Bha

BHA & DRILL STRING FUNDAMENTALS STUDENT MANUAL Revised 06-2008

Special thanks to: Kenny Amend – Director of Training Sarah Wakefield – Instructional Designer Katrina Pigusch – Technical Writer Beverlyn Bankes – Graphics Designer

©2008 Smith International, Inc.

COURSE

BHA & DRILL STRING FUNDAMENTALS Course Objective

At the end of this course, you should be able to: o Basic Knowledge o The rig and its basic components o Introduction to the drill string and its components o Types of wells o Deviation and controlling deviation o BHAs o BHA Specifics o Drill Pipe Overview o Drill Pipe Connection Science o Failure Mechanisms o Includes an inspection section o Drill String Design o Step by Step instruction on the math involved with creating a drill string

Suggested Pre-requisites

N/A

Course Topics

Basic Knowledge BHA Specifics Drill Pipe Overview Connection Science Failure Mechanisms Drill String Design

Following Along

When you see this on the screen:

The number in the PowerPoint presentation is the page number for your student manual.

You should see this in your manual:

Acronyms From This Book API

American Petroleum Institute

BHA

Bottom Hole Assembly

BSR

Bending Strength Ratio

DC

Drill Collar

DEI

Diamond Enhanced Insert

DLS

Dog Leg Severity

DP

Drill Pipe

DS

Dual Shoulder

ERD

Extended Reach Development

EMI

Electromagnetic Induction

FH

Full Hole

HWDP

Hevi-Wate Drill Pipe

IBS

Integral Blade Stabilizer

ID

Inside Diameter

IF

Internal Flush

MD

Measured Depth

MT

Magnetic Particle Inspection

NC

Numbered Connection

OD

Outside Diameter

PT

Liquid Penetrant

RFO

Reed Full Opening

ROP

Rate of Penetration

SS

Single Shoulder

SSC

Sulfide Stress Cracking

TVD

True Vertical Depth

UT

Ultrasonic Inspection

VDS

Vertical Drilling System

VT

Visual Inspection

WFJ

Wilson Flush Joint

WOB

Weight on Bit

Course Overview Introduction

The Bottom Hole Assembly (BHA) course is divided into four modules. The first module focuses on BHA basics. There are six chapters in this manual.

Basic Knowledge

Chapter one contains basic knowledge explaining what a rig is and its major components. Also covered is an introduction to the drill string and components. Following the drill string and component introduction we will transition into actual well drilling. A variety of well types will be addressed. We will discuss well site challenges including deviation causes, formation types, doglegs and keyseats. These challenges can be controlled by specific BHA components and assemblies.

BHA Specifics

Chapter two covers detailed information on the BHA components introduced in the chapter one. A drill collar has multiple benefits, including adding weight to the BHA. There are a variety pipe types in the BHA, called Hevi-Wate pipe (referred to as transition pipe because it transitions from the BHA to the top of the drill string). The stabilizer, a BHA component, is available in many varieties depending on the application. Reamers are available in multiple configurations. The rotary substitute is used to connect BHA components. By the end of this chapter you will have a thorough familiarity with these terms.

Drill Pipe Overview

Chapter three explores the anatomy of a drill pipe, covering the production process. To ensure the drill pipe is manufactured defect free, there are several pre and post production inspections. Drill pipe specifications are designed to meet multiple conditions including support strength, overcoming downhole variations and combating pressures. Also discussed is drill pipe identification. Finally, we will talk about how drill pipe from a job site undergoes a thorough inspection process to ensure optimum quality before it is sent to the next job.

Drill Pipe Connection Science

Chapter four discusses threaded connections on the end of every drill string component. Depending on the component, the threaded connection may be the least or most probable part to fail. Downhole components will bend, either slightly or drastically. The connection’s bending strength can create severe problems during the drilling process. The chapter ends with an exercise using tool joint identifiers (devices which measure threaded connections).

Failure Mechanisms

There are multiple causes for a drill string failure. This chapter explores failure types, as well as their causes and avoidance. Tension (stretch of the drill string), torsion (twisting), fatigue (cycles of stress), buckling, burst/collapse, and corrosion are common drill string component failures. Drill string component failures may be reduced using methods discussed in class.

Drill String Design

The final chapter introduces basic mathematic equations to calculate drill string design. Each equation builds on the next equation, in order for you to learn a complete method for calculating the drill string.

Basic Knowledge

CHAPTER 1

BASIC KNOWLEDGE Module Objective

At the end of this chapter, you should be able to: o Identify and explain basic knowledge about drill string components, causes of deviation, poor wellbore quality issues, as well as features of various BHAs o Understand basic well drilling o Identify basic drill string components used to drill a well o Identify basic wellbore types o Identify deviation causes and the components used to control deviation o Explain wellbore quality challenges and the affect on cost and prolonged wellbore creation o Identify various BHAs and the conditions where they are most useful

Topics

Exercise: Makin’ Hole Introduction to Drill String Components Types of Wellbores Causes of Deviation Wellbore Quality BHA Components used to Control Deviation Exercise: Deviation, Quality and Components Bottom Hole Assemblies BHA Drilling Techniques: Pendulum BHA Drilling Techniques: Packed Hole BHA Drilling Techniques: Angle Building Vertical Drilling System Exercise: BHA Configurations

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 1 – Basic Knowledge

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Exercise: Makin’ Hole

While watching the video, answer the following questions. 1. What are the four systems available on all rigs?

2. What equipment turns the pipe?

3. In what ways can a top drive reduce drill time?

4. What components are included in the hoisting system?

5. What is the purpose of mud during the drilling process?

©2008 SMITH International, Inc.

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Introduction to Drill String Components BHA Overview

A drill string design includes several components. Drill strings are unique. The BHA can include the drill bit, drill collars, stabilizers, reamers, and Hevi-Wate drill pipe. The remainder of a drill string is drill pipe. A correctly designed drill string can:

Drill String Designs

©2008 SMITH International, Inc.

o Produce a high quality hole o Maximize performance of components o Minimize drilling and production problems

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Drill Bit

At the bottom of all BHAs is a drill bit. The bit design will vary BHA depending on the formation. Its primary function is creating the hole by digging into the earth. The correct bit will provide a good rate of penetration (ROP), last a reasonable number of hours, and drill holes the same size as the bit. There are essentially two types of bits. The first is the Roller Roller Cone Bit Cone Bit (left). This bit gets its name because the bit teeth roll over the bottom of the hole. Most Roller Cone Bits have three cones, although they may have four or two cones. The Roller Cone Bit is sometimes referred to as the “jetted bit” because its high pressure jets spray mud. The Fixed-Head Bit (right) doesn’t PDC Drill Bits have moving parts like the Roller Cone Bit. It penetrates a formation by the weight and rotation of the drill string. The cutters are made from natural, synthetic or hybrid diamonds.

Stabilizer

Stabilizers are included in multiple places in a drill string, usually before and after one or more drill collars. Depending BHA on the stabilizer type its function can vary. A stabilizer can help maintain hole direction when used throughout the BHA design. A stabilizer will help increase the stiffness of a BHA when used with larger or smaller OD drill collars.

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Reamer

A reamer has several drill string purposes including smoothing the wall of the wellbore, maintains hole gauge BHA and helps stabilize the bit. Reamers are generally required during hard rock formation drilling. The reamer is placed directly above the bit to prolong the bit life and prevent sticking.

Drill Collar

The Drill Collar is located just above the drill bit to put weight on the bit (WOB). The WOB will affect the rate of BHA penetration. The Drill Collar performs additional functions including preventing the drill string from buckling, bit support and stabilization, and maintaining a vertical or straight hole.

Jars

A Jar frees stuck drill stem components during drilling or workover operations. The driller controls the impact force of “jarring” both up and down. It can be placed almost anywhere in the BHA for optimal performance.

Hevi-Wate Drill Pipe

Hevi-Wate drill pipe is typically located above the drill collars, and technically it is part of the BHA. Sometimes BHA referred to as transition pipe, it provides a graduated change in stiffness between the limber drill pipe above and the BHA below. The graduated change in stiffness reduces the likelihood of drill pipe fatigue failures. Hevi-Wate drill pipe has thicker walls than standard drill pipe, causing it to weigh twice as much. Hevi-Wate has a center upset which reduces the pipe wear and aids in preventing critical buckling.

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 1 – Basic Knowledge

BHA

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Drill Pipe

Drill Pipe is located at the very top of the drill string. It makes up the distance between the Kelly and the remainder of the drill string downhole. The drill pipe turns the drill string and provides a conduit for the drilling mud.

Drill String

The drill string components are described in detail later this chapter. Our current focus is each component’s basic function in the drill string.

©2008 SMITH International, Inc.

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Types of Wellbores Introduction

Some wells are not drilled vertically. The production zone may be intersected in multiple ways depending on specific well factors. This section introduces wellbores and what circumstances require a specific wellbore.

Vertical Wellbores

The most basic wellbore is the Vertical Wellbore, although they are rarely vertical. It is almost impossible to drill a perfectly vertical wellbore, so there will be changes in direction. The degree of change is generally limited to 3º for every 100 feet drilled.

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Horizontal Wellbores

A Horizontal Wellbore is a directional wellbore where the leg that deviates from vertical is close to a 90º angle. The Horizontal Wellbore is used when the production zone is relatively narrow or has a low porosity and is at a very shallow angle, or to penetrate the production zone further and increase the exposure to the zone.

Directional Wellbore

A Directional Wellbore is intentionally drilled away from vertical. The Directional Wellbore is drilled for a variety of reasons including a production zone that is below a surface structure (example: city or a lake). A Directional Wellbore may be drilled to intersect multiple production zones or one production zone many times. Do not confuse a Directional Wellbore with a Deviated Well. A Deviated Well is an unplanned change in direction. There are tools and equipment used to correct a Deviated Well.

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Extended Reach Development (ERD)

An Extended Reach Development (ERD) well is a type of horizontal wellbore. To be an ERD the horizontal portion of the well must be more than twice the measured length of the vertical portion of the well. This well type is especially beneficial in offshore production where another production zone can be reached without an additional rig.

MD vs. TVD

The terms measured depth (MD) and true vertical depth (TVD) are used to determine the exact position of an area downhole. The MD is the depth along the wellbore path; this is a known measurement because the driller knows what components have gone downhole. The TVD is the distance from a point in the well to the surface of the earth not following the wellbore path

©2008 SMITH International, Inc.

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Causes of Deviation Introduction

Unplanned wellbore deviations are among the many problems that may occur during drilling. The origin of deviation is not precisely known. Experience suggests that formation factors are a primary cause of deviation. A formation factor is anything related to the ground being drilled including fracturing, faulting, drillability, and non-uniformity.

Formation Factors

Geologists study formations. Petroleum Geologists are specifically concerned with finding hydrocarbons (oil). Hydrocarbons tend to be trapped in certain areas depending on formation changes, such as faulting. Accessing the hydrocarbons in a complex formation can present drilling challenges. Fracturing

A fracture is a stress point in the earth’s crust. The fracture is caused by movement of the earth’s crust, which exerts tremendous pressure on the formations.

Fractured Rock

Faulting

Fault

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A fault is the shifting of a fractured formation due to gravity. A normal or gravity fault occurs when the overhanging side slides downward. If the fault is characterized as a reverse or thrust fault, there was an upward movement of the overhanging side. Describing a fault’s degree of shifting is called a formation dip. The dip is the degree of inclination (from horizontal) of the layers.

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Laminate Formations

A laminate formation is one where there are many different narrow layers of materials or rock type. Typically when a laminate formation is drilled the alternating layers of material can cause the bit to deflect from its normal course. The bit will tend to deviate in the direction where there is the least amount of resistance.

Laminate Formation

Non-Uniformity

The term uniformity suggests consistency. Calling a formation non-uniform suggests there is a lack of consistency. Drilling a hole with non-uniform properties presents a challenge because the formation could include alternating hard and soft layers, laminate, and faulting. Non-uniform properties in a drilling formation will result in a crooked hole. Deviation is expected while drilling. There are preventative measures to control deviation. Deviation type and control are discussed in the next two sections.

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Wellbore Quality Introduction

Wellbore deviation may present a big drilling problem. Formation factors can create excess issues to arise while cementing or casing a hole. Fortunately, there are some simple well drilling techniques that facilitate the quality of a wellbore.

Doglegs

When holes do not remain “vertical” a dogleg or Dogleg Severity (DLS) can form. A dogleg is a hole angle change and/or direction of more than 3° per 100 feet. All wellbores have deviations, but they should be gradual and controlled. A dogleg is formed by abrupt or sharp angle changes (due to drastic change in WOB), and sudden or significant change in formation. Doglegs may cause the borehole to be off course and can cause physical problems to drilling components.

Dogleg and Key Seat Comparison

Stuck and/or Damaged Casing

Running casing through a dogleg can be a very serious problem. If casing becomes stuck in the dogleg before reaching the productive zone, it is necessary to drill out the shoe and set a smaller size pipe. Even if casing is run to the bottom successfully, it can be damaged, thereby preventing the running of production equipment. Cementing

A dogleg will force casing tightly against the wall of the wellbore, preventing a good cement job. The cement cannot circulate between the wall of the wellbore and the casing at the point of contact. Casing Wear

Drill pipe, rotating against casing in the dogleg or dragging through it while tripping, can damage or wear a hole in the casing. It can cause the acceleration of cyclic stresses, resulting in drill pipe fatigue.

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Key Seats

The chance of a key seat is increased by an existing dogleg. A key seat is an irregularity the size of the drill pipe tube. It forms because of the pipe rotation in or through a sharp bend in the hole. It usually occurs during the soft formation penetration. It is caused by a combination of rotational and tensional forces exerted by the drill stem on the wellbore. A dogleg will increase the likelihood of key seats.

Key Seat

Lateral Force

Dip Angle

Unlike doglegs and keyseats, the dip angle is a natural deviation tendency. A BHA wants to drill perpendicular to the angle of the formation planes. In formations with dip angles 45º to 60º or less, the bit tends to drill “up-dip.” The natural tendency of a BHA is to drill perpendicular to the angle of the formation.

Dip Angle

Offset Ledges

An Offset Ledge is formed within a wellbore when an unstabilized bit drills into alternating hard and soft formations. The softer formations tend to “wash out” above and below the hard formations. This action creates a ledge intruding into the wellbore creating a natural “whipstock effect” sending the bit another direction. The best way to prevent offset ledges is to use a packed hole assembly during drilling.

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Techniques for a Quality Wellbore

Wellbore quality issues cannot be solved completely, but can be reduced. Two solutions to help maintain a vertical or planned deviation wellbore are maintaining Weight on Bit (WOB) and Hole Clearance. Weight on Bit (WOB)

WOB is the force that makes a hole. Depending on the type of formation being drilled, an increase or decrease of WOB is necessary for the most effective penetration. If too much pressure is applied to the BHA, there is a higher tendency for the drill string to bend or buckle near the bit. Bending or buckling initiates a deflection causing an increase in deviation. As the well is drilled, an increased rate of penetration (ROP) is the goal. Drilling faster than the cuttings can be circulated out of the hole and formation hardness can reduce success. An increase of WOB is required to penetrate a harder formation; however the increase can also cause the bit to deflect. The deflection could possibly result in a dogleg or an abrupt change in wellbore direction. Correctly designing the BHA to offset its tendency to buckle will allow us to drill a better wellbore. Hole Clearance

The drill collar size is directly related to the size of the drill bit selected. Using a small drill collar will result in excessive room in the annulus (space between drill collar and wall of the hole) allowing the bit to move. The moving bit will create a crooked hole. If the drill collar too big for the bit, there won’t be adequate room in the annulus for the mud to circulate which may create a wellbore washout. Downhole problems are usually solvable. Often the BHA components need to be changed, moved, or added. Additional changes to control deviation are discussed in the next section.

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BHA Components Used to Control Deviation Introduction

Sometimes it’s necessary to do more to a drill string to control deviation than add WOB or ensure the proper size drill collar. The following components are used in a drill string to control deviation.

Drill Collars

The Drill Collar helps with vertical holes. A drill collar is heavier and stiffer than drill pipe and provides more weight close to the bit. There are multiple drill collars types available. When differential sticking occurs, a Spiral Drill Collar is useful. A Square Drill Collar can maintain WOB and provide an annulus area. The corners of a Square Drill Collar are coated with tungsten carbide to prevent excessive wear. Its design makes it stiffer than a regular drill collar. A Square Drill Collar will not completely prevent an angle from building up, but it will prevent a rapid change in hole angle, thus reducing the doglegs. Stabilizers

A stabilizer is added to the drill string in more difficult to drill formations, called Crooked Hole Country (regions where crooked holes are prevalent). The addition of the stabilizer above the drill bit will offer more support to the bit as well as increasing the bit life. A stabilizer can also provide stabilization to the drill collars. In areas where crooked hole tendencies are more severe, a stabilizer provides more wall contact. A stabilizer by design reduces the probability of differential sticking, but can increase the chances of other downhole sticking issues.

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Roller Reamers

A reamer works as a stabilizer, but is more expensive to run. A benefit of choosing a reamer over a standard stabilizer is that there is some torque reduction. As mentioned above a reamer will help prevent wear on joints further up the drill string. Roller reamers can be a good alternative to a stabilizer in medium and hard formations even though wall contact is minimal. They are easy to rotate and behave differently than a stabilizer. Hevi-Wate Drill Pipe

Instead of using drill collars for WOB, another option is Hevi-Wate drill pipe. Hevi-Wate is not as heavy as a drill collar, but provides stability with less wall contact. Less wall contact means less friction in the hole and less probability the drill stem will climb the side of the wall. Hevi-Wate drill pipe also utilizes a unique center upset or wear pad to reduce wear on the tube, resulting in less hole drag because of limited wall contact. Hevi-Wate can also be used in place of drill collars in the BHA to increase the length while maintaining the weight. As a general rule, two joints of Hevi-Wate drill pipe equal the weight of one drill collar.

©2008 SMITH International, Inc.

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Exercise: Deviation, Quality and Components

Part A. Answer the following questions. 1. Why is drilling a straight hole with a quality wellbore important?

2. Keyseats are usually associated with what?

3. In the space to the right, draw the side view of a keyseat.

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4. In the space to the right, draw a wellbore that has passed through a laminate formation with offset ledges.

5. In the space to the right, draw a wellbore that has passed through a faulted formation. Include a drawing of the formation.

