3 Drill String

7/23/2019 3 Drill String

1/43

CHAPTER THREE: DRILLSTRING


2/43

C O N T E N T S 1. Introduction ............................................................................................................ 1

2. Drill Pipe ............................................................................................................... 2

2.1. Drillpipe Stress and Failure............................................................................. 4

2.2. Drillpipe Inspection......................................................................................... 5

2.3. Drillpipe Classification ................................................................................... 8

2. ToolJoints .............................................................................................................. 8

3. Heavy Wall Drillpipe (HWDP) ........................................................................... 10

5. Drill Collars ......................................................................................................... 11

5.1. Special Types of Collar ................................................................................. 12

6. Other Drillstring Components ............................................................................. 13

7. Drill-String Design .............................................................................................. 16

7.1. Design of a Stabilised String ......................................................................... 16

7.2. Bending Moments in String Design .............................................................. 19

7.3. Drillstring Selection ...................................................................................... 19

7.3.1. Drillpipe Selection ................................................................................. 19

7.3.2. Drillcollar Weight and Length ............................................................... 21

7.4. Drillstring Design Criteria ............................................................................ 23

7.4.1. Collapse Load ........................................................................................ 24

7.4.2. Tension Load ......................................................................................... 25

7.4.3. Design Factor ......................................................................................... 27

7.4.4. Slip Crushing ......................................................................................... 27

7.4.5. Additional Design Variables .................................................................. 28

8. Appendix .............................................................................................................. 30

9. Calculations ......................................................................................................... 33


3/43

Soran University Drilling Engineering I

LEARNING OBJECTIVES:

Having worked through this chapter the student will be able to:

General

Describe the basic components and the function of each component in the

drillstring

Drill-pipe

Describe the components parts of a joint of drillpipe.

Describe the way in which drillpipe is classified in terms of size, weight and

grade

Describe the stresses and wear mechanisms to which the drillstring is exposed.

Describe the techniques used to inspect drillpipe and the worn pipe

classification system

Tool-joints

Describe a tooljoint and identify the major characteristics of a tooljoint.

HWDP

Describe the HWDP and the reasons for running HWDP

Drill-collars

Describe the reasons for using Drillcollars.

Describe the loads to which Drillcollars are subjected.

Describe the function of: conventional; Spiral; Square and Monel Drillcollars.

BHA Components:

Describe the function of: Stabilisers, Roller Reamers; Shock Subs; Subs andDrilling Jars

Describe the ways in which the above are configured in the BHA

Drill-string Design:

Calculate the dry weight and buoyant weight of the drillstring

Calculate the length of drillcollar required for a drilling operation

Calculate maximum drillable depth for a given grade and weight of drillpipe

Understand the effect of slip crushing on drillpipe design.


4/43


5/43

1


1. Introduction

The term drillstring is used to describe the tubular and accessories on which the drillbit is

run to the bottom of the borehole. The drillstring consists of drillpipe, drillcollars, the Kellyand various other pieces of equipment such as stabilisers and reamers, which are included

in the drillstring just above the drillbit (Figure 1). All of these components will be

described in detail below. The drillcollars and the other equipment which is made up just

above the bit are collectively called the Bottom Hole Assembly (BHA). The dimensions of

a typical 10,000 ft drillstring would be:

(Component)(Outside Diameter, in) (Length, ft)

Drillbit 12 1/4 Drillcollars 9 1/2 600

Drillpipe 5 9400

The functions of the drillstring are:

To suspend the bit

To transmit rotary torque from the kelly to the bit

To provide a conduit for circulating drilling fluid to the bit

It must be remembered that in deep wells the drillstring may be 5-6 miles long.

Figure 1: Components of the drillstring


6/43

The Drillstring T H R E E

2

2. Drill Pipe

Drillpipe is the major component of the drillstring. It generally constitutes 90-95% of the

entire length of the drillstring. Drillpipe is a seamless pipe with threaded connections,

known as tooljoints (Figure 2). At one end of the pipe there is the box, which has thefemale end of the connection. At the other end of each length of drillpipe is the male end of

the connection known as the pin. The wall thickness and therefore the outer diameter of the

tooljoint must be larger than the wall thickness of the main body of the drillpipe in order to

accommodate the threads of the connection. Hence the tooljoints are clearly visible in the

drillstring. Tooljoints will be discussed in greater depth below.

