wells running across each other.

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

depths to give some separations.

7. 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 of 1.5 to 0.5 is commonly used.

If the change of angle occurs too quickly, severe dog-legs can occur in the trajectory.

Sharp bends make it difficult for drilling assemblies and tubulars to pass through and also causes

more wear on the drill string.

8. Experience Gained From Drilling Previous Directional Wells :  A review of previous drilling practices and problems will give better guide lines for

future wells.

Planning a directional well path:

• Kick off point.

• Build up rate.

• Azimuthal direction.

• Inclination angle.

• True vertical depth.

• Measured depth.

• Horizontal displacement.

Fig b: Direction of the well

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Well drilled without Planning:  

29

4.1 Well Profile Terminology 

Fig d: Basic Well Profiles

30

•TVD - True Vertical Depth

•TMD - Total Measured Depth

•DLS - Dog-Leg Severity

•BUR - Build-Up Rate

• Inclination - The Angle from Vertical

•Azimuth - The Direction of the Well

4.2 Types of Directional Patterns These complex well paths are harder to drill and the old adage that “the simplest method

is usually the best” holds true. Therefore, most directional wells are still planned using traditional

patterns which have been in use for many years. Common patterns for vertical projections are

shown on the following:

Build and Hold

Simplest

• Inclination 15 -55°

• KOP determines inclination

• Large horizontal displacements at shallow depths

Applications:

• Deep wells with large horizontal displacements

• Moderately deep wells with moderate horizontal displacement, where intermediate casing

is not required

Build Hold and Drop

More difficult control

• Increased torque and drag

• Multiple target intersection

• Small horizontal displacement

• Near vertical target Penetration

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Applications: Disadvantages:

Multiple pay zones - Increased torque & drag

Reduces final angle in reservoir - Risk of key seating

Lease or target limitations - Logging problems due to inclination

Well spacing requirements

Deep wells with small horizontal displacements

Fig e: Build and Hold Fig f: Build Hold and Drop

Continuous Build to Horizontal

• Most simple to drill

• Minimum hole length

• Short horizontal displacement to target

• Smallest measured depth

• Long lateral hole is possible

Applications:

• Appraisal wells to assess the extent of a newly discovered reservoir

• Repositioning of the bottom part of the hole or re-drilling

• Salt dome drilling

Disadvantages:

Formations are harder so the initial deflect ion may be more difficult to achieve

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Harder to achieve desired tool face orientation with down hole motor deflection assemblies

(more reactive torque) Longer trip time for any BHA changes required

Fig g: Continuous Build to Horizontal

On multi-well platforms, only a few wells are given deep kick-off points, because of the

small slot separation and the difficulty of keeping wells vertical in firmer formation. Most wells

are given shallow kick-off points to reduce congestion below the platform and to minimize the

risk of collisions

Horizontal wells Horizontal well is defined as the well drilled in the zone parallel to the bedding plane.

The well is deflected to the 90° from vertical and the drain hole is placed exactly in the drainage

area. The objective of the first horizontal well, is to determine if a horizontal well could be

drilled economically and to acquire production data to see if future horizontal redevelopment in

the field is beneficial. The directional objective to drill a horizontal section is staying in the top

3m ( 10 ft ) of the sand to increase sweep efficiency and to stay as far as possible from the

oil/water contact thereby lowering the water cut. For many applications, the best well profile is

one in which the inclination is built to 90° or even higher. Unfortunately there are other

considerations (e.g. water injection wells may have to be grouped together for manifold

requirements). Also, as more wells are drilled and the reservoir model is upgraded, targets can be

changed or modified.

33

Types of horizontal wells : • Long Radius (1°-5°/100 ft.)

• Medium Radius (5°-20°/100 ft.)

• Short Radius (20°-40°/100 ft.)

• Ultra Short Radius (45°-90°/ ft.)

Fig h: Multilateral wells

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Kick‐off Point and Build‐Up Rate The selection of both the kick-off point and the build-up rate depends on many factors.

Several being hole pattern, casing program, mud program, required horizontal displacement and

maximum tolerable inclination. Choice of kick-off points can be limited by requirements to keep

the well path at a safe distance from existing wells. The shallower the KOP and the higher the

build-up rate used, the lower the maximum inclination. Build-up rates are usually in the range

1.5°/100' M.D. to 4.0°/100' M.D. for normal directional wells. Maximum permissible dogleg

severity must be considered when choosing the appropriate rate. In practice, well trajectory can

be calculated for several KOPs and build-up rates and the results compared. The optimum choice

is one which gives a safe clearance from all existing wells, keeps the maximum inclination

within desired limits and avoids unnecessarily high dogleg severities.