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Part B. Describe how each of the following components helps to alleviate wellbore quality issues. 1. Drill Collars:

2. Stabilizers:

3. Roller Reamers:

4. Hevi-Wate Drill Pipe:

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Bottom Hole Assemblies Introduction

Several factors should be considered when designing a BHA: hole diameter, hole type (vertical or horizontal), and formation type. The most important factor is stiffness. A BHA must be adjusted depending on the formations being drilled. The BHAs covered in the remainder of this chapter are design combinations that will drill through most formations.

Typical Types of BHAs

Tapered Drill Strings

The most common type of drill string is tapered. The term tapered drill string is commonly used to describe the use of two different sizes, weights, or strengths of drill pipe. Tapering a drill string is commonly found in larger wellbores where a larger OD drill collar is required. In this drill string the stiffest components will usually be at the bottom, providing stabilization for the bit. A reduction in the diameter of drill collars must be no more than two inches. Also, a reduction in diameter should only occur after three joints of the same size have been placed in the drill string. The images above show how tapering the drill string occurs, with the heaviest and stiffest sections in the lowest part of the string and a gradual transition to the lighter and more flexible components. An abrupt change would be a stress riser and increase the probability of failure due to cyclic stress.

"

A reduction in the diameter of drill collars must be no more than two inches.

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Point of Tangency

The point of tangency should be considered when designing a drill string. The point of tangecy is the place in the drill string where the BHA makes contact with the wellbore causing the drill string to change direction. The component that creates the point of tangency is sometimes a stabilizer and sometimes a drill collar or other BHA component. It’s important that the point of tangency stays in the BHA because the components are more durable and are more likely to withstand the stress. Calculating the point of tangency is a complex process beyond the scope of this class. Some of the calculations in the Drill String Design chapter of this book are designed to keep the point of tangency in the BHA.

Vertical Wellbore

Wells are drilled to be vertical, directional, or horizontal. This section highlights the various BHAs that create a vertical wellbore (where mentioned), as opposed to a directional or horizontal wellbore. Directional or horizontal wellbores are beyond the scope of this class. A vertical wellbore is never truly vertical, but will generally look like the image below on the left. The image on the right illustrates how the well deviates from vertical due to the formation changes and hardness.

The next page displays all the BHAs covered in this chapter. The best use for each BHA will be explained.

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Slick Pendulum

Fulcrum Pendulum

Mild Crooked Hole Country

Medium Crooked Hole Country

Severe Crooked Hole Country

Angle Building

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BHA Drilling Techniques: Pendulum Overview

The Pendulum is just one type of BHA used to achieve a specific drilling goal. The Pendulum Effect is the tendency of the drill string to hang in a vertical position due to the force of gravity pulling on the weight of an unsupported length of drill collar. The portion of the drill string identified as the pendulum is between the drill bit and where the drill collar (or stabilizer) rests at the lowest point against the side of the hole, also known as the point of tangency. Pendulum force works against formation resistance to return the drill string to vertical.

Factors Effecting the Pendulum

Before designing a Pendulum BHA there are external factors to take into consideration. Stiffness of the drill collar

The stiffness of a drill collar is proportional to the OD of the drill collar. In a drill collar the stiffness increases to the fourth power (OD4) of the OD and weight increases to the second power (OD2) of the OD. Inclination of the hole

In a drilling operation where a pendulum BHA is pulled away from vertical, the more force is working to then return it to vertical. Thus, the greater the hole angle, the greater the pendulum force is exerted to restore the drill string to vertical. Weight on bit

The drill collar is the BHA component that provides the weight on bit (WOB). When designing a pendulum BHA, take this into consideration because the more WOB, the higher the tendency for the drill string to deviate from vertical. There is also a higher tendency for the drill collars to buckle as more weight is applied and the pendulum length reduced. Formation characteristics Pendulum BHA

©2008 SMITH International, Inc.

Formations are the primary cause of wellbore deviation. As formation types alternate, the drillability changes causing the drill string to drift.

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Slick Pendulum Assembly

We will focus on two main pendulum types, the Slick Pendulum and the Fulcrum Pendulum. The Slick Pendulum Assembly relies on the drill collar (instead of a stabilizer) to create the point of tangency. This type of BHA consists of a drill bit and drill collars. In order to straighten a hole the WOB needs to be reduced and the rotation speed increased. Reducing the WOB causes the bending characteristics of the drill stem to change. This is not always the best practice since reducing the WOB reducing the ROP. In addition, there is an increase in doglegs. A gradual reduction in the WOB usually returns the wellbore to vertical without sharp bends. There is a lack of control when using a Slick Pendulum Assembly because the point of tangency is dependant on the angle of the hole. Ideally, the point of tangency should be 60 feet above the bit. This BHA is rarely used, but is best for extremely soft formations or mild crooked hole country.

Fulcrum Pendulum Assembly

Slick Pendulum BHA

The Fulcrum Pendulum relies on a stabilizer to create the point of tangency. Including a stabilizer in the drill string allows more control of the point of tangency, thus control of crooked hole problems. The stabilizer works by centering the drill collar away from the walls of the wellbore wall. Placing the stabilizer too high will cause the drill collar to sag lowering the point of tangency. A stabilizer placed too low will reduce the pendulum effect. This type of BHA consists of the drill bit, drill collars and one stabilizer. In some cases, two stabilizers can be used. Fulcrum Pendulum Assemblies are rarely used because a more predictable behavior results from using two or more stabilizers. This BHA works best when attempting to remain within a known inclination range.

Fulcrum Pendulum BHA

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Pendulum Assembly Downhole

As the BHA passes through the various formations, it may deviate more than normal. The Pendulum Assembly is often used for correction runs. If the wellbore path is deviating in the wrong direction a Pendulum Assembly uses the force of gravity to bring the hole back to vertical or closer to the planned wellbore path. At the beginning of the drilling process the Pendulum Assembly will require reduced weight on bit to return to a vertical position. The natural tendency of the bit is to stay directly below the drill string due to the pendulum motion.

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BHA Drilling Techniques: Packed Hole Overview

The Packed Hole Assembly is a type of BHA. Depending on the severity of the sub-surface formations a Packed Hole Assembly can be mild, medium, or severe. The term Packed Hole is used because the drill collars or stabilizers in the lower part of the BHA are almost the same size as the bit. The Packed Hole Assemblies prevent doglegs and key seats and allows higher bit weights, improving penetration rates and increasing bit life

Packed Hole Assemblies

Mild

Mild Crooked Hole Country requires a lightly packed BHA to drill. The Packed Hole Assembly for mild crooked hole country is considered minimal for straight hole drilling and bit stabilization. Three points of stabilization are used, one in each zone. A vibration dampener, if included, should be placed above the second stabilizer instead of a short drill collar. If crooked hole tendencies are mild, the vibration dampener may be run in place of the short drill collar between the first two stabilizers downhole. Medium

Mild Packed Hole

A Packed Hole Assembly for medium crooked hole country is similar to the mild, but requires two stabilizers above the drill bit. This increases bit stabilization and adds stiffness to limit angle changes caused by lateral forces. The pony collar is placed after the stabilizers above the bit. There are a minimum of four stabilizers in the entire BHA.

Medium Packed Hole

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Severe

In Severe Crooked Hole Country, three stabilizers are run in near the bit, providing stiffness and wall contact area. In the example to the left the component directly above the bit is a reamer, which acts as a stabilizer. In hole sizes ≤8 ¾”, a large diameter, pony collar is often included between the last and second to last stabilizer, this will increase stiffness and reduce deflection of the total assembly. For each of BHA, hole size dictates the length of the pony collar (short collar) that should be run above the first stabilizer. For the most updated numbers, refer to your SMITH Drilling Handbook.

Hole Size (in) 17 1/2 & larger 12 1/4 - 17 1/2 8 1/2 - 12 1/4 6 - 8 1/2 6 & smaller

Pony Collar Length (ft) 15-20 10-15 8-12 6-8 4-6

Severe Packed Hole

Packed Hole Assembly Downhole

The Packed Hole Assembly will maintain a course more effectively than other BHAs. The image to the right shows a target area below the rig. Using a BHA and adjusting the WOB will keep the string on a vertical course as it penetrates various formations.

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BHA Drilling Techniques: Angle Building Angle Building Assembly

The final assembly is the Angle Building Assembly. Unlike the designs of the previous BHAs Angle Building Assembly is specifically designed to increase the deviation of a hole to horizontal. A single stabilizer is located near the bit. An additional stabilizer is sometimes added further up the drill string. The angle building BHA is very sensitive to a change in WOB. There are additional variations to these BHAs. These are the most common and practical for the purpsose of this training course. As technology advances, the number of tools that can go downhole will increase adding to the number of effective BHAs.

Angle Building

Angle Building Assembly Downhole

The image to the right shows a vertical wellbore, with an off center target area. The natural tendency of the well is to remain vertical, but the target area is not directly below the rig. The well needs to deviate slightly to reach the target area. This is accomplished by using the Angle Building Assembly. When the direction to the target area has been achieved, a Packed Hole Assembly is used to maintain the direction.

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Vertical Drilling System Overview

The SMITH SERVICES Vertical Drilling System (VDS) is an effective and cost efficient way of maintaining a vertical wellbore path. It combines the Packed Hole Assembly with a downhole motor. The design has several key components that make it effective.

Vertical Drilling System Design

Even Rubber Thickness Power Section (Mud Motor) Rotating Near Bit Stabilizer/Reamer

DEI Integral Blade Stabilizer

DEI Transmission Housing DEI Bearing Housing

The VDS works similarly to a Packed Hole Assembly. Unlike other assemblies, the VDS uses a rotating near bit combined with a reamer/stabilizer providing additional support which helps in deviation control. This system has a longer life and improved drilling performance due to the power section. The power section can be used in high temperature environments and is compatible with all drilling fluids.

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Exercise: BHA Configurations Part A. Look at the BHA on the left and answer the questions on the right. Identify the BHA configuration on the 1. left.

©2008 SMITH International, Inc.

2.

Why is this BHA identified the way it is?

3.

What types of formations work best with this configuration?

4.

How does WOB affect the BHA in this configuration?

5.

When would you run this type of BHA?

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Part B. Look at the BHA on the left and answer the questions on the right. Identify the BHA configuration on the 6. left.

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7.

How is this BHA different from the slick pendulum assembly?

8.

Where is the point of tangency created in this BHA?

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Part C. Look at the BHA on the left and answer the questions on the right. Identify the BHA configuration on the 9. left.

10.

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Label the zones on this BHA. You can refer to the Drilling Assembly Handbook if you have any questions.

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Part D. Look at the BHA on the left and answer the questions on the right. Identify the BHA configuration on the 11. left.

©2008 SMITH International, Inc.

12.

Circle the Pony Collar in the graphic.

13.

What is the benefit of using a DEI Double Combo Tool in this BHA?

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Part E. Look at the BHA on the left and answer the questions on the right. Identify the BHA configuration on the 14. left.

©2008 SMITH International, Inc.

15.

What length of pony collar is required for a 10 5/8” hole?

16.

List the benefits of the using the reamer in place of the stabilizer above the bit in this BHA.

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Part E. Look at the BHA on the left and answer the questions on the right. Identify the BHA configuration on the 17. left.

©2008 SMITH International, Inc.

18.

When would you use this type of BHA?

19.

How is this BHA different than a Pendulum BHA?

20.

How is this BHA different than a packed hole BHA?

21.

How many inches can you usually safely reduce taped drill collars?

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BHA Specifics

CHAPTER 2

BHA SPECIFICS Module Objective

At the end of this chapter, you should be able to: o Explain in detail the BHA components including their function and placement in the drill string o Explain BSR and neutral point and how they affect the drill string and BHA

Topics

Exercise: BHA Component Functions Stabilizers Reamers Drill Collars Jars Hevi-Wate Drill Pipe (Transition Pipe) Rotary Substitutes Bending Strength Ratio (BSR) Neutral Point

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BHA & Drill String Fundamentals Chapter 2– BHA Specifics

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Exercise: BHA Component Functions

Previously you were introduced to the BHA basic components. This chapter offers more detail about the BHA components. Part. A. Read about the additional tools in the chapter. Prepare a question and answer for each tool and write it below. Following the class presentation on that tool, select someone from your group to quiz the presenting group with the prepared questions. Stabilizers

Question: Answer:

Reamers

Question: Answer:

Drill Collars

Question: Answer:

Jars

Question: Answer:

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Hevi-Wate Drill Pipe

Question: Answer:

Rotary Subs

Question: Answer:

Part B. You will design a presentation for a specific tool. In the presentation emphasize tool purpose, features, tool application and optimum use. Be prepared to answer follow-up questions from the group. Use the space below to take notes.

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Stabilizers Introduction

There are many components that can be included in the BHA and drill string. This chapter explores the basic components and their functions. The first is a stabilizer. Stabilizers are tools in the BHA to help maintain hole direction. They usually have at least three blades, straight or spiraled out from the body of the stabilizer. These blades may be welded on or machined into the tool body. These tools can be run in the BHA or in some cases in the drill pipe section of the string.

Types of Stabilizers

There are two basic stabilizers types available depending on the application. Non-rotating Sleeve Stabilizers work best in hard formations such as lime and dolomite. Rotating blade Stabilizers have straight or spiral blades which can be short or long. Rotating Blade Stabilizers come in five distinct types: Integral Blade Stabilizers (IBS)

An extremely durable drilling tool forged from one piece of steel. The IBS is used in very hard formations because pieces or parts of the stabilizer can’t detach. Welded-Blade Stabilizers

This is a low-cost alternative to the IBS. The blades are welded onto a forged mandrel body. This type of stabilizer is most frequently used in soft and medium formations. Shrunk-On Sleeve Stabilizer

This is an integral stabilizer composed of two pieces – a body and a sleeve. During assembly of the stabilizer, the sleeve is heated to expand the bore and then cooled to contract around the body. When the blades are worn out, the sleeve is removed with a cutting torch and a new sleeve is installed. IBS

Replaceable-Blade Stabilizer

This stabilizer is most frequently used near the bit when maintaining hole gauge is important in hard or abrasive formations. The body of the stabilizer is machined to hold replaceable blades held in place by bolts. The blades can be easily changed on the rig floor.

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Sleeve Stabilizer

Sleeve stabilizers provide an economical method of providing stabilization services in a remote area. They can be used in all but the hardest formations. A single mandrel can be fitted with replaceable screw-on sleeve blades. Blade changes can be done on the rig floor.

Hardfacing Sleeve

Tungsten Carbide

Hardfacing

Sleeve Stabilizer

Features and Components

Stabilizers offer different features and components depending on downhole conditions, including formation type and temperature. Stabilizers can have a diamond enhanced blade, various hardfacing options, or tungsten carbide inserts.

SMITH Specific Stabilizers

SMITH offers four types of stabilizers: Diamond Enhanced Insert (DEI), Double Diamond Combo Tool, Ezy-Change Type II Rig-Replaceable Sleeve-Type and an IBS. Each type of stabilizer offers different variations that will suit almost any downhole need.

DEI Stabilizer

The DEI Stabilizer is purpose-built for BHA stabilization in hard or abrasive formations. The DEI Stabilizer works best in packed hole assemblies, pendulum assemblies and directional assemblies. It maintains hole gauge, extends stabilizer life and improves the BHA performance.

Double Diamond Combo Tool

The Double Diamond Combo Tool features two sets of three blade spiraled ribs designed to reduce damage to the hole wall and ensure maximum fluid circulation. It is an effective bottom hole stabilizer where severe crooked hole tendencies are encountered (deviation control). It places two points of stabilization where it is needed most – directly above the bit. The Double Diamond Combo Tool works best as a near bit component in all packed hole BHAs. It can be used in a variety of environments including air, foam and mud. Hole gauge, increased wall contact, improved penetration and enhanced tool performance are benefits of the Double Diamond Combo Tool.

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Ezy-Change Type II RigReplaceable Sleeve-Type Stabilizer

The Ezy-Change Type II Rig-Replaceable Sleeve-Type Stabilizer is designed around a rugged, one-piece mandrel constructed of high-strength alloy steel with ample tong space for handling and extra length for recutting connections. It controls well bore deviation, reduces risk of stickage and reduces vibrations in the BHA. This stabilizer offers a good value for the customer. Depending on the size of the mandrel there are three or four blade options available. The design provides a maximum annular flow area. The blades offer various hardfacing options depending on the downhole environment. The Ezy-Change Type II Rig-Replaceable Sleeve-Type Stabilizer is ideal for use in a variety of applications. It is best used in mild to medium packed hole assemblies and pendulum assemblies. The interchangeable sleeves are perfect for remote and space constrained locations.

IBS

The IBS is manufactured from high-strength alloy steel as a single piece tool. It is available in bottom hole and string designs, providing flexibility to run it anywhere in the BHA. The unitized construction features three spiraled ribs designed to minimize downhole torque, reduce damage to the hole wall and ensure maximum fluid circulation. This type of stabilizer offers integral blades, is available in “open” and “full wrap” designs and different wear surfaces. These options make the IBS ideal for packed hole assembles, pendulum assemblies (the most effective configuration is to run two stabilizers separated by one drill collar) and situations where the formation is soft and sticky to formations that are hard and abrasive.

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Reamers Introduction

Reamers are generally used in drilling hard formations since it is the only tool that can effectively maintain hole gauge in very hard rock. When used, they are placed directly above the bit. It opens the hole to full gauge. The reamer reduces torque, smoothes the wellbore, and maintains the gauge. It will also prolong the life of the bit and prevent differential sticking problems.

Types of Reamers

Reamers are 3-point or 6-point depending on the number of rollers or cutters they require. A 3-point reamer has three cutters and is sometimes referred to as a Near Bit Reamer; it runs directly above the bit. A 6-point reamer has six cutters and is used in extreme conditions when more wall contact is required; it is run up the string and provides both stabilization and reaming capabilities. Components

A reamer’s cutters come in several types depending on formation hardness. There is a Hardfaced Sharp Tooth Cutter for soft formations, a Hardfaced Flat Tooth Cutter for medium-hard formations, and a tungsten carbide insert cutter for hard formations. The cutters are mounted either vertically or at a slant on the reamer. Vertical cutters give a true roller action while reaming. The slanted cutters provide a scraping and gouging action as well as preventing string vibrations by eliminating the flat plane that occurs between two vertical rollers. Borrox AP 3-point

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SMITH Specific Reamers

There are four models of reamers SMITH offers: Borrox Sealed Bearing Reamer (AP, 85), Model 60 and 62 Reamer, DEI Reamer and a DOG Sub.