Figure 2: TooljointsEach length of drillpipe is known as a joint or a single . The standard dimensions for

drillpipe are specified by the American Petroleum Institute. Singles are available in three

API length ranges (see Table 1) with range 2 being the most common. The exact lengthof each single must be measured on the rig-site since the process used to manufacture the

drillpipe means that singles are not of uniform length. Since the only way in which the

driller knows the depth of the drillbit is by knowing the length of the drillstring, the length

of each length of drillpipe (and all other drillstring components) made up into the drillstring

must be measured and recorded on a drillpipe tally . The drillpipe is also manufactured in a

variety of outside iameters, and weights (Table 2) which assuming a specific gravity for

steel of 490 lb/cuft, is a reflection of the wall thickness of the drillpipe. The specification

for a particular string of drillpipe could therefore appear as:

5 19.5 lb/ft Grade S Range 2


7/43

3


API Range Length, ft

1 18-22

2 27-30

3 38-45

Table 1: Drillpipe Lengths

Size OD, in ID, in Weight (Ib/ft)

2 3/8 1.815 6.65

2 7/8 2.151 10.40

3 2.992 9.50

3 1/2 2.764 13.30

5 4.602 15.52

5 4.408 16.25

5 4.276 19.505 4.00 25.60

5 4.776 21.90

5 1/2 4.670 24.70

Table 2: Dimensions of Drillpipe

The drillpipe is also manufactured in a variety of material grades (Table 3). The grade of

drill pipe describes the minimum yield strength of the pipe. APIdefines five grades: D, E,

X, G and S. However, in oilwell drilling, only grades E,G and S areactually used. In most

drillstring designs, the pipe grade is increased if extra strength isrequired.

API Grade Minimum YieldStress (psi)

Minimum TensileStress (psi)

D or D-55 55,000 95,000 0.58

E or E-75 75,000 100,000 0.75

X or X-95 95,000 105,000 0.7

G or G-105 105,000 115,000 0.91

S or S-135 135,000 145,000 0.93

Table 3: Drillpipe Material Grades

All of these specifications will influence the burst, collapse, tensile and torsional strength of

the drillpipe and this allows the drilling engineer to select the pipe which will meet the

specific requirements of the particular drilling operation.

Care must be taken when using the specifications given in Table 2 since although these are

the normally quoted specifications for drillpipe, the weights and dimensions are nominal

values and do not reflect the true weight of the drillpipe or the minimum internal diameter

of the pipe.


8/43


4

2.1. Drillpipe Stress and Failure

It is not uncommon for the drillpipe to undergo tensile failure (twistoff) whilst drilling.

When this happens, drilling has to stop and the drillstring must be pulled from the borehole.

The part of the string below the point of failure will of course be left in the borehole whenthe upper part of the string is retrieved. The retrieval of the lower part of the string is a very

difficult and time consuming operation.

The failure of a drillstring can be due to excessively high stresses and/or corrosion.

Drillpipe is exposed to the following stresses:

Tension the weight of the suspended drillstring exposes each joint of drillpipe to

several thousand pounds of tensile load. Extra tension may be exerted due tooverpull (drag caused by difficult hole conditions e.g. dog legs) when pulling out of

hole.

Torque during drilling, rotation is transmitted down the string. Again, poor hole

conditions can increase the amount of torque or twisting force on each joint.

Cyclic Stress Fatigue in deviated holes, the wall of the pipe is exposed to

compressive and tensile forces at points of bending in the hole. As the string is

rotated each joint sustains a cycle of compressive and tensile forces (Figure 3). Thiscan result in fatigue in the wall of the pipe.

Stresses are also induced by vibration, abrasive friction and bouncing the bit off bottom.

F igure 3: Cyclic loading


9/43

5


Corrosion of a drillstring in a water based mud is primarily due to dissolved gases,

dissolved salts and acids in the wellbore, such as:

Oxygen present in all drilling fluids. It causes rusting and pitting. This may lead

to washouts (small eroded hole in the pipe) and twist offs (parting of the drillstring).