5.0 MOTOR ASSEMBLY The motor section consists of a rubber stator and steel rotor. The simple type is a helical

rotor which is continuous and round. This is the single lobe type. The stator is molded inside the

outer steel housing and is an elastomer compound. The stator will always have one more lobe

than the rotor. Hence motors will be described as 1/2, 3/4, 5/6 or 9/10 motors. Both rotor and

stator have certain pitch lengths and the ratio of the pitch length is equal to the ratio of the

number of lobes on the rotor to the number of lobes on the stator. As mud is pumped through the

motor, it fills the cavities between the dissimilar shapes of the rotor and stator. The rotor is

forced to give way by turning or, in other words, is displaced (hence the name). It is the rotation

of the rotor shaft which is eventually transmitted to the bit.

5.1 MOTOR CONFIGURATION  

Standard drilling Motor

• Standard bearing pack

• Power section lined with a standard or premium elastomer

• Conventional power sections

35

High Performance Drilling Motor

• High torque bearing pack

• Power section lined with a standard or premium elastomer

• High torque power section

5.2 MOTOR SELECTION 

High Speed Motors–These motors work well in applications where high torque is not

required, such as drilling soft formations.

Medium Speed Motors – These motors have been designed for increased flow rates,

rotary speeds, and torque outputs. They are used in drilling applications where above

normal flow rates are desired such as when needing to clean a hole better due to

increased penetration rates or where high rotary speeds are desired.

Low Speed Motors – These motors have both low speed & high torque outputs which

are ideal for applications such as drilling in hard formations. By design the multi-lobe

configuration provides the ability for high torque output in a shorter length tube which is

beneficial in applications such as high build radius drilling.

Conventional Power Section – These are used for the most common drilling

applications and consist of the widest variety of speeds, torques & lengths.

High Torque Power Section – This configuration is used when the torque output

desired cannot be achieved with a conventional power section. Typically it will consist

of a hard elastomer such as NBR250 which can accommodate larger pressure drops

and thus produce higher torque outputs. This level of performance is only available on

medium & low speed motors. They are ideal for use with aggressive PDC bits and in

applications where maximum torque is required.

Even Rubber Thickness Power Sections - These motors utilize even rubber thickness

technology which has a higher pressure rating over conventional power section s and

thus provide a much higher torque capacity. They are ideal for use with aggressive PDC

bits and in applications where maximum torque is required.

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Different Motors Sizes:   The following are the different motor sizes with respective hole sections. They are listed below as follows:

S. No HOLE SECTIONS STABILIZER

SLEEVE MOTORS AT DIFFERENT SIZES

1 26” 25 ¾” 9 5/8” 11 ¼”

2 17 ½” 17 3/8” 9 5/8” -

3 12 1/4” 12 1/8” 9 5/8” 8”

4 8 ½” 8 3/8” 6 ¾” -

5 6” 5 ¾” 5 7/8” 4 ¾”

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CHANGE IN MOTOR :

OPERATION Converts hydraulic power from the drilling fluid into mechanical power to drive the bit

– Stator – steel tube containing a bonded elastomer insert with a lobed, helical pattern bore

through the center

– Rotor – lobed, helical steel rod

• When drilling fluid is forced through the power section, the pressure drop across the cavities

will cause the rotor to turn inside the stator

Pattern of the lobes and the length of the helix dictate the output characteristics

• Stator always has one more lobe than the rotor

• Stage – one full helical rotation of the lobed stator

• With more stages, the power section is capable of greater differential pressure, which in turn

provides more torque to the rotor

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5.3 POWER TRANSMISSION: This is a short tool which has a set number of stages and its bearing section entirely

within one housing. That is, it is not a sectional tool and will be typically less than 30 feet long.

It is designed for short runs to kick off or correct a directional well, using a bent sub as the

deflection device.

Figure: Cross-section of a turbine motor

Motor Observations • There is minimal surface indication of a motor stalling.

• Sand content of the drilling fluid should be kept to a minimum.

• Due to minimal rubber components, the turbine is able to operate in high temperature wells.