Borrox AP Sealed Bearing Reamer

A Borrox AP Sealed Bearing Reamer is a drill string component with fully customizable hole gauge maintenance and torque reduction characteristics. It works by providing reaming ahead of stabilization. It maintains well bore gauge diameter by working through abrasive formations and on long runs. It also provides deviation control and support by maintaining wall contact. Three different reamer cutters are available for this model reamer to tailor it for specific applications. KSX Cutter

o Ideally suited for medium to hard reaming applications o Selected for combined torque reduction and reaming requirements o Included in BHA to engage the well bore and suppress lateral/torsional vibrations RSX Cutter

o Ideally suited for soft to medium reaming applications o Effective when torque reduction is the primary concern o Stabilizer alternative DEX Cutter

o Inclusion of diamond enhanced inserts in cutting structure

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The Borrox AP Sealed Bearing Reamer can be easily assembled on the rig floor. Depending on its application the location of this reamer may change. In severe packed hole assemblies this reamer should be directly above the bit. In mild packed hole assemblies the Borrox AP works best as the first zone of stabilization.

" Borrox 85 Sealed Bearing Reamer

Reamers are not always an effective stabilizer and should be followed by full gauge stabilization. The Borrox 85 Sealed Bearing Reamer has a track record of outstanding performance in severe reaming conditions, and comes in both three-point and six-point models. It maintains wellbore gauge diameter by working through abrasive formations and on long runs. It also provides deviation control and support by maintaining wall contact. There are many reasons a customer should choose to use the Borrox 85 Sealed Bearing Reamer. They include: o Sealed and lubricated bearings provide maximum cutter life o Cutter design and insert placement enable reaming capabilities that exceed nominal hole size o The high-strength tungsten carbide inserts maintain full gauge hole o Complete serviceability at the rig site using standard hand tools Reduces vibration during drilling operations and downhole torque The Borrox 85 Sealed Bearing Reamer works best in abrasive formations and extended run drilling.

Model 60 and 62 Rotary Reamers

The Model 60 and 62 Rotary Reamers utilize a simple-non-sealed bearing design making them cost-effective for many applications. They reduce down hole torque with cutter rolling action as well as reducing vibration during drilling operations. These reamers work well in high-temperature conditions and abrasive formations. The Model 60 is ideal for high rotary speed applications due to its large bearing area and open circulation. These models have a “Type Q” cutter which achieves maximum reaming action in medium to hard formations where crushing action against the formation is preferred. Hardfaced, carburized steel teeth ground to gauge provide a wear-resistant reaming structure. “Knobby” cutters use tungsten carbide inserts to fracture the rock, and are recommended for use in hard formations.

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DEI Reamer

The DEI Reamer delivers effective hole reaming across a broad range of applications. Its advanced integral body design incorporates tough, state-ofthe-art synthetic diamond enhanced inserts that shear the hole wall, providing a quality, full gauge wellbore. It maintains wellbore gauge diameter by working through abrasive formations and on long runs. It also provides deviation control and support by maintaining wall contact. In severe downhole conditions, especially hot hole, this reamer is the best selection. The DEI Reamer also reams dogleg and keyseats as well as doing bi-directional reaming. Benefits of using a DEI Reamer include: o Synthetic diamond enhanced inserts provide a durable cutting structure capable of maintaining full gauge hole in soft to medium-hard formation o Spiral body design facilitates high circulation rates and the efficient transport of cuttings past the tool o Tapered body profile enables reaming capability both downward and upward o No moving parts to wear or fail downhole

DOG Sub

The DOG Sub delivers at-the-bit reaming performance. The cutting structure utilizes synthetic diamond enhanced inserts designed specifically for continuous reaming. It is placed directly above the bit. It maintains hole size once the drill bit begins to lose its gauge. The DOG Sub also provides the adequate reaming and contact behind the bit wiping out the ledges as drilling progresses. In directional wells where maintaining hole gauge is expected to be a problem and where doglegs require a reaming run through the build section the DOG sub is the best choice. In a packed hole assembly, the DOG Sub provides near-bit reaming; it also shortens the distance from the bit to the first point of stabilization, which improves BHA and drilling performance. The DOG Sub provides excellent value for the customer because of the synthetic diamond inserts, which provide a durable cutting structure capable of maintaining full gauge hole in soft to medium-hard formations. It also has no moving parts that can fail.

©2008 SMITH International, Inc.

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Drill Collars Introduction

The drill collar is usually located right above the drill bit in the drill string. The primary function of the drill collar is to put weight on the drill bit. The WOB will affect the rate of penetration. It also performs additional functions including preventing the drill string from buckling, supporting and stabilizing the bit, and keeping the hole vertical. Drill collars are not invincible though, and do bend in the hole. Drill collars are available in a variety of sizes in standard or spiral design. The outside diameter (OD) can range from 2” to 14” and can weigh as much as 350 lbs/ft. Larger drill collars are stiffer and help control well deviation along with providing a stronger connection. Using a larger drill collar is not always an advantage since they are more difficult to fish. Slick Drill Collars have a smooth and consistent outside diameter (OD). A benefit of the Slick Drill Collar is it weighs approximately 4% more than the Spiral Drill Collar. Spiral Drill Collars have grooves cut around the body of the tube. The grooves typically start about 18-24 inches from the box (internal end) end and stop no closer than 12 inches from the pin end (external end). Spirals must be of sufficient depth to provide maximum standoff when differential sticking becomes a problem. Spiral Drill Collars help prevent or minimize differential sticking because the grooves provide a space for the mud to flow and enter the low-pressure formation. Another type of drill collar is the Square Drill Collar. They provide more stiffness and WOB, increasing the rate of penetration. The square shape with rounded corners makes this drill collar stiffer and offers more wall support. Square Drill Collars are less effective in soft formations. Finally, a Pony Collar is a short version of a standard drill collar. It is commonly used to space out stabilizers and/or reamers to optimize their effect.

"

A reduction in the diameter of drill collars must be no more than two inches.

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Drill Collar Measurements

Drill collars are chosen for each drill string depending on length, inside diameter (ID) and OD. Drill collars can weigh as little as a few thousand pounds or as much as 11,000+ pounds and are about 30 feet long. The ID and OD influence the drill collar weight. Whenever possible, the drill collar size used in a BHA should be maximized. Drill collars increase in weight by the square of any increase in diameter, but they increase in stiffness by the fourth power of that increase in diameter. This means, that with only a slight increase in diameter, drill collar weight will increase and stiffness will be much greater.

Strengths/ Material Yield

New drill collars will be stronger than those rated premium, used, or class 2. Depending on the dimensions of the drill collar the minimum yield and tensile strength will vary. The chart below shows the different psi for two ranges of drill collar sizes. Drill Collar OD Ranges (in) 3 1/8 – 6 7/8 7 - 10

Manufacturing Procedure

Minimum Yield Strength (psi) 110,000 100,000

Minimum Tensile Strength (psi) 140,000 135,000

Drill collars are required to meet minimum specifications during manufacturing and retooling. During manufacturing API Spec 7 connection specifications are followed. These specifications identify how trepanning (boring out the hole) the connections should meet distance and size requirements for uniformity. Another manufacturing procedure is Hardbanding (applying an additional wear resistant material). It is the most effective way to retard the OD wear occurring on a drill collar under normal open-hole drilling conditions. Hardbanding can be applied in different ways depending on the application.

"

When using drill collars in a BHA, keep the number run in succession to a minimum. The more drill collars run together without a stabilizer or reamer, the more probable a drill string failure will occur.

Number of Collars vs Trouble

0

3

6

9

12

Number of Drill Collars

SMITH Specific Drill Collars

SMITH offers a variety of drill collars based on size in standard or spiral models. They are manufactured to meet API Spec 7 standards and can be special ordered to meet a customer’s specific needs.

©2008 SMITH International, Inc.

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Jars Introduction

A jar frees stuck drill stem components during drilling or workover operations. This is done by “jarring” both up and down with an impact force controllable by the driller. It can be placed almost anywhere in the BHA for optimal performance. Types of Jars

There are three jars types: mechanical, hydraulic, and hydro-mechanical. Jars are designed to deliver an impact to a stuck downhole component. The impact should free the component. Mechanical jars work best in vertical wells or directional wells with less than a 30º hole angle. Hydraulic jars work best in vertical and directional wells with elevated torque and drag; they can also be used in horizontal and extended reach wells. Jars are sometimes run with a tool called an accelerator. The accelerator will enhance the impact of the jar. SMITH Specific Jar

The Hydra-Jar is the only jar offered by SMITH. Jar Placement

Proper placement of the jar in the BHA is a critical design component. SMITH’s Jar-Pact software should be used before the components are sent out to a rig. This information is covered in detail in the Impact Technology class.

"

Never run jars in the neutral point or as a change over component.

©2008 SMITH International, Inc.

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Hydra-Jar

The Hydra-Jar works with a companion accelerator to free struck drill stem components during drilling or fishing operations. It works by jarring upwards or by jarring up and down with an impact force controllable by the driller. It is available in the Advanced Performance (AP) model or the Thru-Tubing (TT) model. Each model has a companion accelerator which intensifies the effect created by the jar. The Hydra-Jar is rated to work in temperatures up to 500ºF with circulation rated at 10,000 psi. It also features a Safety-Lok which prevents the jar from accidentally firing. When making the jar up into the drill string a safety clamp allows it to be handled like drill point, which reduces trip time. Other features of the Hydra-Jar include: o A unique metering process that compensates for the decrease in detent cylinder oil viscosity as the jar is fired repeatedly, ensuring consistent impact o The jarring direction, duration and impact are controlled from the rig floor o The jar can be run in compression or tension, providing optimized placement in the drill string

©2008 SMITH International, Inc.

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Hevi-Wate Drill Pipe (Transition Pipe) Introduction

Transition pipe is used between the BHA and drill pipe, separating the drill stem. It is usually referred to as Hevi-Wate and is available in standard and spiral designs. The standard design of Hevi-Wate drill pipe has thicker walls than standard drill pipe, causing it to weight nearly twice as much. Yet Hevi-Wate drill pipe is more flexible than drill collars. Hevi-Wate can be run in the place of drill collars if the drilling rig hook load becomes excessive. The weight of one drill collar is equivalent to the weight of two Hevi-Wate drill pipes (when they are the same size—ID, OD, and joint size).

Spiral-Wate drill pipe shares the same characteristics of Hevi-Wate drill pipe, but has grooves to prevent differential sticking. Transition Pipe Measurements

Hevi-Wate drill pipe (HWDP) is normally 30 ½’ long and is available in a 3 ½” to 6 5/8” OD. A joint of Hevi-Wate can weigh as little 700 pounds to as much at 2,000+ pounds. Unlike drill collars, Spiral-Wate drill pipe weighs more than its standard version by 7-10%. Hevi-Wate drill pipe should not be used as bit weight in vertical holes larger than those listed in the table below.

"

Hevi-Wate Size Max. Hole Size

©2008 SMITH International, Inc.

In. In.

3½ 7

4 8 1/8

4½ 9 1/16

BHA & Drill String Fundamentals Chapter 2– BHA Specifics

5 10 1/16

5½ 11

6 5/8 13 ½

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Transitioning

"

When the BHA is complete, the transition pipe needs to be made up into the drill string. Larger OD wellbores require larger OD drill collars. In this case a tapered BHA is necessary. When transitioning from one size to the next, the change should not exceed a 2” reduction. Drill collars should be run in multiples of three until the required size is reached. Acceptable OD limits for transitioning from drill collars to Hevi-Wate drill pipe: Hevi-Wate Size Max. Drill Collar Size Inches Inches 3½ 5¾x2¼ 4 6½x2¼ 4½ 7 ½ x 2 13/16 5 8 ¼ x 2 13/16 5½ 9 x 2 13/16 6 5/8 10 ½ x 3

Strengths/ Material Yield

The Hevi-Wate drill pipe and Spiral-Wate drill pipe serve specific functions. Depending on the type of hole being drilling, horizontal or vertical, one or the other is preferable. Spiral-Wate is generally preferred over Hevi-Wate when differential sticking is possible, except in horizontal holes. Spiral-Wate tends to drill a low side key seat in a horizontal hole. Spiral-Wate has no center wear pad and bends over a larger area.

Manufacturing Procedure

Hevi-Wate drill pipe has a center wear pad (donut) and longer than standard tool joints. Hevi-Wate drill pipe is hardbanded, meaning that metal and small pieces of tungsten carbide are welded onto the tool joints and on the donut. Hardbanding can be tungsten (most common) or chrome based. The hardbanding is normally applied ‘proud’ while the chrome is in-laid or flush (recessed). Hardbanding helps to prolong pipe life by reducing wear to tool joints and middle wear pads. Longer tool life will result in additional profits over the tool life. Tungsten based hardbanding provides standoff for the large tool joints as the chrome based is more of a sacrificial wear element. Chrome or alloy based hardbanding is considered to be casing friendly and is more commonly found on Spiral-Wate drill pipe. The API Boreback box stress relief feature is standard for the box connection on 4" Hevi-Wate drill pipe and larger, helping to extend the service life of the connection.

SMITH Specific Hevi-Wate

The Hevi-Wate drill pipe manufactured by SMITH is manufactured per API Spec 7 standards and is available in standard or spiral. Special orders can be manufactured to meet the customer’s needs.

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Rotary Substitutes Introduction

Rotary substitutes (or subs) are threaded adapters for connecting tools with incompatible threads. They are threaded on both ends, made of steel and are used to connect various parts of the drill string together. These components are used in drill strings, but are not necessarily a happy addition. Including a rotary sub in a drill string will generally increase the likely of a failure.

Types of Substitutes

There are multiple rotary subs types depending on what needs to be connected together. Bit Subs

A bit sub connects pin-up BHA components to the drill stem. The bit subs are rotary double box subs (internal threads). Crossover Sub

A crossover sub has a box end (internal threads) and a pin end (outer threads). This sub connects drill string components with incompatible threads. They can be a single OD, or a dual OD to fit the connecting pipe. Dual OD Subs

Dual OD Subs are used when connecting a larger OD drill string component to a smaller OD drill string component. A dual OD sub will maintain a balanced connection concerning is bending strength ratio (BSR). Reducing the OD of the sub on one end then the connection will provide superior service.

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Top Drive Subs

A top drive sub is used to connect a top drive system to the drill string is a double pin (outer threads) sub. These subs are typically shorter in length and have a reduced OD to provide proper spacing. They are compatible with the top drive on the drilling rig. Sizing

Rotary subs are available in lengths from 6 1/2” to 24 1/8” (and longer when required), shoulder to shoulder. When measuring shoulder to shoulder that is the length from the box end of the sub to the pin shoulder end before the threading starts. The connection sizes available range from 2 7/8” to 7 5/8”.

SMITH Specific Subs

Customers needing any type of sub will be able to get it from SMITH. Subs are available in different configurations for a variety of uses depending on the customer’s need.

Rotary Subs

A rotary sub serves two primary duties. First, to cross over from one connection size to another. Second, as a disposable component; It will extend the life of a more expensive drill string member.

Bit Subs

A bit sub serves as a type of cross over to connect the bit and the remainder of the drill string.

Lift Sub

A lift sub enables the safe, efficient handling of straight OD tubulars by using the drill pipe elevators.

Top Drive Sub

The top drive sub serves as the sacrificial element between the drillstring and the top drive, reducing repair and maintenance costs. We have reviewed BHA and transition pipe components of the drill string. The next chapter will discuss drill pipe.

©2008 SMITH International, Inc.

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Bending Strength Ratio (BSR) Introduction

The BSR applies only to the BHA and in some cases Hevi-Wate drill pipe. Due to the strength of BHA components, the connection tends to be the weakest part. In the case of Hevi-Wate drill pipe the tool joints are longer. Longer tool joints can be weak at the connection when exposed to difficult downhole conditions.

Bending Strength Ratio (BSR)

When a pipe joint is torqued and downhole, a non-vertical wellbore will cause the pipe to bend. Pipe joint is kemplated because it can bend at the connection. Kemplating reduces galling and enhances joint compound retention. The BSR is a number descriptive of the relative capacity of the pin and box to resist bending fatigue failures. A balanced connection results in the tool joint when the box is 2 ½ times wider than the same area on the pin.

40% Pin 100%

Bending Strength Ratio Charts are included in the “Drilling Assembly Handbook” from pages 79-95. The handbook is included with this manual.

©2008 SMITH International, Inc.

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Box BSR

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Neutral Point Introduction

Now that you understand a little more about the BHA, it’s important to understand how the neutral point and the BHA are connected. The neutral point is a drill string position where neither tension or compression forces are in effect; below the neutral point there is compression and above the neutral point there is tension. The position of the neutral point is the place in the BHA where WOB is met in pounds per foot; for example, if the WOB is 5,000 pounds, the neutral point would be located 5,000 pounds up the drill string from the bit.

Keeping the Neutral Point in the BHA

The main reason to keep the neutral point in the BHA is due to the strength of the BHA components. The neutral point should be located where there is a drill collar since it is the strongest component in a drill string. As the neutral point moves toward the top of the BHA there is a higher failure possibility. If the neutral point reaches the drill pipe, there will be a big problem. The drill pipe has much thinner wall and if it is rotating while in compression it will fatigue quickly and fail.

Calculating the Safety Factor

Drill collars and HWDP provide the necessary WOB required for drilling. The BHA design will affect how the safety factor is calculated. The range for the safety factor is from 115% to 125% of the required WOB. In special cases a drill stem may use only drill collars (and not HWDP) to provide WOB, the safety factor used should be 150%. Including the safety factor keeps the neutral point in the BHA, which prevents buckling.

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Buckling

When applying WOB, there is an equal and opposite compressive load on the drill string. The load will cause even the stiffest known drill collars or drill pipe to bend. In drill pipe, the flexibility will allow it to buckle quiet easily (left, image on the right). If the load is Keep WOB Less Than What is Needed to Buckle It large enough, the bending will reach a point of instability and buckle. In most cases, we need to keep the WOB less than the load required to buckle the drill string.