Oxygen can be removed from drilling fluids using a scavenger, such as sodium

sulphate. Even small concentrations of oxygen (< 1 ppm) can be very damaging.

Carbon dioxide can be introduced into the wellbore with the drilling fluid

(makeup water, organic drilling fluid additives or bacterial action on additives in the

drilling fluid) or from the formation. It forms carbonic acid which corrodes steel.

Dissolved Salts increase the rates of corrosion due to the increased conductivity

due to the presence of dissolved salts. Dissolved salts in drilling fluids may come

from the makeup water, formation fluid inflow, drilled formations, or drilling fluid

additives.

Hydrogen sulphide may be present in the formations being drilled. It causes

hydrogen embrittlement or sulphide stress cracking. Hydrogen is absorbed on

to the surface of steel in the presence of sulphide. If the local concentration of

hydrogen is sufficient, cracks can be formed, leading rapidly to a brittle failure.

Hydrogen embrittlement in itself does not cause a failure, but will accelerate failure

of the pipe if it is already under stress or notched. Only small amounts of H2S need

be present to induce fatigue (< 13 ppm). Special scavengers can be circulated in the

mud to remove the H2S (e.g. filming amines).

Organic acids These produce corrosion by lowering the pH, remove protective

films and provide hydrogen to increase hydrogen embrittlement.

Although added chemicals can build up a layer of protection against corrosion, the fatigue

stresses easily break this layer down, allowing corrosion to re-occur. It is this interaction of

fatigue and corrosion which is difficult to combat.

2.2. Drillpipe Inspection

When new pipe manufactured, they will be subjected to a series of mechanical tests by the

manufacturer such as; tensile and hydrostatic pressure tests in accordance with API

Specification 5A and 5AX. This will ensure that the pipe can withstand specified loads. A

joint of drillpipe will however be used in a number of wells. When it has been used it will

undergo some degree of wear and will not be able to withstand the same loads as when it isnew.


10/43


6

It is extremely difficult to predict the service life of a drillstring since no two boreholes

experience. However, as a rough guide, the length of hole drilled by a piece of drillpipe,

when part of a drillstring will be:

Soft drilling areas: 220000 - 250000 ft

Hard or deviated drilling areas: 180000 - 210000 ft

This means that a piece of drillpipe may be used on up to 25 wells which are 10,000ft deep.

During the working life of the drillpipe it will therefore be necessary to determine the

degree of damage or wear that the pipe has already been subjected to and therefore its

capacity to withstand the loads to which it will be exposed in the future. Various non-

destructive tests are periodically applied to use drillpipe, to assess the wear and therefore

strength of the pipe, and to inspect for any defects, e.g. cracks. The strength of the pipe is

gauged on the basis of the remaining wall thickness, or if worn eccentrically, the average

minimum wall thickness of the pipe. The methods used to inspect drillpipe are summarized

in Table 4.

Table 4: Summary of inspection techniques

Following inspection, the drillpipe is classified in terms of the degree of wear or damage

which is measured on the pipe. The criteria used for classifying the drillpipe on the basis of

the degree of wear or damage are shown in Table 5. The Grade 1 or Premium drillpipe

classification applies to new pipe, or used pipe with at least 80% of the original wall


11/43

7


thickness still remaining. A classification of Grade 2 and above indicates that the pipe has

sustained significant wear or damage and that its strength has been significantly reduced.

The strength of some typical drillpipe sizes when new and when worn is shown in tables 11

and 12.

Drillpipe will generally be inspected and classified before a new drilling contract is started.

The operating company would require that the drilling contractor provide proof of

inspection and classification of the drillstring as part of the drilling contract.