• Pressure drop through the tool is typically high and can be anything from 500 psi to over 2000

psi.

• Motors do not require a by-pass valve.

• Usually, the maximum allowable bearing wear is of the order of 4mm.

Motor Characteristics • Torque and RPM are inversely proportional (i.e. as RPM increases, torque decreases and vice

versa).

• RPM is directly proportional to flow rate (at a constant torque).

39

• Torque is a function of flow rate, mud density, blade angle and the number of stages, and varies

if weight-on-bit varies.

• Optimum power output takes place when thrust bearings are balanced.

• Changing the flow rate causes the characteristic curve to shift.

• Off bottom, the turbine RPM will reach “run away speed” and torque is zero.

• On bottom, and just at stall, the turbine achieves maximum torque and RPM is zero.

• Optimum performance is at half the stall torque and at half the runaway speed, the turbine then

achieves maximum horsepower.

• A stabilized turbine used in tangent sections will normally cause the hole to “walk” to the left.

 REACTIVE TORQUE Generally drilling motor turns the bit with a right-hand (clockwise) rotation. As WOB is

increased, reactive torque is developed in a left-hand (counter-clockwise) direction on the

drilling motor housings. Reactive torque is transferred to the BHA and may cause the

connections above the power section to tighten or connections below to loosen. Reactive torque

increases with larger WOB and reaches a maximum when the motor stalls. Reactive torque

affects directional control and must be taken into account when orienting the drilling motor

from the surface in the desired direction.

Reactive torque is created by the drilling fluid pushing against the stator. Since the stator

is bonded to the body of the motor, the effect of this force is to twist the motor and BHA anti-

clockwise. As weight-on-bit is increased, the drilling torque created by the motor increases, and

reactive torque increases in direct proportion.

Factors Affecting Reactive Torque

The reactive torque which motors generate will be in direct proportion to the differential

pressure across the motor. This in turn is influenced by:·

• Motor characteristics

• Bit characteristics

• Formation drillability

• Weight on bit

40

Estimation of reactive torque has always been a problem for directional drillers. Several charts

and rules of thumb have evolved. One is:

EXPECTED REACTIVE TORQUE = 10° - 20° / 1000 ft M.D.

MAXIMUM RPM FOR MOTOR BEND SETTING 

The following are the different bend settings with their respective rpm’s. As from

the below table it refers that as the Bend setting goes on decreasing the RPM goes on

increasing.(Straight Hole) Maximum RPM for Motor Bend Setting (Straight Hole) Bend

Setting 1.83º 1.5º 1.15º 0.78º 0.39º

RPM 60 70 90 110 150

The following are estimated build rates with Sick, One Stabilizer, & Two Stabilizer. This

table refers that build developed is increasing with respect to the increase in stabilizers & its

placement at certain distances.

ESTIMATED BUILD RATES           Degrees / 30m (100 ft.) 

41

ROTARY BHA

It consists of a bit, drill collars, stabilizers, reamers run below the drill pipe. In deviated

well the drill collar makes contact with the low side of the hole. The placement of the stabilizer

in the BHA effects the size of the side force and hence dictates weather the BHA will build or

drop the angle. A stabilizer placed just above the bit acts as the fulcrum. The weight of the collar

above the stabilizer acts as the lever to make the build angle. As the distance between the bit and

the stabilizer increase the upward force on the bit is reduced. Using the concept the BHA can be

designed for the required purpose in the bore hole.

Building Assemblies This type of assembly is usually run in a directional well after the initial kick-off has been

achieved by using a deflection tool. A single stabilizer placed above the bit will cause building

owing to the fulcrum effect. The addition of further stabilizers will modify the rate of build to

match the required well trajectory. If the near-bit stabilizer becomes undergauge, the side force

reduces. Typical building assemblies are shown in Fig. Assemblies A and B respond well in soft

or medium formations. The inclusion of an undergauge stabilizer in assembly C will build

slightly less angle. By bringing the second stabilizer closer to the near-bit stabilizer, the building

tendency is increased. In hard abrasive rocks, the problems of bit wear are significant. To

maintain gauge hole, the near-bit and second stabilizer should be replaced by roller reamers. The

build rate should be kept below 2' per 100 ft to reduce the risk of dog-legs. The amount of WOB

applied to these assemblies will also affect their building characteristics. Too much WOB will

cause rapid build-up of angle.