Buckling in Vertical and Non-Vertical Holes

The type of hole being drilled, vertical or non-vertical, affects the weight which will buckle the drill string. A paper published by Arthur Lubinski in 1950, “A study of the Buckling of Rotary Drill Strings,” was the first to correctly model many aspects of the mechanics of drilling strings. The results were for perfectly vertical holes. We know that a flaw in his theory is no hole is perfectly vertical. In1982, the duo of Paslay and Dawson published, “Drill Pipe Buckling in Inclined Holes.” This article essentially confirmed that a safety factor should be included in WOB calculations to ensure buckling does not occur.

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Drill Pipe Overview

CHAPTER 3

DRILL PIPE OVERVIEW Module Objective

At the end of this chapter, you should be able to: o Explain the basics of drill pipe including the drill pipe manufacturing process, grade and class, as well as how to identify drill pipe o Explain the drill pipe manufacturing process o Explain how drill pipe grade and class are determined o Identify drill pipe pin base markings or the slot and groove system

Topics

Exercise: Question Trade Drill Pipe Anatomy Drill Pipe Manufacturing Process Exercise: Drill Pipe Manufacturing Process Drill Pipe Specifications Drill Pipe Identification Slot and Groove Method of Drill Pipe Identification Drill Pipe Weight Code Identification Exercise: Drill Pipe Identification

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Exercise: Question Trade

During this Drill Pipe lecture, write a minimum of three questions below (don’t include the answers). Following the lecture, exchange your paper with a classmate and answer each others questions. 1.

2.

3.

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Drill Pipe Anatomy Introduction

The drill pipe is the remainder of the drill string, beyond the BHA. Drill pipe is a seamless tube of forged steel or extruded aluminum that serves as a conduit for the drilling fluid. It is located at the top of the drill string (above the transition pipe) and transmits the rotation of the rig’s rotary or top drive down the drill string.

Box Tool Joint

Upset Tube

Pin Tool Joint

Drill Pipe Upset

A drill pipe is prepared for the welding on the tool joint by forging an upset at the end of the pipe. An upset is a change in the ID and/or OD of a pipe. An upset is created by super heating the tube ends and applying great force to compress the ends creating a thicker wall. The upset area is thick enough to provide a solid foundation to join the tool joint to the drill pipe tube.

Upset Types

Drill pipe has three types of upsets: o An internal upset has a reduced ID or bore. An external view of the pipe shows no thickened areas. It best represents a slimhole pipe. o An external upset has an increased OD and a slightly reduced ID. Smaller sizes of drill pipe typically have external upsets. o An internal and external upset combines both, seen in larger sizes.

Internal and External Upsets

Area of Focus

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Drill Pipe Manufacturing Process Manufacturing Process

Drill pipe is manufactured in two stages: tool joints and tube manufacturing. First, the tool joints are forged into blanks (they have no specific qualities such as threading) and are inspected. The tool joints are bored and austenitized. Austenitizing is the process of heating to form austenite (a corrosion preventing carbon). The heating and even cooling process occurs in a controlled environment so the microstructure and properties are uniform. To ensure continued quality, laboratory testing verifies compliance with Near Ready Tool Joints/Molten Salt mechanical property requirements. Next, the tool joints are tempered, inspected, and threaded. Superior results are produced during the threading process due to the machined upset forgings. In order to ensure the superior results the blanks for tool joints must meet basic compliance standards and traceability. API standards dictate the design standards. Finally, a five step phosphate coating is applied and the joints are inspected Phosphating Vat again. Hardbanding can be applied to specific areas of the joint to reduce wear.

Tooling Threads

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The drill pipe begins as a “green tube” (drill pipe that has not been heat treated or processed). SMITH has specific standards for their green tubes. Chemical and dimensional standards must be met. This helps SMITH maintain their high quality standards, such as tubes being manufactured to meet a 95% minimum wall standard. Long Internal Run-Out

First, the tube is gas fired so the upset can be created, then the tube is deburred and faced. Just like the joints, the tube is austenitized. Unlike the tool joints, the tube is quenched with water and tempered in a furnace. Quenching cools the pipe by running it through a device that sprays water 360º cooling the pipe evenly. Even quenching enables a martinsite microstructure to form.

Quenching

Drill pipe subjected to stressful conditions will need to meet or exceed the API standards. Texas Steel Conversion (TSC) has developed an upsetting practice that produces an extra long internal runout; this aids in fatigue resistance. Following tube inspection, it is straightened and inspected for any imperfections. The cross section of the pipe and the joint must be concentric (similar). Concentricity will ensure a good

Concentricity

weld when the two pieces are joined together. The tool joint is added to the pipe by a process called inertia welding. Inertia welding is a process where one piece is connected to a flywheel and the other is stationary. The flywheel is rotated to a predetermined speed and pressed against the stationary piece. Kinetic energy turns to heat and joins the two pieces together. SMITH uses the most up-to-date equipment available for this process. ©2008 SMITH International, Inc.

Inertia Welding

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When the two pieces have been welded together several steps are taken to ensure the weld quality. First, the upset is saddle gauged. The saddle gauging ensures a concentric OD between the tool joint and tube. Next the weld flash is removed and the weld area is machined to a smooth finish. Machining removes the weld flash and other potential stress risers. The welded area is heated and quenched. This heat treatment performs the same Weld Flash function as it did in the beginning of the process, providing a uniform consistent steel microstructure. Various specifications require different heat treatment cycles. The weld is quenched and Post Weld Quench checked for hardness. A temper cycle ensures complete tempering of the heat affected zone, becoming tougher and more resilient.

Machined Welds

Finally, the welded area is finished and inspected. The finishing will remove surface marks and provide the right OD specifications. The entire upset is inspected. The inspection process

includes: o o o o o o

Visual Brinell Hardness Ultrasonic Wet Magnetic Particle Inspection Concentricty Dimensional

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Ultrasonic Inspection

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Exercise: Drill Pipe Manufacturing Process The next two pages contain a visual flow of how drill pipe is manufactured. Some of the steps have a blank box below them; enter in the name of the process of that step from the list. Austenitizing with integrated Oil Quench Upsetting the Pipe Forge Tool Joint Blanks Tempering Furnace Full Length Pipe Inspection External Quench Tool Joint & Tube Joined with Inertia Weld Phosphate Coating or Kemplating

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Drill Pipe Specifications Drill Pipe Size

There are many sizes of drill pipe available. Drill pipe is manufactured to meet customer specifications. The American Petroleum Institute (API) has approved sizing measurements. API drill pipe is furnished in eight sizes: 2-⅜", 2-⅞", 3-½", 4", 4-½", 5", 5-½", and 6-⅝". These sizes are the outer diameter (OD) in a non-upset section. Drill pipe that doesn’t meet these specifications has usually been manufactured for a specific job. Generally, drill pipe that doesn’t conform to API standards exceed the API specifications.

Drill Pipe Anatomy

1 joint of drill pipe is made up of three components

Drill pipe tube Green tube

Tool Joints

Ends are upset

120,000 MYS

Heat treated to specific strength

Pin tool joint = 35° taper Box tool joint = 18° taper

Tool joints welded on Upset area Thickness required to weld tool joints onto to tube

Drill Pipe Weight

Drill pipe weight is calculated as part of the hookload capability on the derrick. The derrick supports the weight of the components downhole. If the weight exceeds the approved hookload capacity there can be problems. In turn, each component in the drill string supports the weight of the drill string below it. The components at the top of the drill string need to support more weight than those in the BHA. Drill pipe weight varies depending on its form. The drill pipe weights are: plain end weight, approximate weight, and nominal weight (most frequent).

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Plain End Weight

Plain end weight is the weight per foot of a non-upset, non-threaded and non-tool jointed piece of pipe. Approximate Weight

This is the average weight per foot of a joint of complete drill pipe assembly. It includes the tube, the upsets and both tool joints. Nominal Weight

Drill pipe is purchased and referred to by its nominal weight. The nominal weight refers to the wall thickness of the pipe, not the drill pipe’s actual weight. Nominal weight is a classification system. It is how most drill pipe is referred to because remembering the weight would be too difficult. Example of weight variance: Size Wall inches inches 4-1/2

.337

Nominal Weight lb/ft 16.60

Plain End Weight lb/ft 14.98

Approximate Weight lb/ft 17.98

Drill Pipe Length

Drill pipe is available in three length ranges. This variance is due to derrick heights. The most common range for drill pipe length is Range 2, between 27-30 feet. It is available from 18 feet (Range 1) to 45 feet (Range 3).

Drill Pipe Grade

The specification for drill pipe grade means the pipe must meet the standard at which force will damage the pipe. The higher-grade steel pipes have higher strengths, allowing them to withstand greater forces. Drill pipe grade is indicative of the yield strength in thousands of pounds per square inch. Yield is the maximum pull a joint of pipe can withstand without receiving permanent damage. For each grade of drill pipe, API has established a range of minimum yield strengths. For example, grade E pipe must fall within its established range of 75,000 psi and 105,000 psi. Drill pipe is also graded by the heat treatment method used in the pipe manufacturing (which also determines the pipe’s strength considerations). If the yield strength of a material sample falls within the range assigned to more than one grade, then its grade will be based on the heat treatment method used. For example, E pipe is normalized and X, G, S, and V pipe are quenched and tempered.

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Common Grades E-75 X-95 G-105 S-135

Yield Strength Minimum Maximum psi MPa psi MPa 75,000 517 105,000 724 95,000 655 125,000 862 105,000 724 135,000 931 135,000 931 165,000 1138

The above chart indicates minimum yield providing the basis for maximum pull (hookload) calculations. The red box shows manufacturer’s the high end parameter to maintain strength and hardness characteristics. This will be covered in more detail in the next chapter. Drill Pipe Strengthening Process

Drill pipe strength is determined by the heat treatment method used in pipe manufacturing. Each of the processes explains how the pipe is strengthened. o Austenitizing—exposing the tubing to extremely high temperatures o Normalizing—heating and cooling the tube in ambient temperatures o Quenching—rapidly cooling the metal o Tempering—exposing the metal to slow baked heat and controlling the raising and lowering of the temperature

Drill Pipe Class

Drill pipe class determination is affected by several factors; the most important is the amount of remaining wall. A reduction in the wall thickness reduces the mechanical strength of the pipe. The remaining wall thickness for each class is shown as a percentage of nominal wall thickness. The four usable classes of pipe are separated by the remaining wall limits, with premium being the most widely specified class: o New — 87.5% nominal wall o Premium — 80 % nominal wall o Class 2 — 70% nominal wall o Class 3 — less than 70% nominal wall

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Drill Pipe Identification API

When identifying a drill pipe The American Petroleum Institute (API) has addressed a commonality among manufacturers. Drill spring identification is located on a steal stamp on the pin thread base or a single groove and milled slot.

Pin Base Markings

A set of five characters (letters and numbers) appear at the pin base of the drill pipe. Each set identifies specific information about the pipe. o o o o o

The first set identifies the tool joint manufacturer Next the month the joint was welded appears in numerical format Then the year the joint was welded Next the pipe manufacturer’s symbol Finally the drill pipe grade is identified with a letter (E, X, G, S)

Pin Base Image

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Current Slot and Groove

As of December 2004, the current system for identifying drill pipe is with a single groove and milled slot. Each grade of drill pipe follows an identification system. There is standard weight and extra weight drill pipe which is identified by the markings as well. The first type of drill pipe is Grade E. Standard Weight Grade E drill pipe has no markings. If it is extra weight drill pipe there will be a milled slot with an “E” in the pipe grade code area and pipe weight code number listed.

Grade E Extra Weight

Grade E Drill Pipe

The remainder of the drill pipe has a single groove and a milled slot. The milled slot and groove changes locations on the joint to identify standard weight or extra weight drill pipe. Standard weight has the groove to the right of the milled slot; the milled slot will show the code and weight. The extra weight will have a groove to the left of the milled slot.

Standard Weight Drill Pipe

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Extra Weight Drill Pipe

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Previous Slot and Groove

Previously a multi-groove identification system was used. The multigroove system identified drill pipe on sight. API specifications required a specific number of grooves in the joint to identify the weight and grade of the drill pipe. These grooves were required on all pipe except Grade E-75 which was flush (just like the current slot and groove system).

Grade E Standard Weight

Grade E Heavy Weight

Grade X drill pipe at first may appear to be similar to the current slot and groove method. Notice the milled slot is located immediately next to the groove. The current slot and groove system has a space between the two identifiers.

Grade X Standard Weight

Grade X Heavy Weight

Standard weight Grade G drill pipe has two grooves that identify it. If the drill pipe is heavy weight then the milled slot will be between the grooves.

Grade G Standard Weight

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Grade G Extra Weight

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Finally, standard weight Grade S drill pipe has three grooves. If the drill pipe is heavy weight the milled slot will appear between two of the grooves.

Grade S Standard Weight

Grade S Extra Weight

The milled slot on all heavy weight drill pipe will show the pipe weight code and the grade code, assuming it hasn’t worn off during the drilling process. The change in the Slot and Groove System was necessary because it caused damage to the rotating head seals during the tripping out process by the multiple grooves. Drill pipe is the longest portion of the drill string. It supports extreme amounts of weight. Inspection and drill pipe safety for all components of the drill string is necessary to ensure a successful drilling operation. Using properly rated and classed drill pipe will aid in a successful operation.

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Slot and Groove Method of Drill Pipe Identification

Standard Weight Drill Pipe

Extra Weight Drill Pipe

Drill Pipe Grade Code Standard Grade GRADE

SYMBOL

E-75

E

High Strength Grades GRADE SYMBOL

X-95 G-105 S-135 V-150

X G S V

Grade E Extra Weight

Use the chart on the following page to identify drill pipe. Note A: Standard weight Grade E drill pipe designated by an asterisk (*) in the drill pipe weight code will have no groove or milled slot for identification. Grade E heavy weight dill pipe will have a milled slot only, in the center of the tong space. Note B: Groove radius approximately 3/8 inch. Groove and milled slot to be ¼ in. deep on 5 ¼ inch OD and larger tool joints, 3/16 inch deep on 5 inch OD and smaller tool joints. Note C: Stencil the grade code symbol and weight code number corresponding to grade and weight of pipe in milled slot of pin. Stencil with ¼ in. high characters so marking may be read with drill pipe hanging in elevators.

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Drill Pipe Weight Code Identification

OD Size (inches) 2⅜ 2⅞ 3½ 4

4½

5 5½ 6⅝

Wall Thickness (inches) .190 .280 .217 .362 .254 .365 .449 .262 .330 .380 .271 .337 .430 .500 .550 .575 .296 .362 .500 .304 .361 .415 .330 .362

©2008 SMITH International, Inc.

Nominal Weight (lbs/ft) 4.85 6.65* 6.85 10.40* 9.50 13.30* 15.50 11.85 14.00* 15.70 13.75 16.60* 20.00 22.82 24.66 25.50 16.25 19.50* 25.60 19.20 21.90* 24.70 25.20* 27.70

BHA & Drill String Fundamentals Chapter 3 – Drill Pipe Overview

Weight Code Number 1 2 1 2 1 2 3 1 2 3 1 2 3 4 5 6 1 2 3 1 2 3 2 3

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Exercise: Drill Pipe Identification

Answer the following drill pipe questions. Use pages 19-20 as a resource. 1.

Identify the following components.

A

B

C

D

A. B. C. D. 2.

The following drill pipe has a 4"OD and has the stencil S 3.

A. What does the S designate?

B. What does the groove placement designate?

C. What is the nominal weight of this drill pipe?

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Answer the following drill pipe questions. Use pages 19-20 as a resource. 3.

The following drill pipe has the stencil G 2.

A. What does the G designate?

B. What does the 2 designate?

C. How is the 2 determined?

4.

The following tube has a 5" OD, X-95 grade, 25.6#. Write in the code that should be stenciled on the milled slot.

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Answer the following drill pipe questions. Use pages 19-20 as a resource. 5.

The following has a 3 1/2" OD, S-135 grade, 13.3#. Write in the code stenciled in the milled slot.

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Connection Science

CHAPTER 4

CONNECTION SCIENCE Module Objective

At the end of this chapter, you should be able to: o Identify and explain the basics of threaded connections o Explain the three connection types and their identifying characteristics o Explain how make up torque and BSR affect a connection o Perform the steps required to identify a connection

Topics

Threaded Connections Connection Science Identifying Threaded Connections Threaded Connection Charts Measuring the Connection Activity: Thread Identification

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Threaded Connections Introduction

In the last chapter the drill pipe manufacturing process was discussed. The threaded connections were briefly mentioned, because connection science requires more than a paragraph to cover. Threaded connections are referred to by the brand name of the thread type (API Regular), the designated connection number (NC38), and the nominal size of the connection (3½" FH). It is important to be familiar with these connections so tools are connected properly.

Connection Types

There are three primary types of connections used in the US drilling industry: API, dual shoulder, and wedge thread. API Connection

API is the most common type of connection. The shoulder is located externally at the top of the box and the base of the pin. The benefits of an API connection include: free spinning, easy stab up, common use, and ease of recut/repair.

API Connection

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Dual Shoulder A dual shoulder connection has one sealing point, the external shoulder. The internal shoulder is a torque stop. Some dual shoulder connections are interchangeable with API connections, yet they lose the added torque capability. The benefits of a dual shoulder connection include: free spinning, easy stab up, and increased torque capability.

Dual Shoulder

Wedge Thread

The wedge thread is a unique proprietary connection created by Hydril Company, LP. It is the strongest connection on the market; attributed to interlocking threads that act as seals. The image to the right shows there is no shoulder seal. The wedge thread has increased torque capability. The wedge thread can only be cut by CNC machine. It is not interchangeable with any other connections. Wedge Thread

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Connection Features & Benefits

Connection Type

Names

Free Spinning

Easy StabUp

Easy to Repair & Recut

Increased Torque Capabilities

API

REG, FH, IF, NC DSTJ, GP HT, SSDS, Tuff-Torq GP XT, GP XTM

R R

R R

R R

 R

R

R



R

Wedge Thread (WT)







R

Dual Shouldered High Performance (Proprietary) High Performance (Proprietary)

Nominal Size

Thread Forms

-----------------------------------------------------------------------------------------The nominal size of a threaded connection is identified by the approximate size of the connection OD. Sizes such as 2⅜", 2⅞", 3½" 4", 4 ½", 5", 5½", 6⅝", 7⅝", or 8⅝" are examples of the available nominal sized connections. While the nominal size provides a sense of how large the connection is, it does not correspond to any actual dimension on the threads. It is a method used to identify the thread size not a dimensional measurement. Manufacturers can vary. Each company has its preferred thread type. Each thread type has an ideal application. For example, a rounded threaded is better for shallow wells and a lighter hook load, while a wedged thread is ideal for higher pressure wells and a heavier hook load.