CLASSIFICATION OF USED DRILL PIPE AND USED TUBING WORK STRINGS

(All Sizes, Weights and Grades. Nominal dimension is basis for all calculations)

C o n d

i t i o n 1 2 3 4

Pipe condition Premium class Class 2 Class 3

E x

t e r

i o r

A) OD Wear Wall Remaining wall not lessthan 80%

Remaining wall notless than 65%

Remaining wallnot

less than 55%B) Dents & Marshes Not over 3% of OD Not over 4% of OD

C) Slip area dia.variations;

1- Crushing2- Necking Not over 3% of OD Not over 3% of OD

Not over 4% of OD Not over 4% of OD

D) Stress induced dia.variations;

1- Stretched

2- String Shot

Not over 3% of ODreduction

Not over 3% of ODincrease

Not over 4% of ODreduction

Not over 4% of OD

increase

E) Cuts, Gouges &Corrosion

1- Round Bottom

2- Sharp Bottom:Longitudinal

Transverse

Remaining wall not lessthan 80%


Remaining wall not lessthan 80% and length not

over 10%

Remaining wall knotlessthan 65%


Remaining wall not lessthan 65% and length

not over 10%F) Fatigue cracks None None None

I n t e r

i o r

A) Corrosive Piping Wall Remaining wall notless than 80%


A) Erosion & Wear Wall Remaining wall notless than 80%


B) Fatigue cracks None None None

Table 5: Classification of used drillpipe and used tubing work strings


12/43


8

2.3. Drillpipe Classification

Drill pipe, unlike other oilfield tubulars such as casing and tubing, is re-used and therefore

often worn when run. As a result the drill pipe is classified to account for the degree of

wear.

The API has established guidelines for pipe classification in API RP7G. A summary of the

classes follows:

New : No wear, has never been used.

Premium : Uniform wear and a minimum wall thickness of 80% of new pipe.

Class 2 : Drill pipe with a minimum wall thickness of 65% with all the wear on one

side so long as the cross sectional area is the same as the premium class.

Class 3: Drill pipe with a minimum wall thickness of 55% with all the wear on one

side

Drill pipe classification is an important factor in the design and use of drill pipe since the

degree of wear will affect the pipe properties and strengths. API RP7G provides a series of

tables which detail the strengths and properties of the various grades and classes of pipe as

shown in table 5.

2. ToolJoints

Tooljoints are located at each end of a length of drillpipe and provide the screw thread for

connecting the joints of pipe together (Figure 4). Notice that the only seal in the connection

is the shoulder/shoulder connection between the box and pin. Initially tool joints were

screwed on to the end of drillpipe, and then reinforced by welding. A later development

was to have shrunk-on tooljoints. This process involved heating the tool joint, then

screwing it on to the pipe. As the joint cooled it contracted and formed a very tight, close

seal. One advantage of this method was that a worn joint could be heated, removed and

replaced by a new joint. The modern method is to flash-weld the tooljoints onto the pipe. A

hard material is often welded onto the surface of the tooljoint to protect it from abrasive

wear as the drillstring is rotated in the borehole. This material can then be replaced at some

stage if it becomes depleted due to excessive wear. When two joints of pipe are being

connected the rig tongs must be engaged around the tooljoints (and not around the main

body of the drillpipe), whose greater wall thickness can sustain the torque required to


13/43

9


make-up the connection. The strength of a tool joint depends on the cross sectional area of

the box and pin. With continual use the threads of the pin and box become worn, and there

is a decrease in the tensile strength. The size of the tooljoint depends on the size of the

drillpipe but various sizes of tool joint are available. The tooljoints that are commonly used

for 4 1/2 drillpipe are listed in Table 6. It should be noted that the I.D. of the tooljoint is

less than the I.D. of the main body of the pipe.

F igure 4: Tool joint

Table 6: API tool joints


14/43


10

Tooljoint boxes usually have an 18 degree tapered shoulder, and pins have 35 degree

tapered shoulders. Tool joints are subjected to the same stresses as drillpipe, but also have

to face additional problems:

When pipe is being tripped out the hole the elevator supports the string weight

underneath the shoulder of the tool joint.

Frequent engagement of pins and boxes, if done harshly, can damage threads.

The threaded pin end of the pipe is often left exposed and is therefore exposed to

possible damage.

Tool joint life can be substantially extended if connections are greased properly when the

connection is made-up and a steady torque applied.

3. Heavy Wall Drillpipe (HWDP)

Heavy wall drillpipe (or heavy weight drillpipe) has a greater wall thickness than ordinary

drillpipe and is often used at the base of the drillpipe where stress concentration is greatest.

The stress concentration is due to:

The difference in cross section and therefore stiffness between the drillpipe anddrillcollars.