Holding Assemblies Once the inclination has been built to the required angle, the tangential section of the well is

drilled using a holding assembly. The object here is to reduce the tendency of the BHA to build

or drop angle. In practice this is difficult to achieve, since formation effects and gravity may alter

the hole angle, To eliminate building and dropping tendencies, stabilizers should be placed at

close intervals, using pony collars if necessary. Assembly I) in Fig. 3.7 has been used

successfully in soft formations. The undergauge stabilizer in assembly E builds slightly to

counter gravity, In harder formations the near-bit stabilizer is replaced by a reamer. Generally

42

only three stabilizers should be used, unless differential sticking is expected. Changes in WOB

will not affect the directional behavior of this type of assembly, and so optimum WOB can be

applied to achieve maximum penetration rates. A packed hole assembly with several stabilizers

should not be run immediately after a down hole motor run.

Dropping Assemblies In directional wells, only an S shape profile requires a planned drop in angle. The other

application of a dropping assembly is when the inclination has been increased beyond the

intended trajectory and must be reduced to bring the well back on course. It is best to drop

i. Building assembly  

ii. Holding assembly  

43

iii. Dropping assembly  

6.0 COMPONENTS OF MOTOR 

MUD LUBRICATED BEARING SECTION 

The bearing section contains the radial and thrust bearings that 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. Mud lubricated bearing sections utilize a limited portion of drilling fluid

for lubrication and cooling. The drilling fluid by-passing through the bearing section exits

directly above the bit box and rejoins the primary flow to help clean the hole.

STABILIZATION Bearing housings are available with screw-on style stabilization. This provides the

option of installing a stabilizer sleeve on the rig floor in a matter of minutes. The drilling motor

can be operated slick through use of a thread protector sleeve when stabilization is not

required.

44

DRIVE ASSEMBLY 

The design of the power section imparts an eccentric rotation of the rotor inside the

stator. To compensate for this eccentric motion and convert it to a concentric rotation. 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 delivered by the power

section. 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.

POWER SECTION The power section is comprised of two components: the stator and the rotor. The stator

consists of a steel tube containing a bonded elastomer insert with a lobed helical pattern bored

through the center. The rotor is a lobed helical steel rod. When the rotor is installed into the stator

the combination of the helical shapes form sealed flow 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 rotation provides power to the bit.

The performance characteristics of a power section are controlled by the following design

criteria.

• Lobe configuration

• Stages

• Power section fit

• Elastomer

Generally as the lobe ratio is increased speed of rotation is decreased, and torque

output is increased.

A stage is defined as a full helical rotation of the lobed stator. Power sections may be

classified in stages. As the number of stages increases, a power section is capable of greater

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

The power section fit is the compression or clearance between the rotor and stator. Each power

section configuration is designed with a specific fit to optimize performance output. Many

45

configurations have options available for larger clearance specifically designed to compensate for

elastomeric swell caused by temperature and/or drilling fluid.

Elastomers & Its Types: 

The stator elastomer has a large influence on the overall performance output, drilling fluid

compatibility, and operating temperature limit. Weatherford drilling motors have a variety of

elastomeric compounds available to suite the needs of each drilling application.

Weatherford drilling motors use a variety of elastomers that can be classified by their basic

compound make up.

SE r

The choice for rubber typ

following are different ty

  Types of Mud’s UsThere are mostly t

Oil based drilling fluid

temperatures, increasing

drilling fluid compatibil

HSN (Highly Saturated N

For as such drilli

rotor. But incase of wate

tator lastome

NBR – Nitrile Butadiene Rubber (Nitrile)

or

HNBR – Hydrogenated Nitrile Butadiene Rubber

Rotor

StatorTube

es depends upon the type of drilling fluid used at drill site. The

pes of mud’s used at drill site.

ed at the drill site: wo types of mud’s used at drill site. They are below as follows

1. Oil based type

2. Water based type

has a tendency to degrade stator elastomer, particularly at higher

the risk of elastomer failure. HNBR is used in applications where

ity or temperature is an issue. HNBR is also sometimes classified as

itrile Butadiene Rubber).

ng fluid clearance fit is maintained in between the stator elastomer and

r based mud tighter fit is maintained and standard rubber is used.

46

BOTTOM HOLE ASSEMBLY  

String Float Sub String Float subs are designed to be run above the motor and contain a float valve. The float

valve prevents drilling fluid from back flowing and keep cuttings out of the motor and drill pipe.