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Dual Shoulder and Single Shoulder Connections

When designing a connection using a dual shoulder component (DS), it can be connected to a liked-size single shoulder (SS) component. DSTJ is a DS connection used with an API SS connection. The torque advantages are lost when interchanging connections, but a crossover sub is not required when connecting like sized components. The images below represent what the connection looks like when mixing and matching connection types.

The strength or weakness of a connection is dependant on its location in the drill string. The components in the BHA tend to be weaker in the connection. Drill pipe, on the other hand, is more flexible due to a smaller cross sectional area. Connection strength will vary in drill pipe depending on several factors including the grade and thread type. For example, 2⅞" AOH drill pipe E-95 is weaker in the tube, while S-135 with the same thread type shows more weakness in the connection.

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Connection Science Introduction

The connection may be the strongest or the weakest part of a drill string. The joints used in a drill string play a large part in determining the strength of the connection. In addition to the joints the torque, fatigue, and bending strength ratio (BSR) affect the strength of a connection. An important part of any connection is the shoulder. The shoulder is the flat area where the pin and the box meet when it’s joined together. In some connection types this is the only seal. Some connections have two shoulders, and the second seal is in the box.

Shoulder is the Seal

In the box, the critical zone is just short of the end of the pin at the root of the last engaged thread. This zone is not supported by the mating pin threads and is the weakest section in the box. The critical zone of the pin is about 0.75 inches from the shoulder, at the thread root.

In Pin In Box

Pin and Box Weakness Areas

Torque

The connection is made up by torque. Torque is the amount of pressure used to tighten “twist” the joints together. Applying the proper amount of torque provides a good connection, but over-torquing can cause fatigue and eventually failure. The thread types and dimensions are critical in torque, since they require different psi to make up. Equipment used in the BHA will be connected using rotary-shouldered connections, or the API connection. The remainder of the drill string could be connected using the other connections discussed at the beginning of this chapter.

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Improving Fatigue Life

Drill collar connections are kemplated to protect them from the elements after machining to help prevent galling (surface damage on threads caused by localized friction welding of high spots) upon initial makeup. Thread roots are cold-rolled on all API and H-90 connections except 2⅜" sizes, 2⅞" Regular and Slim-Line H-90. Cold rolling compresses the fibers in the thread root making this area of the connections more resistant to fatigue failure. Pressed-steel thread protectors are supplied for all drill collars equipped with standard connections.

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Identifying Threaded Connections Introduction

Connection threads and tool joints types were discussed at the beginning of the chapter, followed by the science of connection make-up and weakness identification. How is a tool joint identified? We will explore the steps. First we will use logic, if that doesn’t work then it’s time to measure.

Use Logic

Threads can be identified using simple logic. First, consider what type of tool will be made up in the drill string. Ask the questions: “What will this tool connect to?” “How will it be used?” Example: if you are trying to identifying the threads on a Box x Box substitute, you might use the following thought process: o Box x Box subs are usually run above drill bits o Drill bits always have an API regular pin connection o At least one of the connections on the substitute is likely to be API regular

Which End is Up?

To assemble a drill string you must know how the connections fit together. It’s known that bits and near bit accessories are run pin up. Every other component in a conventional drill string is run box up.

Interchanging Connections

Some thread types are interchangeable. The contour and dimensions of the connections are similar enough to be made up together without risking damage to the threads. Some threads are manufactured to match threads already available but are called something else.

API Connections

API connections are available in regular (REG), full-hole (FH), and numbered connections (NC). The API numbered connections are interchangeable with the now obsolete API internal flush (IF) connections. The table below shows the interchangeable thread. NC NC26 NC31 NC38 NC40 NC46 NC50

©2008 SMITH International, Inc.

IF 2⅜ 2⅞ 3½

X-Hole

Full Hole

4" 4" 4½

4½ 5"

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Dual Shoulder Connection

Dual shoulder connections are sold by a variety of manufacturers. Grant Prideco, Omsco, NKK, and SMITH all produce dual shouldered connections that meet customer requirements.

Bevel Diameter

Certain amounts of torque are required to seal the face contact between the box and pin. The greater the square inches on the surface of the face, the greater the amount of torque needed for that connection. Alternately, the smaller the square inches on the surface of the face, the smaller the amount of torque needed for that connection. The diameter of the bevel provides a specific surface area on the face that allows for the correct amount of torque to seal the connection. The bevel diameter changes as the OD changes on the BHA components. Drill pipe bevel diameter stays the same as the tool joint wears down.

Visual Thread Identification

XTM

XT

SSDS & GPDS

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Threaded Connection Charts Introduction

The following charts provide size information for the most popular connections available in each brand. Use the chart below as a guide for the areas being measured. These measurements are approximate only.

AOH Connection

SIZE 2 3/8 2 7/8

A 2⅜ 2⅞

B 3 1/16 3⅞

C 2¾ 3 9/64

D 2.468 2.802

E 2 13/16 3 3/16

F 2½ 3

G 2 2 5/32

H 4 4

G 2⅛ 2 7/16 2 13/16 3 5/32 4 5

H 5 5 4 5 4 4

FH Connections

SIZE 2⅞ 3½ 4 4½ 5½ 6⅝

A 3½ 3⅝ 4⅜ 3⅞ 4⅞ 4⅞

B 4¼ 4⅞ 5⅜ 6 7½ 8⅝

©2008 SMITH International, Inc.

C 3.625 3.994 4.280 4.792 5.825 6.753

D 2.750 3.088 3.551 3.823 5.012 5.940

E 3 11/16 4 3/64 4 11/32 4⅞ 5 29/32 6 27/32

F 3⅞ 4⅜ 4⅝ 4⅛ 5⅛ 5⅛

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H-90 Connections

SIZE 3½ 4 4½ 5 5½ 6⅝ 7⅝

A 3⅞ 4⅛ 4⅜ 4⅝ 4⅝ 4⅞ 6

B 5⅜ 5⅞ 6⅜ 6¾ 7¼ 8⅛ 9½

C 4.125 4.500 4.834 5.104 5.375 6.000 7.389

B 4¼ 4¾ 6¼ 6½

C 3.327 3.812 4.834 5.250

D 3.479 3.813 4.105 4.334 4.604 5.188 5.889

E 4 3/16 4 9/16 4 57/64 5 11/64 5 7/16 6 1/16 7 29/32

F 4⅛ 4⅜ 4⅝ 4⅞ 5⅜ 5⅝ 6¼

G 2¼ 2⅝ 2¾ 2½ 3 3¼

H 3½ 3½ 3½ 3½ 3½ 3½ 3½

G 1⅞ 2 7/16 3¼ 3¾

H 4 4 4 4

G 1¼ 1½

H 4 4

XH Connections

SIZE 2 7/8 3½ 4½ 5

A 3⅞ 3⅜ 4⅜ 4⅜

D 2.681 2.250 4.105 4.521

E 3 23/64 3⅞ 4 29/32 5 5/16

F 4⅛ 3⅝ 4⅝ 4⅝

PAC Connections

SIZE 2 3/8 2 7/8

A 2¼ 2¼

B 2⅞ 3⅛

©2008 SMITH International, Inc.

C 2.365 2.531

D 2.084 2.250

E 2 13/16 2 19/32

F 2½ 2½

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IF Connections (Obsolete)

SIZE 2 3/8 2 7/8 3½ 4 4½ 5½ 6 5/8

A 2⅞ 3⅜ 3⅞ 4⅜ 4⅜ 4⅞ 4⅞

B 3⅝ 4¼ 4¾ 6¼ 6⅜ 7⅜ 8½

C 2.876 3.391 4.016 4.834 5.250 6.397 7.459

D 2.397 2.879 3.370 4.105 4.521 5.585 6.646

E 2 15/16 3 39/32 4 5/64 4 29/32 5 5/16 6 29/64 7 33/64

F 3⅜ 3⅞ 4⅛ 4⅝ 4⅝ 5⅛ 5⅝

G 1¾ 2⅛ 2 11/16 3¼ 3¾ 4 13/16 5 29/32

H 4 4 4 4 4 4 4

B 3⅛ 3⅞ 4½ 5¾ 7 7¾ 9 10

C 2.515 2.890 3.390 4.515 5.410 5.882 6.890 7.840

D 1.875 2.125 2.562 3.562 4.333 5.159 5.688 6.608

E 2 11/16 3 1/16 3 9/16 4 11/16 5 37/64 6 1/16 7 3/32 8 3/64

F 3⅛ 3⅝ 3⅞ 4⅜ 4⅞ 5⅛ 5⅜ 5½

G 1 1¼ 1½ 2¼ 2¾ 3½ 4 4¾

H 5 5 5 5 4 4 4 4

REG Connections

SIZE 2⅜ 2⅞ 3½ 4½ 5½ 6⅝ 7⅝ 8⅝

A 3 3½ 3¾ 4¼ 4¾ 5 5¼ 5 3/8

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NC Connections

NC # 23 26 31 35 38 40 44 46 50 56 61 70 77

A 3 3 3½ 3¾ 4 4½ 4½ 4½ 4½ 5 5½ 6 6½

B 3⅛ 3½ 4⅛ 4¾ 4¾ 5¼ 5¾ 6¼ 6¾ 8 9 9¾ 11

C 2.437 2.750 3.266 3.625 3.891 4.156 4.499 4.709 5.135 5.703 6.266 7.141 7.828

D 2.063 2.376 2.808 3.114 3.349 3.530 3.875 4.084 4.500 4.626 5.063 5.813 6.376

E 2⅝ 2 15/16 3 29/64 3 13/16 4 5/64 4 11/32 4 11/16 4 29/32 5 5/16 5 15/16 6½ 7⅜ 8 1/16

F 3⅛ 3⅛ 3⅝ 3⅞ 4⅛ 4⅝ 4⅝ 4⅝ 4⅝ 5⅛ 5⅝ 6⅛ 6⅝

G 1¼ 1½ 2 2 2¼ 2 13/16 2 13/16 2 13/16 2 13/16 2 13/16 2 13/16 3 3

H 4 4 4 4 4 4 4 4 4 4 4 4 4

Interchangeable Threads

NC26 = 2 ⅜ IF NC31 = 2 ⅞ IF NC38 = 3 ½ IF NC40 = 4" FH NC46 = 4" IF or 4 ½ XH NC50 = 4 ½ IF or 5” XH

©2008 SMITH International, Inc.

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Measuring the Connection Introduction

If using logic doesn’t identify a connection, then it’s time for a joint identifier. A Tool Joint Identifier is also used to measure dimensions for interchanging connections. If using a Tool Joint Identifier doesn’t identify a connection, then measure the OD of a connection. The Tool Joint Identifier or a data sheet with connection dimensions will help determine the thread type and nominal size of the connection.

Tool Joint Identifier

The simplest way to measure threads per inch on the connection is using a Tool Joint Identifier, sometimes called an “idiot stick”. This tool identifies the most common threads. When a tool joint is identified, confirm the measurement with a proper gauge. The first step in identifying a connection is to measure the threads per inch. Common thread types are on the front of the ruler, where SMITH SERVICES is printed. They are: o 3 ½ threads per inch o 4 threads per inch o 5 threads per inch

Tool Joint Identifier

The reverse side of the Tool Joint Identifier distinguishes which side is used for measuring the pin, and which side is used to measure the box.

The number of threads per inch will help limit the type of connection. All PAC, IF, XHole, and NC have four threads per inch. H-90 connections have 3½ threads per inch. The remainder, Full Hole, and Regular, can be 4 or 5 threads per inch depending upon size.

©2008 SMITH International, Inc.

Measuring the Pin

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Measuring the OD of a Pin Connection

In addition to identifying the connection threads, OD requires measurement. There are two methods, one for the pin end and the other for the box end. Pin End Measurement

For the pin end, use a caliper to measure the connection OD at the cylindrical base of the pin. If the pin has a relief groove, about ½ inch of unthreaded connection at the base of the pin, then use a straight edge to measure the connection OD accurately. Measuring with a Caliper

Line up one prong of the caliper with the pin mark on the thread identifier and let the other caliper prong fall where it will along the marked lengthy of the identifier. The markings closest to where the prong falls that match the measured threads per inch will help identify the thread type and nominal size. Tighten the caliper while it has the measurement obtained from the pin end. Line it up in the notch on the pin side of the tool joint identifier.

Pin Relief Groove Measurement

The caliper measurement will not always fall directly on one of the premarked hash marks on the thread identifier, sometimes exactly between two. You may still have to explore more measurements, such as pin length and/or tool ID. The thread identifier Lining up with Tool Joint Identifier should be used only as a guideline to help the user determine the correct thread.

©2008 SMITH International, Inc.

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Measuring the ID of a Box Connection

Measuring the box connection requires fewer steps and is much easier. Just use the thread identifier to measure between the inside edges of the mouth of the box. The markings on the identifier will identify the connection.

Measuring the Box End

Verification

When measuring is complete, verify the measurements are correct using the proper gauge to double check. There are two gauges types used to verify measurements. The first is a Stone Ground Gauge, which is tool joint with perfect measurements. These gauges are extremely expensive and must be housed in an air conditioned environment to maintain their integrity. Stone ground gauges are required for all API shops. The other gauge type is a Po’ Boy thread gauge. This is created from an existing connection where the size is known. To verify the size of an questionable connection the Po’ Boy is threaded onto the questionable connection to see if it fits.

Hard to Identify

If the threads are still difficult to identify the problem could be a couple of things. First, the connection could be measured as either a 4 ½ API Regular or full hole. It’s also possible the connection is not listed on the tool joint identifier, or it’s a specialty cut connection. Follow a measurement chart and take measurements of other parts of the connection which may identify it. See the dimension chart included in this chapter for measurements.

NC Connections

Some of the connections are easily interchanged. The following list shows the connections that work with NC connections. NC 26 2 ⅜IF NC 31 2 ⅞IF NC 38 3 ½ IF NC 40 4" FH NC 46 4 ½ X-hole or 4” IF NC 50 5" X-Hole or 4 ½ IF

©2008 SMITH International, Inc.

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Recap

When there is a questions about thread type, use the following methods to aid in identification: 1 2 3 4 5 6 7

©2008 SMITH International, Inc.

Use logic when looking at the threads Measure the connection with the tool joint identifier Use the caliper to measure the pin base Use the tool joint identifier to measure the box end Verify the results Double check with connection drawing Make sure to double check all connections before sending components out to a job

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Activity: Thread Identification

Part A Look at the pictures below. Follow the directions for each.

In the image above circle all the shoulders. The list below shows parts of a connection you should be familiar with. Circle and label these parts in the diagram on the left.

©2008 SMITH International, Inc.

1.

Shoulder Seal

2.

Bevel

3.

Critical Pin Area

4.

Critical Box Area

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Part B Using the charts on pages 10-14, identify the nominal OD of the following measurements. 1. 4 ½" REG

2.

2 ⅞" PAC

3. 3 ½" IF

4.

NC 31

5. NC 50

6.

4 ½" XH

7. 6 ⅝ REG

8.

NC 46

9. NC 26

10. 2 ⅞" REG

©2008 SMITH International, Inc.

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Failure Mechanisms

CHAPTER 5

FAILURE MECHANISMS Module Objective

At the end of this chapter, you should be able to: o Identify and explain common failure mechanisms, ways to reduce failures and common ways to identify drill string o Explain what fatigue is o Explain how tension affects the drill string o Explain how torsion affects the drill string o Explain how buckling affects the drill string o Explain how corrosion affects the drill string o Explain how burst/collapse affects the drill string o Identify the ways to reduce drill string failure o Explain the inspection methods used to identify flaws

Topics

Exercise: Drill String Failure Failure Mechanisms Fatigue Tension Torsion Buckling Corrosion Burst/Collapse Poor Handling Practices Reducing Drill String Failure Inspection Methods Drill Pipe Damage Exercise: Drill Pipe Damage

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 5 – Failure Mechanisms

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©2008 SMITH International, Inc.

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Exercise: Drill String Failure

Read the following pages on failure mechanisms, fatigue, tension, torsion, buckling, corrosion, burst/collapse, poor handling practices, and reducing drill string failure. Your group will be assigned one or more of these concepts. You will have to design a poster that describes each concept assigned in detail. You must include at least one visual. Your group will be judged based on the quality and explanation of your poster. Your poster should be detailed enough to be self explanatory, but be prepared to explain it. Use the space below to take notes.

©2008 SMITH International, Inc.

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Failure Mechanisms Overview

Drill string failure is the most serious and most costly problem of a drill string. Failure occurs for any number of reasons. Solving drill string failure issues quickly saves time and money. A proactive approach to drill string design will help avoid failure issues. This chapter discusses how drill string failures occur and what inspections are performed to help alleviate the number of failures.

Nature of Failures

Failures vary depending on the location in the drill string. The BHA is comprised of the drill bit, very thick drill collars, and the transition pipe. The remainder of the drill string consists of drill pipe. In the BHA a failure is more likely to occur in the connection because of the component stiffness. Transition pipe, Hevi-Wate drill pipe or Spiral-Wate drill pipe is more flexible than drill collars and more durable than drill pipe and by design it can endure compressive stresses such as buckling. Finally, at the top of the drill string is the drill pipe. Drill pipe tube tends to be weaker than the connection, making the failure more apt to occur in the tube. Drill pipe is exposed to two forces during a drilling operation. The first is tension; tension is the weight of the load the drill string holds. Every component in a drill string must support the weight of every component below it. The other force a drill pipe is constantly exposed to torsion; torsion is the rotation of the pipe downhole. Limited data is available concerning the location of drill pipe failures, the type of failures, or their probable cause. The following list of failures was compiled from vast experience. Most failures occur: o When rotating or picking the pipe off bottom immediately after drilling rather than pulling on stuck pipe o Within four feet of the tool joint on either end of the pipe o When there is severe pitting on the inside of the pipe, the pitting usually began from the inside o From slip marks or other surface damage, such a gouges, welding arc spots, stenciled numbers, etc. o As a result of pulling on stuck pipe Drill strings failures are caused by forms of fatigue, tension, torsion, burst/collapse, or corrosion.

©2008 SMITH International, Inc.

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Fatigue

Washout Due to Fatigue

Drill pipe fatigue is the most common cause of failure. Drill pipe fatigue is progressive, cumulative damage that occurs when the pipe is subjected to cycles of stress (tension, compression, and torsion) that exceeds the tensile strength of the material. Visible cracks are formed from submicroscopic cracks.