The rotation and cutting action of the bit can frequently result in a vertical bouncing

effect.

HWDP is used to absorb the stresses being transferred from the stiff drill collars to the

relatively flexible drillpipe. The major benefits of HWDP are:

1. Increased wall thickness

2. Longer tool joints

3. Uses more hard facing

4. May have a long central upset section (Figure 5)

HWDP should always be operated in compression. More lengths of HWDP are required to

maintain compression in highly deviated holes.


15/43

11


F igure 5 : Heavyweight drillpipe

5. Drill Collars

Drillcollars are tubulars which have a much larger outer diameter and generally smaller

inner diameter than drillpipe. A typical drillstring would consist of 9 O.D. x 2

13/16I.D.drillcollars and 5 O.D. x 4.276 I.D. drillpipe. The drillcol lars therefore have a

significantly thicker wall than drillpipe. The function of drill collars are:

To provide enough weight on bit for efficient drilling.

To keep the drillstring in tension, thereby reducing bending stresses and failures due

to fatigue.

To provide stiffness in the BHA for directional control.

Since the drillcollars have such a large wall thickness tooljoints are not necessary and the

connection threads can be machined directly onto the body of the collar. The weakest point

in the drillcollars is the connection and therefore the correct make up torque must be


16/43


12

applied to prevent failure. The external surface of a regular collar is round (slick), although

other profiles are available.

Drillcollars are normally supplied in Range 2 lengths (30 - 32 ft). The collars are

manufactured from chrome-molybdenum alloy, which is fully heat treated over the entire

length. The bore of the collar is accurately machined to ensure a smooth, balanced rotation.

Drill collars are produced in a large range of sizes with various types of joint connection.

It is very important that proper care is taken when handling drillcollars. The shoulders and

threads must be lubricated with the correct lubricant (containing 40-60% powdered

metallic-zinc or lead).

Like drillpipe, collars are subjected to stresses due to:

Buckling and bending forces

Tension

Vibrations

Alternate compression and tension.

5.1. Special Types of Collar

Square collars

These collars are usually 1/16 less than bit size, and are run to provide maximum

stabilization of the bottom hole assembly.Monel collars

These collars are made of a special non-magnetic steel alloy. Their purpose is to isolate

directional survey instruments from magnetic distortion due to the steel drillstring.

Anti-wall stickWhen drilling through certain formations the large diameter drillcollars can become stuck

against the borehole (differential sticking). This is likely to happen when the formation is

highly porous, a large overbalance of mud pressure is being used and the well is highly

deviated. One method of preventing this problem is to reduce the contact area of the collar

against the wellbore. Spiral grooves can be cut into the surface of the collar to reduce its

surface area (Figure 6).


17/43

13


Fi gure 6: Spiral drillcollar

6. Other Drillstring Components

6.1. Roller Reamer

A roller reamer consists of stabiliser blades with rollers embedded into surface of the blade.

The rollers may be made from high grade carburised steel or have tungsten carbide inserts

(Figure 7). The roller reamer acts as a stabiliser and is especially useful in maintaining

gauge hole. It will also ream out any potential hole problems (e.g. dog legs, key seats,

ledges).

F igur e 7: Roller reamers


18/43


14

6.2. Stabilisers

Stabilisers consist of a length of pipe with blades on the external surface. These blades may

be either straight or spiral and there are numerous designs of stabilisers (Figure 8). The

blades can either be fixed on to the body of the pipe, or mounted on a rubber sleeve (sleevestabilizer), which allows the drillstring to rotate within it.

The function of the stabilizer depends on the type of hole being drilled. In this section we

are concerned only with drilling vertical holes. Drilling deviated holes will be dealt with

later. In vertical holes the functions of stabilisers may be summarized as follows:

- Reduce buckling and bending stresses on drill collars

- Allow higher WOB since the string remains concentric even in compression.

- Increase bit life by reducing wobble (i.e. all three cones loaded equally)

- Help to prevent wall sticking.

- Act as a key seat wiper when placed at top of collars.