This helps prevent damage to the stator and keeps the bit from plugging up. It is also used under

the following conditions.

• Drilling unconsolidated formations

• Drilling underbalanced

• Milling Steel

• Sour H2S wells

• Added blow out protection

String Stabilizers String stabilizers can be used with drilling motors to help change the build rate characteristics of

that motor or help stabilize the BHA. These come in a large variety of styles and gauge diameters

to meet specific drilling requirements. Estimated build rates using both a screw-on stabilizer and

a string stabilizer

can be found on each

motor spec sheet

under the two stabilizers

column.

Subs Alignment  

Alignment subs are a tool used in applications requiring the high side bend on the

drilling motor be aligned with another drilling tool further up on the BHA.

47

Adjustable Gauge Stabilizers Adjustable gauge stabilizer can be used above the motor to make changes to the build

rate and rotary build rate characteristics of the BHA while drilling. It is a hydraulically acti-

vated tool with stabilizer blades that can be extended or retracted radially from its body gauged

for the wellbore.

Back‐Off Prevention Historically, drilling motor connection back-offs occur when little or no WOB is being

applied. At these times the vibrations created by the drilling motor are at their highest

amplitudes which increase risk of connection back-off.

This may occur when:

• Reaming

• Time drilling

• Sidetracking

• Circulating

• Drilling underbalanced with compressible fluids

• Drilling with a rotor by-pass

When operating a drilling motor with little or no WOB being applied the operator

must reduce the flow rate to 20% to 30% of the maximum allowable flow rates. In

addition to the applications mentioned above, when WOB is about to be removed the flow

rate should be reduced prior to picking up. This will reduce vibration of the BHA.

Once significant WOB has been applied the flow rate can again be brought back up as

high as the maximum allowable flow rate. Applying this procedure as consistently as

possible will reduce risk of connection back-offs.

 DEFINE JARRING:  A tool operated mechanically to give an upward thrust to a fish by the sudden release of

a tripping device inside the tool. If the fish can be freed by an upward blow, or downward blow

the jar can be very effective. This mechanical action is called jarring.

There are three types of jars. They are below as follows

48

• Mechanical Jar

• Hydraulic Jar

• Hydro-mechanical Jar

Details on jarring:

• Jarring can induce high tensile and compressive shock loads on

drilling motor components.

• Jarring loads are typically much larger than the over pull load

required to actuate the Jar.

• Jarring down in an over gauge hole may result in serious damage to

the motor due to buckling.

Rotor Catch Functioning The operator should be able to quickly identify connection twist-off or

back-off. The identifying features are:

• Pressure loss when the bit is on bottom (due to loss of flow through housing).

• When the motor is off bottom the standpipe pressure will increase.

• With WOB reapplied the pressure increase disappears.

The rotor catch mandrel will bottom on the inside shoulder of the motor top sub. In this

condition, circulation is not possible and will result in a significant standpipe pressure increase.

The rotor catch design is to prevent a portion of the motor from separating in the event of a

housing connection failure.

TOP SUB ROTOR CATCH Drilling motors come with a rotor catch assembly as standard equipment. The rotor catch is a

safety device that allows the motor to be pulled out of hole in the event of a connection failure.

The catch mandrel, which is connected to the rotor, will catch on the inside of the top-most sub of

the drilling motor ensuring that when pulling out of the hole the rest of the drilling motor will

come with it. When engaged for retrieval, care must be used to prevent over stressing the catch

49

mandrel. Top sub rotor catch assemblies have options available for an integrated float or ported

rotor catch mandrel for rotor by-pass (jetting).

DIFFERENTIAL PRESSURE To compensate for reduced elastomer strength at higher temperatures the amount of

elastomer loading from drilling should be reduced accordingly.

The reduction in loading will offset the reduction in elastomer strength and help reduce

loss in life expectancy associated with temperature. The loading that occurs on the

elastomer is directly related to the differential pressure applied across the power section

while drilling.

The Load Curve Scaling Factors at Temperature chart can be used as a guideline to

scale the differential pressure based on temperature.

The differential scaling factor can be used in two ways.