Tension

Tension failure occurs when the load applied to the drill string is beyond the operating capacity of the weakest member of the string; usually near the top of the hole. Tension (or tensile) capacities are calculated based on the minimum yield strength of the steel and the cross-sectional area of the affected string member.

Torsion

Torsional failure is a yielding of the drill stem component due to applying excessive torsional loads (twisting) resulting in a swelled box. A connection will hold the amount of torque applied until an equal or greater opposite force is applied to the connection. The danger occurs because the Overtorqued Connection connection will take any additional torque. Make up torque should be 60% of the torsional yield for the tool joint connection. Torsional failure first appears as stretched pins or swelled boxes, depending on which is the weaker part of the connection.

©2008 SMITH International, Inc.

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Corrosion

Corrosion is the alteration and degradation of material caused by its environment. Corrosion is a contributor to drill string failure. The primary corrosive agents are dissolved gasses (oxygen, CO2, H2S), dissolved salts, and acids. In Hydrogen sulfide (H2S) environments the BHA is mainly affected. As the chemical attacks the pipe it changes forms (chemically altered) and is no longer dangerous to the remainder of the drill string. The result is a high probability of a failure in a BHA connection. Carbon dioxide (CO2) is a common element emitted by vegetation during photosynthesis. But, if it is combined with high salinity (salty) water, it causes corrosion on the pipe. Visually this appears as pitting on the pipe. Excessive Pitting

Burst/Collapse

Drill pipe collapse occurs when the pressure in the wellbore is higher than the pressure in the pipe by an amount that exceeds the collapse capacity of the pipe. When the fluid levels inside and outside the drill pipe are equal, and the density of the mud is constant then there will be no pressure to collapse. Drill pipe burst is the exact opposite where the internal pressure exceeds the external pressure. Neither of these occurrences is common in drill pipe, and impossible in a drill collar.

©2008 SMITH International, Inc.

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Fatigue Overview

Drill pipe fatigue is the most common cause failure. Drill pipe fatigue is progressive, cumulative damage that occurs when the pipe is subjected to stress cycles (tension and compression) that exceed the tensile strength of the material. Drill pipe fatigue failures are often due to gradual progressive growth of minor irregularities into major cracks.

Fatigue Limit

The fatigue limit is estimated to be one-third to one-half of the minimum tensile strength of the pipe. Theoretically, the pipe will never fail if stress doesn’t exceed the fatigue limit.

Fatigue Failure

Metal tubes in the drill string subjected to cyclic combinations of stress will fail due to the growth of small irregularities to large cracks and stress even after the tube is no longer exposed to a high level of stress. This failure through progressive growth of small irregularities at low stress levels is a high-cycle, low-stress fatigue failure. Commonly, the area around the fracture shows concentric semicircular marks that illustrate periodic growth of the crack, which are sometimes called beach marks. The beach marks are more common in connection fatigue.

Various Factors Affect Fatigue

Early studies examined the effect of combined bending and tensile stresses in drill pipe. This showed that when a length of pipe is in a gradually changing hole angle, the tool joints are pulled tangent to the wall of the hole, and the pipe between the tool joints is pulled straight, creating severe bending of the pipe adjacent to the tool joints. The amount of bending stress is relative to the rate of change of the hole angle and to the amount of tension in the pipe.

©2008 SMITH International, Inc.

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Drill Pipe vs. Drill Collars

Each component is affect differently by bending change. Drill pipe tends to be more affected by bending that occurs in the upset runout area. The area least affected is the tool joint. Drill collars are the complete opposite. High bending stress areas are at the connection and low bending stress is in the middle of the pipe.

Fatigue Break

Combined Stresses

Bending pipe causes each fiber to be stressed alternately in tension and compression. Adding high-tensile pull to the pipe causes the stress to vary from maximum tension to compression. Including a secondary stress on the pipe reduces the ability of the pipe to withstand cyclic stress. Since drill pipe is always operated in tension, the fatigue life of the pipe is reduced to some degree by the amount of tension in the pipe. Where drill pipe is highly stressed in bending, as in a dogleg, the amount of tensile stress becomes critical.

Combined Stresses of Tension and Bending

A plot of tension in the pipe vs. rate of change of hole angle, is demonstrated for Grade E-75 drill pipe. There is a tensile load of 200,000 pounds in the pipe, a rate of change of hole angle greater than 2¾º per 100' will stress the pipe above the endurance limit, while with a 50,000 pound tensile load in the pipe, 7º per 100' could be tolerated without exceeding the endurance limit.

©2008 SMITH International, Inc.

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Tension Overview

Drill pipe tension exists when a very heavy load is being supported by the top of the drill string. The steel is elastic in nature, meaning that it has the capability to stretch and then return to its original shape after the weight is released. There are limits to the elasticity though. Drill pipe can only stretch so much before the drill pipe is stretched beyond its limits. Understanding the elasticity of the drill pipe and its limits are covered in this section.

Elasticity

Steel drill pipe that is made up in a drill string is expected to stretch to some degree. This is due to each component in a drill string supporting the weight of the components below it. The components at the top of the drill string are supporting very heavy loads and will stretch like a rubber band, returning to its original size Elastic Deformation and shape after the load is removed; this type of stretching is called elastic deformation.

Elastic Limit

If too much weight was added to the drill pipe in the above image the pipe would not return to its original size. There is a limit to the amount of weight that can be added without consequence. If too much weight is added to the drill pipe, it will not return to its original length when the weight is removed. The drill pipe will be permanently Elastic Limit deformed. The limit of weight that can be added before the drill pipe will be permanently deformed is the elastic limit.

©2008 SMITH International, Inc.

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In the image to the left: o The top pipe represents point A, with no damage to the pipe after stretching o The second pipe shows the stretch from points B to C o The third image represents the fracture point indicated on the chart above

Yield Point

Keeping the drill pipe within acceptable limits is the only way to ensure its performance and longevity. Maximum Allowable Hook Load

During oil well drilling, the concern is how much pull is available on a string of drill pipe. The yield strength and the tensile strength of the pipe then become very important. It is always desirable to keep the tensile stress in the pipe below the material’s yield point. This is referred to as the tensile yield strength or maximum allowable hook load for the pipe.

Effect of Tensile Strength on Endurance Limit

In drill pipe steel, an increase in yield strengths is obtained without a relative increase in ultimate strength. The chart below shows the minimum yield strength (point B on the previous page) and the minimum tensile strength (point C on the previous page). Grade

Min. Yield Strength psi

Min. Tensile Strength psi

D-55 E-75 S-135

55,000 75,000 135,000

95,000 100,000 147,000

Ratio of Min. Yield to Min. Tensile 58% 75% 91%

Keep in mind the information provided in this section is based on destructive testing. The primary focus in the field is to monitor and work within API standards.

©2008 SMITH International, Inc.

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Tensile Test

Laboratory tests have determined the limits of stress and strain that can be exerted on drill pipe. A sample of one drill pipe is tested to ensure it meets basic API requirements. The sample is exposed to the minimum yield strength indicated by the grade (point A). Point A is a representation of the normal operating limits of the drill pipe. Additional pull is placed on the sample to reach point B. Once the sample is exposed Weight Limits of Drill Pipe to Point B it will be permanently elongated. The sample is then exposed to more stress and strain until it reaches point C. The longer the arc is from point B to point C, the stronger the sample. At point C, the sample is necking down and will eventually fracture. Common Grades E-75 X-95 G-105 S-135

©2008 SMITH International, Inc.

Yield Strength Minimum Maximum (A) psi MPa (B) psi MPa 75,000 517 105,000 724 95,000 655 125,000 862 105,000 724 135,000 931 135,000 931 165,000 1138

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Torsion Overview

Torsion applies to the drill string in two ways. First in the connections when they are made up (also called make-up torque) then in the entire drill string while it is rotating. The problems that can occur will be discussed in this chapter.

Connection Torque

When a joint is added or removed from the drill string, torque is applied to tighten or loosen the tool joint. The torque is measured in pounds. Applying too much torque while making up a tool joint will damage and weaken the connection. Make-up torque is applied using a top drive or large wrenches called tongs. Torque is applied using rig equipment to apply force by pulling

Controlling the Torque

on one tong while the other is tied off at a fixed point. The length of the tong is multiplied by the pound of pull to provide a ft/lb. value.

Torque Monitoring Equipment

Drill String Torsion

If a tool joint is not tightened enough there will not be a seal in the connection. A leak will occur and a washout will happen in these cases.

One of the drill pipe functions is to rotate the bit and BHA. Rotation causes a torsional stress on the drill string. Common downhole conditions including wall friction and stabilizer hang-up will increase the torque required to rotate the tube. If the torque becomes too great, the tube may fail. The drilling torque should never exceed make-up torque. Similar to tension there is a yield point with torsion. The torsional yield strength of drill pipe is the resistance of the tube to fail by a twisting torque or force.

©2008 SMITH International, Inc.

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Combined Torsion and Tension

Usually when a drill string is downhole it is subjected to more than one force. The drill string is not only turning downhole, but each component is supporting the weight of the components below it. When a joint of drill pipe is subjected to a combined load of torque and tension, such as normal drilling operations, it is more likely to torsionally fail. The chart below illustrates the effect of tension and torsion on 4 ½", 16.60 lb/ft, grade E-75 drill pipe. As the wall of the drill pipe is worn away and the joints decrease in class, its ability to work with extreme levels of tension and torsion decrease.

Tension and Torsion based on Class

©2008 SMITH International, Inc.

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Corrosion Overview

Corrosion is the alteration and degradation of material caused by its environment. Corrosion is a common cause and contributor to drill string failure. The primary corrosive agents are dissolved gasses (oxygen, CO2, H2S), dissolved salts, and acids.

Sulfide Stress Cracking

Sulfide stress cracking (SSC) is a frequent cause of drill string failure, which occurs when drilling H2S environments. Atomic hydrogen, the smallest of atoms, penetrates the steel changing the chemistry of the steel of the drill pipe. Normally, hydrogen atoms quickly combine to form Possible SSC molecular hydrogen, which is too large to be absorbed by the metal and bubbles off as gas. In the presence of sulfide, the hydrogen remains in the atomic form for a longer time. This longer span allows a greater probability of absorption by the pipe. After absorption, the hydrogen accumulates in the area of maximum stress, and when a critical concentration is reached, a small crack forms. Then hydrogen accumulates at the top of the crack and the crack grows. The process continues until the remaining metal cannot sustain the applied load and a sudden brittle fracture occurs. To offset the effects of the H2S environments an oil based mud can be used for circulation. If the H2S scavengers achieve a proper pH prior to attacking to the pipe, the effects will be neutralized before causing damage.

©2008 SMITH International, Inc.

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Pitting

CO2 environments are also considered corrosive. When CO2 mixes with water, carbonic acid is formed. The carbonic acid forms scale in the water and can attach to the pipe surface, trapping moisture next to the pipe wall. Pitting can occur should this scale be left untreated. This problem is referred to as under-deposit corrosion. Drill Pipe Pitting Additives to the circulation medium can help prevent this from occurring.

Proactive Approach

Lowering minimum yield materials will allow work to continue despite the corrosive environment. Grades E-75 and X-95 are recommended when H2S gas is present. Some manufacturers have developed higher strength drill pipe that has shown resistance to failure in corrosive environments, called controlled yield drill pipe.

©2008 SMITH International, Inc.

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Burst/Collapse Overview

Drill pipe collapse occurs when the pressure in the wellbore is higher than the pressure in the pipe by an amount that exceeds the collapse capacity of the pipe. When fluid levels inside and outside the drill pipe are equal, and the mud density is constant there will be no differential pressure to collapse. Drill pipe burst is the exact opposite where the internal pressure exceeds the external pressure.

Yield Strength Collapse

The yield strength collapse refers to the pressure that generates minimum yield stress on the inside wall of a heavy wall tubes. The yield strength collapse pressure is not a true collapse pressure, but is used because it is thought to be unsafe to use a pressure greater than that, which causes yielding.

Drill Pipe Collapse

Collapse Pressure in Drill String Design

The drill pipe may be subjected to an external pressure higher than the internal pressure. This condition can occur during drill stem testing and may result in collapse of the drill pipe. Differential pressure is required to produce the collapse.

Drill Pipe Burst

Drill pipe burst is the result of excessive internal pressure. A burst pipe may be the most common occurrence where excessive internal pressures are experienced.

Drill Pipe Burst

©2008 SMITH International, Inc.

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Poor Handling Practices Notches and Cuts

Notches and cuts in the drill pipe metal will increase the fatigue amount, speeding the breakdown of metal. If the notch or pit is within 20 inches of the tool joint, where maximum bending takes place, it can form an early fatigue crack. All dents and scratches can eventually cause drill pipe failure: o Slip marks, cuts, and scratches o Corrosion grooves caused by rubber protectors o Electric arc burns o Downhole notching caused by formation and junk cuts o Dynamic loading of pipe in slips

Bent Pipe

Bent or crooked pipe is always a potential failure because the stress cycle is magnified at the bend. Bent pipe should never be used while actively drilling or rotating. If pipe is returned from a job bent, then it needs to be straightened before it is sent out again.

Bent pipe is caused by: o A crooked kelly can cause bending in the first joint of pipe below the rotary table o A mast or derrick that is not plumb causes the crown block to be off-center; the off-center block throws bending stresses into the kelly and the drill string o Drilling with compressive loads in the drill pipe section of the drill string o Drilling through severe doglegs or around ledges o Intentionally for fishing purposes

©2008 SMITH International, Inc.

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Reducing Drill String Failure Better Operational Practices

Drill string failures can be prevented by working within the published capacities for the drill string material. Operating at stress levels below the fatigue limit can theoretically eliminate drill pipe fatigue. Unfortunately, laboratory conditions cannot replicate all the conditions encountered while drilling and greater stress will occur on a drill string in the field.

Better Materials

Tough material, as measured by its impact resistance, retards the formation and growth of fatigue cracks. Tough material is also less likely to fail catastrophically than brittle (not tough) material operating under identical conditions. Toughness is primarily determined by metallurgical chemistry, cleanliness, and heat treatment.

Better Environment

Reducing the corrosiveness of drilling systems will result in fewer failures. This includes: o Using softer drill string components that can absorb more hydrogen without becoming brittle, such as E-75 or X-95 o Using H2S scavengers o Using oil-based mud o Elevating mud PH which reduces acidity

Better Design

Drill string design and thread selection are the first steps in lowering operating stress levels and reducing drill pipe fatigue. Even though improvements in design will not eliminate drill pipe fatigue, they will slow down the fatigue process and they can also prevent other types of failure such as tension or torsion failures. Moreover, it is important to design the string so the area of the string subjected to the most stress (comprehensive drilling loads) is the strongest area of the string.

Better Inspection

Consistent inspection prevents drill pipe failures by detecting fatigue cracks and other indicators of failure before they reach the point that failure occurs. Consistent inspections and standardized handling practices will reduce the number and severity of notches and cuts that are placed on the pipe through poor handling practices.

©2008 SMITH International, Inc.

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Inspection Methods Introduction

There are many problems that can arise while drilling. One way to prevent possible issues is to conduct regular BHA and drill pipe inspections. There are many different inspection methods to detect stress risers and fatigue in drill string components. o o o o o

Inspection Preparation

Visual Inspection (VT) Magnetic Particle Inspection (MT) Electromagnetic Induction (EMI) Ultrasonic Inspection (UT) Liquid Penetrant (PT) for non-mag components

Preparing a tubular item for inspection requires that it be clean of dope, dirt, paint, and rust. An inspection of the threads requires cleaning with a brush and solvent. The OD of the tube will undergo a buffing to help identify any cracks.

©2008 SMITH International, Inc.

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Visual Inspection (VT)

A visual inspection (VT) is the most common non-destructive method of on-site drill pipe and BHA inspection. Adequate lighting, a well trained eye, and in some cases a camera are required to perform a VT. The inspector visually examines the tool for defects and connections for common key issues. For example, the presence of dark areas on the shoulder or excessive galling of a component connection is indicative of under-torquing; this indicates the presence of future problems if not addressed by the drilling contractor. This is a viable stand-alone inspection method, but is generally conducted in conjunction with more critical methods of nondestructive testing.

An External and Internal Visual Inspection

The following is a list of the specific items inspected during a VT: OD, ID, length, shoulder condition, benchmark, thread profile and depth, bevel diameter and eccentricity.

Box Swell

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Bent Pipe

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Magnetic Particle Inspection (MT)

Magnetic Particle Inspection (MT) is the act of inducing a magnetic field into ferromagnetic drill pipe/BHA components to detect any inherent or service related defects in the metal. There are three basic methods of magnetic particle inspection dependant on the sensitivity requirements: Visual Wet: A magnetic field is applied and visually identifiable particles are applied contrasting to the surface of the tool to be inspected.

Visual Dry-Internal Component Particle Crack

Visual Dry: A yoke is used to induce an active magnetic field on the surface of the tool to be inspected while the inspector simultaneously applies a small amount of dry fine grain iron oxide powder.

The image to the right shows the inspector holding a small flame to the inside of a tube. He is looking for unusual and concentric formation of powder that will identify a crack. It is used specifically on upsets, Kellys, and the slip area on drill pipe.

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Fluorescent Wet Inspection Shows Cracks Under a Blacklight

Damage Caused by Slips

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Fluorescent Wet: This method can be used with an active magnetic field or a strong residual magnetic field. A magnetic force is applied to the test piece and a fluorescent suspension of solvent or waterbased iron oxide particles are applied to the test piece. A black-light is used to ascertain the presence of any discontinuities or inherent irregularities in the metal. MT works because the magnetic field spreads out when it encounters the small gap created by the crack. This is because the air cannot support as much magnetic field per volume as the magnet can handle. The particles are attracted to the small magnetic leakage fields from discontinuities (flaws).

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Pin Connection

Field Indicator Full Length Body

Ultraviolet Meter Centrifuge

Ultraviolet Light DC Coil

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Electromagnetic Induction (EMI/MFL)

MFL inspection systems are based on the same principles as magnetic particle inspection. The primary difference between MFL and magnetic particle inspection is the use of sensors. MFL sensors, developed in the 1920's and 30's, measure the magnetic field around a defect. Sensors allow a quantitative measurement, rather than the more qualitative information provided by particles. Sensors between the magnet pole pieces measure the flux leakage field. The purpose of sensor systems is to convert the flux leakage field into a signal that can be stored and analyzed. The sensor system consists of the Setting Up Buggy sensors themselves, the mounting system used to support the sensors, wear plates between the sensors and the pipe, and cabling between the sensors and other electronic components. The two types of sensors commonly used in MFL tools are induction coils and Hall elements (field sensor). Coils measure the rate of change of a magnetic field, while Hall elements measure the actual magnetic field strength.