F igur e 8: Stabilisers

Generally, for a straight hole, the stabilisers are positioned as shown in Figure 9.Normally

the stabilisers used will have 3 blades, each having a contact angle of 140 degrees (open

design). When stabilisers begin to wear they become under gauge and are less efficient.

Stabilisers are usually replaced if they become 1/2 under gauge ( 3/16 under gauge may

be enough in some instances).


19/43

15


F igur e 9: Stabiliser positions for straight hole drilling

6.3. Subs (substitutes)

Subs are short joints of pipe which act as crossovers (i.e. connect components which cannot

otherwise be screwed together because of differences in thread type or size).

6.4. Drilling Jars

The purpose of these tools is to deliver a sharp blow to free the pipe if it becomes stuck in

the hole. Hydraulic jars are activated by a straight pull and give an upward blow.

Mechanical jars are preset at surface to operate when a given compression load is appliedand give a downward blow. Jars are usually positioned at the top of the drill collars.

6.5. Shock Sub (vibration dampener)

A shock sub is normally located above the bit to reduce the stress due to bouncing when the

bit is drilling through hard rock. The shock sub absorbs the vertical vibration either by

using a strong steel spring, or a resilient rubber element (Figure 10).


20/43


16

F igur e 10: Shock sub

7. Drill-String Design

There are four basic requirements which must be met when designing a drillstring:

1. The burst, collapse and tensile strength of the drillstring components must not be

exceeded

2. The bending stresses within the drill string must be minimized.3. The drillcollars must be able to provide all of the weight required for drilling.

4. The BHA must be stabilised to control the direction of the well.

7.1. Design of a Stabilised String

A drilling bit does not normally drill a vertical hole. This is partly due to the forces acting

on the string by sloping laminar formations. When the slope (or dip) of the beds is less than

45 degrees the bit tends to drill up-dip (perpendicular to the layers).If the dip is greater than

45 degrees it tends to drill parallel to the layers (see Figure11). In hard rock, where greater


21/43

17


WOB is applied, the resulting compression and bending of the drillstring may cause further

deviation. There are two techniques for controlling deviation.

F igur e 11: Drilling through dipping strata

Packed hole assembly (Figure 12) This is basically a stiff assembly, consisting of

reamers, drill collars and stabilisers. The purpose of this design is to align the bit

with the hole already drilled and minimize the rate of change in deviation.Pendulum assembly The first stabiliser of a pendulum assembly is placed some

distance behind the bit. The unsupported section of drill collar (Figure 12) swing to

the low side of the hole. A pendulum assembly will therefore tend to decrease the

angle of deviation of the hole and tend to produce a vertical hole. This will tend to

reduce deviation. The distance L from the bit up to the point of wal l contact is

important, since this determines the pendulum force. To increase this distance, a

stabiliser can be positioned some distance above the bit. If placed too high thecollars will sag against the hole and reduce the pendulum force.


22/43


18

F igur e 12: Pendulum effect The optimum position for the stabiliser is usually based on experience, although theoretical

calculations can be done. When changing the hole angle it must be done smoothly to avoid

dog legs (abrupt changes in hole angle). Some typical Bottom hole assemblies (BHA), for

different drilling conditions, are given in figure 13.

F igur e 13: Typical BHAs


23/43

19


7.2. Bending Moments in String Design

A useful parameter when considering bending of the drillstring is the:

Field results have shown that if the ratio of section modulus between various string

components is kept below 5.5 the failure rate is reduced. The section modulus ratio for a

variety of drillpipe sizes is given in Table 8. In larger holes, or more severe drilling

conditions, the ratio should be kept below 3.5 (Table 13). Essentially these guidelines will

eliminate abrupt changes in cross sectional area throughout the drillstring.

Table 8: I/C Data for drillstring components

7.3. Drillstring Selection

7.3.1. Drillpipe Selection

The drillpipe is to provide a fluid conduit for pumping drilling mud, imparting rotary

motion to the bit and for drill stem testing and squeeze cementing. Basic factors for

consideration in drill string design includes: collapse, tension, dogleg severity and slip

crushing. Collapse together with tension primarily applies to weight selection, grades and

couplings. High-strength pipe is required in the lower sections of the drillstring for collapse

resistance. Tension is considered to dictate the higher strength at the top of the well.