1. To limit the maximum differential pressure on a specific motor configuration

based on temperature

2. To adjust the operating differential pressure on a specific motor configuration for a

different temperature

The maximum differential pressure (maximum operating differential pressure)

indicated on each motor spec sheet is based on operating at temperatures below 140ºF

(60ºC). At temperatures above this the maximum differential pressure must be scaled

down. To calculate, find the DSF (Differential Scaling Factor) for the maximum

expected downhole circulating temperature. Multiply this number by the maximum

differential pressure indicated on the motor spec sheet to determine the new maximum

differential pressure.

New Max. differential pressure = Max. differential pressure x DSF

(Temp. adjusted) (As per spec)

50

If an ideal operating differential pressure is known for a drilling application at a specific

temperature, the DSF can be used to adjust the operating differential pressure accordingly for a

different temperature. To calculate a new operating differential pressure, find the DSF for both

the old temperature and the new temperature. Multiply the old differential pressure by the new

temp DSF divided by the old temp DSF to determine the new differential pressure required.

New Differential Pressure = Old Diff. Pressure x New Temp. DSF `

Old Temp. DSF

7.0 Advances in directional drilling: Rotary steerable tools were introduced to the oil and gas industry in the early 1990’s.

Two basic types emerged; “push-the-bit” and “point-the-bit”. Pushing the bit refers to exerting

lateral side force on the bit as it drills ahead. Pointing the bit involves bending the assembly so

that the bit is pointed toward the intended direction while drilling. Point-the-bit is generally

acknowledged as being superior; resulting in smoother well bores with increased dogleg

capability. OBJECTIVES OF ROTARY‐STEERABLE SYSTEM

• Better well placement

• Smoother wellbores

• Larger operating envelopes

• Enhanced productivity

• Reduced nonproductive time (NPT)

7.1 OPERATIONAL OVERVIEW OF ROTARY‐STEERABLE SYSTEM The Revolution® system is the first 4 ¾-in. rotary steerable system to use point-the-bit

drilling technology for improved borehole quality and bit life. The Revolution® uses a near-bit

stabilizer to orient the drill bit axis with the axis of the desired hole. Experience and testing have

shown that point the- bit drills smoother, cleaner wellbores by cutting with the face of the bit.

51

The Revolution’s simple, compact design makes it reliable and cost-effective—and easy to scale

up for larger tool sizes.

A non-rotating outer sleeve is used with anti-rotation paddles to restrict it from rotating

with the drillstring. A center drive shaft is incorporated to transmit torque through the tool to the

bit, with the sleeve and shaft being decoupled by bearings. Relative rotation between the center

shaft and the nonrotating outer sleeve drives a hydraulic pump. This pump generates the motive

force required to eccentrically offset the drive shaft within the sleeve. When changes in wellbore

direction are required, hydraulic pistons are activated to deflect the shaft from the stabilizer

sleeve centerline. This shaft deflection forces the bit to point in the opposite direction. The tool’s

onboard navigation control electronics direct the internal hydraulic system via an electrically

operated solenoid. The solenoid energizes particular pistons, controlling toolface and deflection.

Should the sleeve begin to roll, the electronics redirects the hydraulic system to maintain the

required toolface and deflection settings. Sensors mounted on the center shaft measure actual

drillstring toolface, actual deflection and relative rpm between the sleeve and shaft. Power for the

control electronics is provided through an internal lithium battery. The electronics insert also

houses a nearbit inclination sensor, and has provision for near-bit azimuth and gamma ray

measurement capabilities. Uplink telemetry is accomplished with mud pulse via an internal

biphase connection with the PrecisionLWD™ system.

52

BHA CONFIGURATION:  The standard BHA configuration consists of the following elements:

53

The bias unit sleeve, pivot stabilizer and dog sub are all true gauge or very close to it.

Experience and testing have shown that this is the optimum configuration for maximizing

directional performance with the tool. The tool is capable of generating doglegs of up to 12

degrees/100 ft or more with this setup. At 90 degrees inclination tests have also shown that with

zero deflection the tool tends to hold angle or build slightly. Obviously, this is formation

dependent and therefore varies to some degree from well to well. To build angle at 6 degrees/100

ft with the tool with little or no turn, a 0 deg toolface and 50–60% deflection should be initially

selected (a general guide). Monitor the resulting surveys then adjust the setting accordingly to

obtain the required dogleg and counteract any turn. Be aware that formation changes can have a

significant impact on tool response. The assembly achieves the build by deflecting the bias unit

sleeve upwards and internal shaft downwards, which in turn pushes the collar above the pivot

stabilizer downwards. The pivot stabilizer pivots and points the dog sub and bit upwards to build

angle. This is illustrated below:

7.2 Advantages of Rotary Steerable System 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 drilled

cuttings 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 tortuosity due to

utilizing a steadier 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.