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Buggy Around Tube

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Ultrasonic Inspection (UT)

Ultrasonic inspection can be performed on the entire tube of drill pipe, on the upsets area, the rotary shouldered connections, or on all three. A magnetic particle inspection is generally used to confirm the finding of UT, where applicable. In ultrasonic testing, highfrequency sound waves are Testing Equipment transmitted into a material to detect imperfections or to locate changes in material properties. The most commonly used ultrasonic testing technique is pulse echo, where sound is introduced into a test object and reflections (echoes) from internal imperfections or the part's geometrical surfaces are returned to a receiver. Below is an example of shear wave weld inspection. Notice the indication extending to the upper limits of the screen. This indication is produced by sound reflected from a defect within the weld. Shear Wave Weld Inspection

Transducer and Wedge

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Liquid Penetrant (PT)

Liquid Penetrant Inspection detects surface defects and cracks in nonferromagnetic metals. This method can be applied to nonmagnetic components of the BHA and various internal components of downhole tools used in drilling applications.

Red Bleedout

Red Dye

Developer ©2008 SMITH International, Inc.

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There are three types of PT that can be used: Fluorescent, Non-FluorescentVisual, and Dual-Sensitivity. These types are distinguished by the light source used to inspect the test specimen. Each type can be further broken down to a particular method—Water Washable, Post Emulsified, and Solvent Removable, which identifies how the penetrant is removed.

Developer application Step 5

Excess Step penetrant removal 4

Penetrant is Applied

Excess Penetrant is Removed

Step 1

Cleaning Penetrant

Step application 2

DPI

Step Penetrant Dwell 3 After the test object has been cleaned, it is coated with a solution containing a visible or fluorescent dye. The dye is left on the test object for an predetermined amount of time before removal. It is removed from the surface of the object, but remains in surface breaking defects. A developer is applied to draw the penetrant out of the defects. With fluorescent dyes, ultraviolet light is used to make the “bleedout” fluoresce brightly, allowing imperfections to be readily seen. With visible dyes, vivid color contrasts between the penetrant and developer make "bleedout" easy to see. The red indications above represent a number of defects in this component.

Developer is Applied ©2008 SMITH International, Inc.

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Inspection Identification

An inspected component needs to be identified as acceptable or unacceptable. Some flaws can be repaired while others render the pipe unusable. Damaged and unusable drill pipe is marked with bright paint. Damaged components require documentation, which should be thoroughly completed to Damaged Shoulder minimize confusion in the future. Even the most thorough inspection may not find all the flaws of a drill pipe. As previously mentioned, most drill string failures are due to fatigue. Unfortunately, fatigue flaws are progressive and cannot be detected until they reach the surface of the component. Visually a fatigue flaw appears as a crack in the form of a single line on the drill pipe surface.

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Drill Pipe Damage Damage Washout

Twist Off

Fatigue Cracking

o o o o o o o o o

Typical Location Slip Area Areas where pipe has been stressed due to transition from pipe to collars Slip Area Washout Areas where pipe has been stressed Slip Area Pipe run in compression Pipe used in horizontal drilling Areas where pipe has been stressed

Corrosion Pitting

Anywhere on pipe

Slip Cuts

Slip Area

Slip Area Mash/Crush

Slip Area

Necking

o Slip Area o Near Upsets

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Probable Causes o Surface notching o Cyclic stressing o Fatigue cracking o o o o

Surface notching Cyclic stressing Fatigue cracking Over torque

o o o o

Surface notching Cyclic stressing Corrosion Cuts hydrogen embrittlement

o o o o o o o o o o o o o o

Chlorides Oxygen Acid Co2 H2s Galvanic action Pipe turning in slips Not using back-up tongs Defective slips Defective bowl Improper slip handling Defective slip component Improper lip handling Excessive make-up or break out torque Bending pipe in slips Using slips to stop downward movement of pipe Improper size slip inserts Stuck pipe Pull past minimum yield Excessive hook load Worn master bushing Stopping travel of pipe with rotary slips

o o o o o o o o

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Damage String Shot

Typical Location o Above pin o Below box that has been backed off

OD Wear

Near center of tube body, spreading towards ends

ID Wear

Near upset areas

Crooked Pipe

o Slip Area o Center third of pipe body

Tong Cuts

Near pin and box end upsets

Chain Cuts

Just above pin end upsets

Rubber Cuts

Approximately 3’ above pin end tool joint

Hammer Dents

Tube body near tool joints

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o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o

Probable Causes Stuck pipe Integral explosion (string shot) for back off Abrasive formations Crooked pipe Deviated hole High rotary speeds Harmonics Doglegs Horizontal drilling High velocity abrasion Sharp sand Drilling fluid turbulence Corrosion Bending in slips (setting tool joint too high above slips) Improper tong line geometry Not using back-up tongs Poor transport handling Dropping pipe on racks Critical harmonics rotary speed Picking up pipe with winch line in center Improper drill collar weight Harmonics Bent for fishing operation Deviated hole Horizontal drilling Pipe run in compression Dropped pipe Tongs placed on pipe body Worn tool joints Short tong space on tool joints Improper tong jaws Poor handling Excessive spinning Chain slip Corrosion Erosion Casing protector Poor mud drain Cleaning at protector end Tapping pipe to check fluid level on trip out of hole

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Damage

Typical Location o o o

Washout/Dry or Muddy Connections

o o

o Shoulders o Threads

o o o o o

Shoulder Gall

Shoulder Area

Shoulder Fins

Shoulder Area

Shoulder Damage

Shoulder Area

Galled Threads

Threaded Area

Pin Break (Cut)

Threaded Area

o o o o o o o o o o o o o o o o o o o o

Pin Break (Flat Fracture)

Threaded Area

o o o o

©2008 SMITH International, Inc.

Probable Causes Damaged or leaking shoulder (face) seals Incorrect make-up torque Galled threads producing excessive shoulder stand-off Shoulder fins rolled between seals High spots on shoulder (false make-up torque) Excessive shoulder removal by refacing Stretched pin threads Dirty threads and shoulders Miss-stabbing connection Improper jacking of stands in setback area Incorrect lubrication on shoulders Incorrect make-up torque Shoulder fins rolled between seals High spots on shoulder Mating tools with different ODs Handling damage Miss-stabbing connections Handling damage Spinning chain between shoulders Improper pipe jacking Handling without thread protectors Cross threading Worn threads Improper thread compound Dirty connection Defective kelly saver sub Improper make-up torque Additional down-hole make-up torque Improper thread compound producing excessive make-up stress Pin wobble failure due to improper make-up torque Shoulder fins False torque Fatigue cracking at last engaged thread root 5/8: from shoulder Galled threads

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Damage Pin Stretch

Typical Location Threaded Area

OD wear

Box and Pin OD

Box Bell

Shoulder Area

o o o o o o o o o o o o o o o o

Heat Check

Box and Pin OD

o o

©2008 SMITH International, Inc.

Probable Causes Improper make-up torque Additional down-hole make-up torque Improper thread lubricant Crooked pipe High rotary speeds Abrasive formation Doglegs Deviated hole Horizontal drilling Rotation of pipe in compression Harmonics Improper make-up torque Additional down-hole make-up torque Thin tool joints Improper thread compound Rapid heating and cooling due to friction between tool joint and formation, casing, whipstock, etc. High rotary speeds with rapid cooling Use of top drive while rotating out of the hole

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Exercise: Drill Pipe Damage Using the Drill Pipe Damage Chart from the previous section and the information discussed at the beginning of the chapter to name the defect and probable cause. 1.

2.

3.

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Using the Drill Pipe Damage Chart from the previous section and the information discussed at the beginning of the chapter to name the defect and probable cause. 4.

5.

6.

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Using the Drill Pipe Damage Chart from the previous section and the information discussed at the beginning of the chapter to name the defect and probable cause. 7.

8.

9.

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Answer the following questions based on information from the Inspection Methods section. 1.

What inspection processes are performed on drill pipe?

2. Briefly explain ultrasonic inspection and where it is used.

3. Explain liquid penetrant inspection methods and name two components that require this inspection method.

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Drill String Design

CHAPTER 6

DRILL STRING DESIGN Module Objective

At the end of this chapter, you should be able to: o Complete the calculations required to design a drill string o Identify the information the customer needs to provide in order to design a drill string o Complete the calculations to determine the number of drill collars needed in the BHA o Complete the calculations to determine the amount of drill pipe needed in the drill string o Perform the calculations to verify the previous calculations were correct o Identify troubleshooting methods for common drill string problems

Topics

Well Information BHA Information Drill Pipe Information Verification Troubleshooting Exercise: Drill String Design

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BHA & Drill String Fundamentals Chapter 6 – Drill String Design

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Drill String Design

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Well Information Overview

There several processes used to design a drill string. Customer input will alter the process; changes in the method result from hole complexity, angle, and geometry. The chapter discusses the recommended order to follow for vertical wells. This section will cover well information including: gathering customer information, determining hole configuration, and fishing contingencies. The remainder of the sections will cover how BHA information is calculated: total weight of drill collars and BHA, and total length of the drill collars. Next, the drill pipe information is collected. Then the verification process is covered, including overpull, maximum drill pipe length, and comparing the results to well data. Finally, troubleshooting methods, including reconfiguring the BHA and substituting different grades, weights, or size of drill pipe and recalculation. Gather Customer Information

The customer provides information to design a drill string, including the total depth of the well, the hole size, and the number of drill collars or the weight on bit (WOB). Occasionally, the customer will request what they need to drill the well. For example, they want a certain number of drill collars sent to the site or the WOB should be a certain amount.

Determine Hole Configuration

The information the customer provides will help determine the size of the equipment to be run downhole. This equipment includes the bit, drill collars, and drill pipe. The customer may provide the bit themselves, or will determine the type necessary. The remainder of the BHA components are determined by hole size compatibility and availability.

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Example

A customer requests a drill string design. They need the depth of the well to be 5,000 ft, and the plan is to drill out 7" 32# casing with their own bit. The information to find the correct sizes is found on a chart called Hole Configuration, located on page 5 in the appendix.

What bit size is needed to drill through 7" 32# casing? ________ Fishing for Equipment

The equipment must be able to fit in the hole, it is important to match up the hole configuration with the right equipment so in the event of an unforeseen fishing job, the equipment can be easily removed from the well. Items stuck in the well are removed with a component called an overshot. An overshot is a tool with a specially designed barrel and internal gripping teeth that can be slipped over the end of tubing or drill pipe lost downhole. Well bore or bit size is the determining factor in choosing the correct size overshot. Fishing experts recommend the largest OD overshot be used in most circumstances. The OD of the choice overshot should be as large as possible, yet will not exceed casing drift diameter. Hole conditions must also be taken into consideration.

Overshot

"

Never put a tool into the customer’s well that cannot be fished out of the well with an overshot, preferably a full strength model.

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Example

The Hole Configuration Chart, on page 5 in the Appendix, will help determine the correct overshot size. The chart shows the universal Bowen component numbers.

Use the information from the previous example to answer the following questions. What is the OD of the overshot needed for this job? ________ What is the maximum OD of a component that can be fished? ________ Recap

The customer information gathered has identified the correct bit size, drill collar and pipe. These components all fit the well, and if necessary, they can be fished out. In the next section, the BHA information and calculations will be covered.

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BHA Information Introduction

This part of the process requires calculating information about the BHA. The weight and length of the BHA is needed for future calculations and verifications. Keep the entire drill string in mind when choosing your BHA components. These decisions will affect future drill string requirements and modifications. The BHA weight will help verify that the drill string will work within its specified parameters. Knowing the length of the BHA will help calculate the amount of drill pipe needed and the length of the entire drill string. To find the weight of the BHA, we need to know the weight of a single drill collar.

Drill Collars

Drill collars make up the majority of the BHA. Depending on the size drill collar used, the weight will vary. To find the weight per foot of a drill collar, first find out the OD and ID of the drill collar. The OD of the drill collar usually matches the maximum catch of the overshot. The ID of the drill collar varies. To see all the available IDs, check the Drill Collar Weight Per Foot chart, on page 6 in the Appendix.

"

If a larger ID is used, the connection in the pin is weakened. A smaller ID results in a stiffer pin where a failure is more likely to occur. It is best to pick an ID that is closer to nominal. In addition, the larger ID would result in a lighter weight, while a smaller ID results in a heavier weight. Using either extreme can result in a BHA that is too long or too short, using the average is better.

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Example

Based on the information provided previously in this chapter and above, answer the following questions. What OD of drill collar that should be used? ________ What is the ID of drill collar that should be used? ________ What is the weight per foot of the ideal drill collar? ________

"

Be aware that the drill collar connections will need to match the available Hevi-Wate or drill pipe connection.

Length of a Drill Collar

As a general rule, all drill collars are approximately 30 feet long. While this length can vary, we will assume all drill collars are this length unless otherwise noted.

Length of BHA

The weight of the BHA is calculated by multiplying the number of drill collars by the length of each drill collar. # of Drill Collars x Length of Drill Collars = BHA Length This calculation will help in calculating the weight of the entire BHA.

Example

What is the length of the BHA if the customer requests nine drill collars? Enter the numbers and solve the equation: ________ X ________ = ________

Weight of the BHA

The weight of the BHA needs to be calculated. The information we have collected and calculated will help find this number. BHA Length x Drill Collar Weight Per Foot = Weight of BHA

Example

Using the length of the BHA just calculated determine the weight of the BHA based on the use of the drill collar weight per foot from the top of this page. ________ X ________ = ________

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"

The previous calculation provides the weight of the BHA in the air. Once downhole the weight of the BHA will be partially supported by the circulating mud. Different weight mud will alter the buoyancy factor which could cause the BHA to have more or less WOB.

Alternate Calculation: Required BHA Weight

If the customer provides the WOB instead of the stating the number of drill collars needed then you need to calculate the required BHA weight. When performing this calculation, like many others, a margin of safety needs to be included. In this case it’s to keep the neutral point in the BHA. The safety margin can be anything over 100%. Typically the safety margin will be between 115% and 125%. For the purpose of working through the equations in this chapter the safety margin is 120%. WOB x 120%=Required BHA Weight

Example

If the customer provides WOB information of 10,000 pounds what would BHA weight need to be? Enter the numbers and solve the equation: ________ X ________ = ________

"

The last equation used 120% as a safety margin. The neutral point should remain in the BHA by using this as part of the equation. We want the neutral point to remain in the BHA because drill collars are stronger than the remainder of the drill string.

Length of the BHA

The length of the BHA can now be calculated using the Required BHA Weight calculations just completed. The length of the BHA can be found by dividing the BHA weight by the weight per foot of the drill collar used. Req.BHA Weight = BHA Length DC Weight Per Foot

Example

Use the calculations completed previously in this section. The required BHA weight number from above should be used. For the purpose of this example, use 50 pounds as the drill collar weight per foot. Enter the numbers and solve the equation for BHA length: = _________

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"

Drill collars are typically run in stands of three or multiples of three. When the first equation is complete, it needs to be recalculated for accuracy, keeping in mind the multiples of three. The equation just calculated provided a BHA length of __________. Divide the number by 30 for the number of drill collars. How many drill collars are needed? ________ Take that number and round up to the next number divisible by three. We now have 9 drill collars in the BHA. Now multiply the number of drill collars by the length of each drill collar for the total length of the BHA. 9 X ________ = ________ Multiply the length of the BHA by the pound per feet of the BHA to get the BHA weight. ________ X 50 = ________

Recalculating

It may not be necessary to recalculate the equation. An equation does not have to be recalculated if the BHA length divided by 30 is divisible by three or is not a whole number and is rounded up to a number divisible by three. In order to make things more efficient on most rigs, drill pipe and drill collars are run in stands—which, in most cases, is three joints.

Recap

The last two sections covered information on how to find the weight of a single drill collar by measuring the OD and finding the nominal ID for the weight per foot of a drill collar. Then, the total weight of the drill collars and the BHA were calculated. Next, WOB with a safety factor was calculated, which helped to find the length of the BHA. Finally, the equations completed were recalculated for verification. The next section will cover the drill pipe including the size, length, grade and weight.

©2008 SMITH International, Inc.

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Drill Pipe Information Introduction

The BHA is only one portion of the drill string. The remainder of the drill string is composed of drill pipe. Previously the customer provided us with information including the depth of the well. In the last section the BHA length was calculated. Now, the remainder of the drill string length will be calculated.

Length of Drill Pipe Needed

To determine the length of drill pipe needed, subtract the BHA length from the total depth of the well. Target Depth – BHA Length = Length of DP Needed

Example

Calculate the length of drill pipe needed by using the BHA length from the last section. Since the initial number was not divisible by three, be sure to use 270 feet from the recalculation. The customer has told us their target depth is 5,000 feet. How much drill pipe is needed? ________ – ________ = ________

Length of a Single Drill Pipe

As a general rule, all drill pipe is Range 2 (approximately 31 feet long). While this length can vary, for the purposes of this section, assume all drill pipe is this length unless otherwise noted.

Number of Drill Pipe Needed

Just like calculating the BHA, determining how many joints of drill pipe are required can be accomplished since the length of drill pipe needed has been established. Divide the length of DP required by the length of each joint to find out the total number of joints needed. Length Required =Number of Joints Needed Joint Length

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Example

Calculate the amount of drill pipe needed based on the previous calculation and length of a single drill pipe. = ________

Round this up to a whole number ________. Weight per Foot of Drill Pipe

The weight per foot of a drill pipe can be found on the Drill Pipe Weight chart in the appendix. Drill pipe weight can vary. The chart requires the OD and ID of the drill pipe.

Example

Grade E-75 drill pipe has a 3 ½" connection. The API Drill Pipe Data Sheet, on page 3 of the Appendix, shows a nominal weight per foot of ________. Recap

This section reviewed the drill pipe portion of the drill string. The total length of the drill pipe section was calculated as well as the number of joints of drill pipe needed for the drill string to reach the required depth. Finally, the nominal weight per foot of the drill pipe can be found in a chart in the appendix. The next section covers how to verify the drill string design will work.