Drilling directional wells with a rotary steerable system results in a smoother wellbore.

This results from constant rotation and deflecting the drillstring through adjustments

down-hole.

Rotary-steerable systems (RSS) outperform conventional directional systems by significantly

improving the drilling process through better hole cleaning, higher rates of penetration (ROPs),

precise directional control and extended reach of horizontal wells.

Weatherford's Revolution RSS uses "point-the-bit" technology to deliver a gun-barrel in-

gauge wellbore. The high-quality wellbore provides significant benefits, including improved

formation evaluation, reduced drilling-fluid costs, easier installation of tubular and enhanced

production

In the future, rotary steerable technology must address operator expectations for even

faster rates of penetration. Powered rotary steerable tools will make this possible. Other

enhancements will provide even greater reliability and efficiency. Ultimately, Rotary steerable

drilling will allow companies to drill out the casing shoe and continue drilling to the next casing

point in a single run. With industry costs for nonproductive drilling time estimated at US$ 5

billion per year, rotary steerable systems will be a key to preventing or reducing these significant

losses.

54

8.0  APPLICATIONS OF DIRECTIONAL DRILLING 

1. Sidetracking: Side-tracking was the original directional drilling technique. Initially, sidetracks

were “blind". The objective was simply to get past a fish. Oriented sidetracks are most common.

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

(Figure 3.1).

Fig 3.1 Side tracking Fig 3.2 Inaccessibility

2. Inaccessible Locations: Targets located beneath a city, a river or in environmentally

sensitive areas make it necessary to locate the drilling rig some distance away. A directional well

is drilled to reach the target (Figure 3.2).

3. Salt Dome Drilling: Salt domes have been found to be natural traps of oil accumulating 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 3.3), thus avoiding the

problem of drilling through the salt

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4. Fault Controlling: Crooked holes are common when drilling nominally vertical. This is often

due to faulted sub-surface formations. It is often easier to drill a directional well into such

formations without crossing the fault lines (Figure 3.4).

Fig 3.3 Salt Dome drilling Fig 3.4 Fault drilling

5. Multiple Exploration Wells from a Single Well-bore: A single well bore can be plugged back at

a certain depth and deviated to make a new well. A single well bore is sometimes used as a point

of departure to drill others (Figure 3.5). It allows exploration of structural locations without

drilling other complete wells.

Fig 3.5 Multiple wells Fig 3.6 Drilling into shallow offshore reservoirs

6. Drilling into shallow offshore reservoirs: Reservoirs located below large bodies of water which

are within drilling reach of land are being tapped by locating the wellheads on land and drilling

directionally underneath the water (Figure 3.6). This saves money-land rigs are much cheaper.

7. Offshore Multi-well Drilling: Directional drilling from a multi-well offshore platform is the

most economic way to develop offshore oil fields (Figure 3.7). Onshore, a similar method is used

where there are space restrictions e.g. jungle, swamp. Here, the rig is skidded on a pad and the

wells are drilled in “clusters".

8. Multiple Sands from a Single Well-bore: In this application, a well is drilled directionally to

intersect several inclined oil reservoirs (Figure 3.8). 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.

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Fig 3.7. Offshore Multi-well Drilling Fig 3.8 Multiple Sands from a Single Well-bore 9. Relief Well: The objective of a directional relief well is to intercept the bore hole of a well

which is blowing and allow it to be “killed" (Figure 3.9). The bore hole causing the problem is

the size of the target. To locate and intercept the blowing well at a certain depth, a carefully

planned directional well must be drilled with great precision.

10. Horizontal Wells: Reduced production in a field may be due to many factors, including gas

and water coning or formations with good but vertical permeability. Engineers can then plan and

drill a horizontal drainhole. It is a special type of directional well (Figure 3.10). Horizontal wells

are divided into long, medium and short-radius designs, based on the buildup rates used. Other

applications of directional drilling are in developing geothermal fields and in mining.

Fig 3.9 Relief well Fig 3.10 Horizontal wells

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9.0 DRILLING COMPLICATIONS AND REMEDIES

DRILLING MOTOR STALL Stalling occurs when the power section is overloaded, stops rotating, and is incapable

of providing enough torque to turn the bit. This may be caused by one, or a

combination, of the following:

• Excessive WOB

• Excessive bend setting or dogleg severity

• Excessive string RPM

• Inadequate hole cleaning or hole sloughing

• Sudden change in formation

VIBRATION 

Vibration while drilling is expected. However, the operator can control the level of

vibration that the motor is subject to downhole. Severe downhole vibration can cause

damage to the motor, BHA, drill string, and even surface components.

Some damaging results of vibration include:

• Connection back-off

• Premature bit wear

• Chipped PDC cutters

• Cracking & twist-offs

• Motor & MWD/LWD failures

• Over torqued connections

• Uneven stabilizer wear

• Directional control issues

• Top drive or rotary stalling

• Excessive wear or drill string washout

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BIT BOUNCE 

Axial vibration is caused by large WOB fluctuations causing the bit to undergo impact

loading. Not only are these vibrations damaging to the bit but also to components in the

BHA. While commonly observed when drilling with tri-cone bits in hard formations, bit

bounce can occur in other situations.

Detecting Bit Bounce 

• Erratic fluctuations of the WOB / hook load

• Visible bouncing motion of the top drive and kelly hose

• Slower rate of penetration (ROP)

• Excessive damage / wear to bit

Mitigating Bit Bounce • Pick up off bottom / work out all torque and vibration

• Decrease RPM / WOB

• Running shock sub in drill string near the bit

Fi

3

1

gure 6. Lateral vibration

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Dog legs ‐ lead to torque (permissible dog leg‐ threshold)  

− Have closer interval surveying when drilling with

limber hookups. This takes more time to survey.

− Do not assume that dog-leg is removed by

reaming. Make sure by re-surveying at same

depth.

− Use dog-leg chart to determine the acceptable dog-

leg for each program.

• Plug back and sidetrack well if an excessive dog-leg cannot be eliminated.

Key seats ‐ more problems in soft formation 

− Keep dog-legs to minimum

− Use keyseat wipers (hard formations) and string reamers (soft formations)

− Make daily wiper trips

Wall sticking –always a problem when drill string is stationary during survey 

and motor run 

− Add lubricant (oil) to the mud system

− Keep pipe stationary to a minimum

− Use HWDP (reduces contact area – spiral

DC)

− Use stabilizers & drilling jars

− Design casing program to help reduce open-hole

Hydraulics 

− Reduce hydraulics while building angle

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− High annular velocities may erode hole while jetting

Lateral drift 

− Normally influenced by bedding planes, hence use structural maps for pre-

planning

− Use true rolling-cone bit (zero offset)

− Use rebel tool (azimuth control tool)

− Use jetting with packed BHA

Small hole and Ream Vs. One Pass 

− Larger holes more difficult to control

− Dog-legs for larger hole not uniform

− Of course a small hole needs to be opened up to larger hole takes time

Plan Vs Actual 

− Plan the well will a lead to the left

− Design lead so that if no walk occurs, one deflection tool run will bring it back to

selected parameters

− Rule of thumb “Never allow yourself to be more than one tool run away from the

target area”

Weight on Bit and Rotary Speed 

− Variation is used to control angle & walk

− Because WOB & RPM are reduced, this method is not always conducive to max.

penetration

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Off‐bottom rotation 

− Creates a ledge and leads to sidetrack

− Aggravates and initiate keyseating

Intersection ‐ Bit and Casing 

− Common on multi-platform or drilling pads – develop structural plots (spidal

diagram).

− Curved conductors may be necessary

− Use gyro orientation survey and short course lengths

Hard & Soft Lines 

− Soft lines are preferred because hard lines cannot be changed, varied, or extended

(lease or fixed areas). Select big target radius.

Casing wear 

− Use rubber pads on the drill string and slow down

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10.0 CONCLUSION: Directional drilling has become a very important drilling process. It has enabled

producers all over the world to develop subsurface deposits that could never have been reached

economically in any other manner. In this module, directional drilling was defined along with its

historical development. The applications of a directional well as well as the features of a well

profile were also covered. The module also included information on the types of well profiles

and the components of a well plan.

A smaller number of wells, located even at a great distance from sensitive and protected

areas, implies a significant reduction in the infrastructures necessary to develop and keep a field

in production, such as drilling sites, service roads, parking areas, and means of transport. All of

this implies less pressure on the area with great advantages for the environment.

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