©2008 SMITH International, Inc.

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Verification Introduction

The customer needs to be assured the drill string design will reach the target depth and be strong enough to withstand the weight required. The longest allowable length of the drill string needs to be longer than the target depth. Included in the drill pipe length calculations are maximum pull and overpull.

Maximum Pull

The maximum pull calculates the weakest point in the string which is also the greatest amount of weight a joint of drill pipe can take; drill pipe is the weakest member of any drill string because it has less surface area than a drill collar. It is important to know the maximum pull when removing (dragging) the drill string from the hole. Each pipe is responsible for withstanding the weight of everything below it. Depending on the grade of drill pipe (Premium or Class 2) this number will change. The grade used on a job is dependant on what is available and what is currently on the rig. Maximum pull is usually referred to as tensile strength (tension) and can be found on the API Drill Pipe Data Sheet in the Appendix.

Example

What is the maximum pull of Class 2 G-105 drill pipe with a 3 ½" connection and has a nominal weight of 13.30? ________

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Overpull

Overpull is sometimes known as the safety factor. It is the excess tensile capacity above the normal working capacity for contingencies such as hole drag and stuck pipe. The selection of the proper overpull is of critical importance. Failure to provide an adequate safety factor can result in loss or damage to the drill pipe, while an overly conservative choice will result in an unnecessarily heavy and more expensive drill string. The actual calculation of overpull is beyond the scope of this class. Overpull is an amount determined by the company man or is atypical to specific area. In crooked hole country 100,000 is commonly used. In less severe drilling areas 50,000 to 75,000 is common.

" Maximum Drill Pipe Length

The maximum drill pipe length is calculated for justification of drill pipe length. The drill pipe chosen for use in a drill string is based on the OD and what is available. It is necessary to find out what is available before doing this calculation. This calculation will help determine if the drill string will work within the customer’s well parameters. To calculate the maximum drill pipe length subtract the BHA weight from the maximum pull, then subtract the margin of overpull from that number. Divide the final number by the weight per foot of the drill pipe. MaxPull-BHA Weight-Overpull =Max DP Length DP Weight Per Foot

Example

If the company states to use an overpull of 75,000, the BHA weight is 13,500 pounds and the maximum pull from the last example is used what is the maximum drill pipe length? −

−

= _________

Compare the answer calculated here to page 11 in this chapter. Is the number larger or smaller? What does this tell you?

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Compare Results to Well Data

When the calculation is complete compare the number to the length of drill pipe needed. The value calculated for the maximum drill pipe length must be larger than the value calculated for the length of the drill pipe determined previously. If this is true the design of the drill string was successful. If this is not true, it is time do to some troubleshooting. For example, if the maximum drill pipe length calculated is 20,000 feet and the calculated length of drill pipe needed is 10,000 the maximum amount of weight (as determined by length) the string can hold is acceptable within the depth of the well. Now it can be determined that the drill pipe(and consequently, the drill string) is likely to be strong enough all the way to the target depth. The equipment chosen would be an acceptable choice in this situation.

Recap

This section covered the maximum pull and overpull associated with performing the calculations for verification. Using these figures we calculated the maximum drill pipe length.

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Troubleshooting Introduction

When the verification of drill pipe doesn’t provide sufficient strength it is necessary to troubleshoot. There are many troubleshooting techniques; strictly speaking there isn’t a particular method to begin with. There are proven methods that may help make a minor change instead of changing the entire drill string. The two methods recommended for novices are to reconfigure the BHA or substitute different drill pipe.

Quick Fixes

Drill String Length

If the drill string doesn’t provide enough length but has enough weight, substitute Hevi-Wate drill pipe for the drill collars. This will help when the drill string is not long enough, but allows the WOB to remain the same. BHA Weight

Change the BHA Length

©2008 SMITH International, Inc.

If the drill string reaches the required depth but is too heavy, recalculate the BHA accounting for bouyancy. Throughout this chapter the BHA weights calculated have assumed the BHA weight in the air. In reality the string will be downhole and in fluid which lessens the effect of the weight of the compoenents—this is called buoyancy. The buoyancy of a drill string is affected by the mud weight. A chart located in the Appendix shows the buoyancy factor as it is related to the mud weight.

BHA & Drill String Fundamentals Chapter 6 – Drill String Design

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"

Buoyancy is the weight of the drill string while it is being supported by the mud downhole.

Make Change

If these quick fixes don’t provide a solution, it’s time to recalculate the drill pipe grade, weight, or size. There may be other types of drill pipe available. For example, if a stronger string is necessary, then increase to a stronger grade of drill pipe. Then there is more weight and available maximum pull.

Advanced Troubleshooting

If the drill string is not strong enough to support the BHA and drill pipe to the target depth, it may be necessary to use multiple grades, weights, and/or classes of pipe. This could be due to a depleted or sporadic inventory or target depth. It’s important to calculate the strength of a multi-types (grade, weight, class, etc.) of pipe to ensure it works within the customers requirements. To optimize the performance of a drill string with two different types of pipe, first subtract the maximum pull of the weaker pipe from the maximum pull of the stronger pipe. Then, divide that number by the average weight of the stronger pipe. This will provide the minimum length of the stronger pipe, which will be run above the weaker pipe. MP#1-MP#2 = Minimum Length of Stronger Pipe Avg. Wt. of MP#1 In the next step, subtract the BHA length from the target depth, then subtract the answer from the first step. This will provide the length of the weaker pipe needed.

Target Depth - BHA Length - Min. Length of MP#1 = Required MP#2 Once both of the numbers have been calcuated, compare them. If the required amount of weaker drill pipe (MP#2) is less than the previously calculated maximum drill pipe length, the drill string will provide the optimum drill string performance.

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 6 – Drill String Design

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Exercise: Drill String Design

Well information has been provided for three locations. Answer the questions for each well following the steps covered in this chapter. Verify your answers. 1. Target Depth Hole Size Drill Collars Drill Pipe Overpull

10,000 feet 6 ¼" Twenty-One 4 ¾" OD x 2" ID 3 ½" 13.30 G-105 Premium 100,000 pounds

What bit size is needed? What is the OD of the overshot needed for this job? What is the weight per foot of the drill collar? What is the BHA length? What is the BHA weight? What is the length of drill pipe needed? Calculate the maximum drill pipe length. Will this drill string work within the parameters provided?

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 6 – Drill String Design

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Use this area to work the problem

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 6 – Drill String Design

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2. Target Depth Hole Size Drill Collars Overpull WOB

17,000 feet 6 ½" 4 ¾" OD x 2" ID 50#/ft 100,000 pounds 24,000 pounds

What bit size is needed? What is the OD of the overshot needed for this job? What connections are typically found on the described drill collar? What is the size, grade, weight, and connection size needed for the drill pipe string? What weight does the target BHA need to be to provide sufficient WOB? What is the length of the BHA that provides sufficient WOB? How many drill collars are required? What is the adjusted weight of the BHA, rounded up? What is the length of drill pipe needed? What size, grade, and weight of drill pipe have you chosen? Calculate the maximum drill pipe length for your string design. Will the drill string work within the parameters provided?

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 6 – Drill String Design

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Use this area to work the problem

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 6 – Drill String Design

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3. Target Depth Hole Size Drill Collars Hevi-Wate Drill Pipe Mud Weight Overpull WOB

12,000 feet 6 ½" 4 ¾" OD x 2" 50#/ft 3 ½" 13.30 G-105 Premium 3 ½ IF 100,000 pounds 24,000 pounds

What bit size is needed? What is the OD of the overshot needed for this job? What is the maximum OD of a component that can be fished? Calculate the target BHA weight. What is the BHA length? What is the actual BHA weight? What is the length of drill pipe needed? What is the maximum pull of the drill pipe used in this exercise? Will the drill string work within the parameters provided?

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 6 – Drill String Design

Page 22

Use this area to work the problem

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 6 – Drill String Design

Page 23

4. Target Depth Hole Size Drill Collars Overpull WOB

17,000 feet 7 ⅞" 6 ¼" OD x 2 ¾" ID 84#/ft 75,000 pounds 30,000 pounds

What bit size is needed? What is the OD of the overshot needed for this job? What is the maximum catch? What is the adjusted BHA weight and length? What is the length of drill pipe needed? Identify the best choice for drill pipe by size, weight, grade and class. What is the maximum pull of the drill pipe used in this exercise? Calculate the maximum pipe length. Will the drill string work within the parameters provided?

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 6 – Drill String Design

Page 24

Use this area to work the problem

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 6 – Drill String Design

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EXTRA CREDIT: Target Depth Hole Size Overpull WOB

22,000 feet 6 ⅛" 100,000 pounds 25,000 pounds

What bit size is needed? What is the OD of the overshot needed for this job? What is the maximum catch? What is the adjusted BHA weight and length? What is the length of drill pipe needed? Identify the best choice for drill pipe by size, weight, grade and class. What is the maximum pull of the drill pipe used in this design? Calculate the maximum pipe length. Will the drill string work within the parameters provided?

List the items in your proposed string.

Hint: Try to use a split string using two weights and sizes of drill pipe.

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 6 – Drill String Design

Page 26

Use this area to work the problem

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 6 – Drill String Design

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Use this area to work the problem

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 6 – Drill String Design

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Appendix

CHAPTER 7

APPENDIX

Topics

API Drill Pipe Data Sheet Hole Configuration Drill Collar Weight per Foot Hevi-Wate Drill Pipe Buoyancy Factor

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 7– Appendix

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©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 7– Appendix

Page 2

API Drill Pipe Data Sheet

Nominal Nominal Size Weight 2 ⅞"

3 ½"

3 ½"

4"

4 ½"

4 ½"

Approx. Weight Grade lb/ft

Min. Yield Strength

Typical Premium Class 2 Connection Max Pull Max Pull Size

10.40

OH 10.59 11.09 11.09 11.55

E-75 X-95 G-105 S-135

75,000 95,000 105,000 135,000

166,535 210,945 233,149 299,764

143,557 181,839 200,980 258,403

13.93 14.62 14.71 14.92

E-75 X-95 G-105 S-135

75,000 95,000 105,000 135,000

212,150 268,723 297,010 381,870

183,398 232,304 256,757 330,116

13.30

NC38(IF)

15.50

NC38(IF) 16.54 16.82 17.03 17.57

E-75 X-95 G-105 S-135

75,000 95,000 105,000 135,000

250,620 317,452 350,868 451,115

215,967 273,558 302,354 388,741

15.04 15.34 15.91 16.19

E-75 X-95 G-105 S-135

75,000 95,000 105,000 135,000

224,182 283,963 313,854 403,527

194,363 246,193 272,108 349,853

14.00

NC40(FH)

16.60

NC46(XH) 18.37 18.79 18.79 19.00

E-75 X-95 G-105 S-135

75,000 95,000 105,000 135,000

260,165 329,542 364,231 468,297

225,771 285,977 316,080 406,388

22.09 22.67 22.86 23.03

E-75 X-95 G-105 S-135

75,000 95,000 105,000 135,000

322,916 409,026 452,082 581,248

279,502 354,035 391,302 503,103

20.00

NC46(XH)

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BHA & Drill String Fundamentals Chapter 7– Appendix

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5"

5"

19.50

NC50(XH) 20.85 21.45 21.93 22.61

E-75 X-95 G-105 S-135

75,000 95,000 105,000 135,000

311,535 394,612 436,150 560,764

270,432 342,548 378,605 486,778

26.85 27.87 28.32 29.43

E-75 X-95 G-105 S-135

75,000 95,000 105,000 135,000

414,690 525,274 580,566 746,443

358,731 454,392 502,223 645,715

25.60

NC50(XH)

Information is from API RP7G Table 8 and Table 26. This is a guideline only, actual API documents should be referred to for actual dimensions.

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 7– Appendix

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Hole Configuration

API Casing Size & WT in 4 1/2

5

5 1/2

6 5/8

7

7 5/8 8 5/8

9 5/8

lbs 9.5/11.6 13.5 15.1 11.50-15 18 29.3-24.2 13-17 13-17 20 20 23-26 23-26 32 32 32 17-23-26 17-23-26 29-32 35 38 20-33.7 20-33.7 39 24-40 44-49 29.3-36 40-43.5 47 53.5

Overshot Recommended for Fishing

Bit Size 3 7/8 3 3/4 3 5/8 4 1/4 4 1/8 4- 3 7/8 4 3/4 4 3/4 4 5/8 4 5/8 4 1/2 4 1/2 5 3/8 5 3/8 5 3/8 5 3/8 6 1/4- 6 1/8 6 5 7/8 5 3/4 6 3/4- 6 5/8 6 3/4- 6 5/8 6 1/2- 6 3/8 7 7/8- 7 5/8 7 1/2- 7 3/8 8 3/4 8 5/8 8 1/2 8 3/8

OD 3 3/4 3 3/4 3 3/8 4 1/8 3 7/8 3 3/4 4 11/16 4 11/16 4 9/16 4 9/16 4 3/8 4 3/8 5 1/8 5 1/8 5 1/8 5 3/4 5 7/8 5 3/4 5 3/4 5 9/16 6 3/8 6 3/8 5 7/8 7 3/8 7 1/8 8 1/8 8 1/8 8 1/8 8 1/8

©2008 SMITH International, Inc.

Max Catch No. 3 1/16 37585 3 1/16 37585 2 1/2 C4623 3 1/8 8220 3 1/8 C1835 3 1/6 37585 3- 2 1/32 9109 3- 2 1/32 9109 3- 2 1/32 C5151 3- 2 1/32 C5151 3 3/8 9635 3 3/8 9635 4 1/4 4716 4 1/4 4716 4 1/4 4716 4 3/4 8975 5 C5171 4 3/4 8975 4 3/4 8975 4 1/4 5896 5 1/4 6655 5 1/4 6655 5 C5171 6 1/4 9692 6 C5196 7 9217 7 9217 7 9217 7 9217

Grapple 37590 37590 B5091 1741 B1837 37590 6662 6662 B4339 B4339 4195 4195 4674 4674 4674 6112 B4369 6112 6112 165 4498 4498 B4369 9687 B5201 9222 9222 9222 9222

Type SH SH SH FS SH SH FS FS SH SH FS FS SH SH SH FS SH FS FS FS SH SH SH SH SH FS FS FS FS

Drill Collars Recommended in Cased/Open Hole Min OD Max OD 2 7/8 3 1/16 2 7/8 3 1/16 2 1/4 2 1/2 3 3 1/8 3 3 1/8 2 7/8 3 1/16 3 1/4 3 1/2 3 1/4 3 1/2 3 1/4 3 1/2 3 1/4 3 1/2 3 3 1/4 3 3 1/4 3 1/2 4 1/8 3 1/2 4 1/8 3 1/2 4 1/8 4 4/7 4 3/4 4 9/16 5 4 9/16 4 3/4 4 1/4 4 1/2 4 1/8 4 1/4 4 9/16 5 1/4 4 9/16 5 1/4 4 9/16 5 6 6 1/4 5 1/2 6 6 7 6 7 6 7 6 7

BHA & Drill String Fundamentals Chapter 7– Appendix

Drill Pipe Recommended in Casing DP Size 2 7/8 PAC 2 7/8 PAC 2 3/8 WFJ 2 7/8 PAC 2 7/8 PAC 2 7/8 PAC 2 7/8 RFO 2 3/8 IF 2 7/8 PAC 2 7/8 RFO 2 3/8 IF 2 7/8 PAC 2 7/8 RFO 2 7/8 IF 3 1/2 IF 3 1/2 IF 3 1/2 IF 3 1/2 IF 2 7/8 IF 3 1/2 IF 4 FH 3 1/2 IF 4 1/2 XH 4 FH 4 1/2 XH, 5 XH 4 1/2 XH, 5 XH 4 1/2 XH, 5 XH 4 1/2 XH, 5 XH

TJ OD 3 1/8 3 1/8 2 1/2 3 1/8 3 1/8 3 1/8 3 7/8 3 1/2 3 1/8 3 7/8 3 3/8 3 1/8 3 7/8 4 1/8 4 1/8 4 3/4 4 3/4- 4 7/8 4 3/4 4 3/4 4 1/8 4 3/4- 4/78 5 1/4 4 3/4- 4 7/8 6 1/4 5 1/4 6 1/2- 6 5/8 6 1/2- 6 5/8 6 1/2- 6 5/8 6 1/2- 6 5/8

Page 5

Drill Collar Weight per Foot

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 7– Appendix

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Hevi-Wate Drill Pipe Tool Joint Nominal Connection Size Size (in.) 3 ½" 4" 4 ½" 5" 5 ½" 6 ⅝"

NC 38 (3 ½ IF) NC 40 (4 FH) NC 46 (4 IF) NC 50 (4 ½ IF) 5 ½ FH 6 5/8 FH

Approx. Weight [Including Tube Mechanical Makeup & Joints(lb)] Properties Torque Tensile Torsional (ft/lb) Yield Yield Wt/ft Wt/Jt (lb) (ft/lb)

OD (in.)

ID (in.)

4¾

2⅜

675,045

17,575

23.4

721

10,000

5¼

2 11/16

711,475

23,525

29.9

920

13,300

6¼

2⅞

1,024,500

38,800

41.1

1,265

21,800

6⅝

3 1/16

1,266,000

51,375

50.1

1,543

29,200

7 8

3½ 4⅝

1,349,365 1,490,495

53,080 73,215

57.8 71.3

1,770 2,193

32,800 45,800

©2008 SMITH International, Inc.

BHA & Drill String Fundamentals Chapter 7– Appendix

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Buoyancy Factor Mud Weight 8.4 8.6 8.8 9.0 9.2 9.4 9.6 9.8 10.0 10.2 10.4 10.6 10.8 11.0 11.2 11.4 11.6 11.8 12.0 12.2 12.4

©2008 SMITH International, Inc.

Buoyancy Factor .872 .869 .866 .862 .859 .856 .853 .850 .847 .844 .841 .838 .835 .832 .829 .826 .823 .820 .817 .814 .811

Mud Weight 12.6 12.8 13.0 13.2 13.4 13.6 13.8 14.0 14.5 15.0 15.5 16.0 16.5 17.0 17.5 18.0 18.5 19.0 19.5 20.0

Buoyancy Factor .807 .804 .801 .798 .795 .792 .789 .786 .778 .771 .763 .756 .748 .740 .733 .725 .717 .710 .702 .694

BHA & Drill String Fundamentals Chapter 7– Appendix

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