Classes are given to drill pipe to account for its weight, grade and class.


24/43


20

The weight per foot of the pipe is a function of the connection type and grade of the

drillpipe.

The weight per foot that should be used when calculating the true weight of a string of pipe

is given in table 9.The weight of the pipe calculated in the manner described above will

reflect the weight of the drillpipe when suspended in air ( Weight in air ). When the pipe

is suspended in the borehole it will be immersed in drilling fluid of a particular density and

will therefore be subjected to a buoyant force. This buoyant force will be directly

proportional to the density of the drilling fluid. The weight of drillpipe when suspended in a

fluid ( Wet Weight ) can be calculated from the following:

Buoyant Weight (Wet Weight) of Drillpipe = Weight of pipe in Air x Buoyancy Factor

Table 9: Specifications of Various Sizes of Drillpipe

Example 1// Dimensions and Weight of Drillpipe

a) What is the weight in air of a joint (30 ft) of 5 19.5 lb/ft Grade G drillpipe with 41/2?

b) What is the wet weight of this joint of drillpipe when immersed in a drilling fluidwith a density of 12 ppg?


25/43

21


7.3.2. Drillcollar Weight and Length

The sizes and weight per foot of a range of drillcollar sizes are shown in table 10. The

weights that are quoted in table 10 are the weight in air of the drillcollars.

Table 10: Drillcollar Weights

Example 2// Drillcollar Dimensions and Weights

A) What is the weight in air of 200 ft of 9 1/2 x 2 13/16 drillcollar?

B) What is the weight of this drillcollar when immersed in 13 ppg mud?


26/43


22

The length of drillcollars, L that are required for a particular drilling situation depends on

the Weight on Bit, WOB that is required to optimize the rate of penetration of the bit and

the buoyant weight per foot, w of the drillcollars to be used, and can be calculated from the

following:

....1

For directional well:

.2 Where = well inclination

If the drillpipe is to remain in tension throughout the drilling process, drillcollars will have

to be added to the bottom of the drillstring. The buoyant weight of these additional

drillcollars must exceed the buoyant force on the drillpipe.

This will be sufficient to ensure that when the entire weight of the drillcollars is allowed to

rest on the bit, then the optimum weight on bit will be applied. The WOB will however

vary as the formation below the bit is drilled away, and therefore the length of the

drillcollars is generally increased by an additional 15%. Hence the length of drillcollars will

be 1.15 L.

Example 3//Length of Drillcollars for a Given WOBYou have been advised that the highest rate of penetration for a particular 12 1/4 bit will

be achieved when 25,000lbs weight on bit (WOB) is applied to the bit. Assuming that you

are drilling a vertical well and that the bit will be run in 12 ppg mud, calculate the length of

drillcollars required providing 25,000 lbs WOB.

Calculate the weight (in air) of 10000 ft of 5 19.5 lb/ft Grade G drillpipe with4

1/2 IF connections.

Calculate the weight of this string in 12 ppg mud.

Calculate the length of 9 1/2 x 2 13/16 drillcollars that would be required to

provide 25,000lbs WOB and keep the drillpipe in tension in 12 ppg mud.


27/43

23


7.4. Drillstring Design Criteria

When drilling highly deviated, extended reach or horizontal wells, computer modeling of

torque and drag should be used for establishing grades, size and weight of drill and

coupling to be used. On such wells, calculation of the effects of deviation on predictedtorque and drag are too complicated to calculate manually.

The criteria used in a drill string design are:

1. Collapse Load

2. Tension Load

Burst pressure is not considered in drillstring design due to the fact that burst loads and

backup loads are provided by the same fluid in the well. Therefore under normal

circumstances there are no effective burst loads, except during squeeze operations where

surface pressure is applied. If squeeze pressures are high, a back-up annulus pressure would

normally be applied to reduce the effective burst pressure.

Collapse and tension considerations are used to select the pipe weights, grades and

couplings. Slip crushing affects the tension design and pipe selection. Dogleg analysis is

performed to study the fatigue damage resulting from rotation in doglegs. Doglegs analysis

may not affect the selection of the pipe, however it will assist in determining the maximum

permissible dogleg during any section of the well.

API R7G gives the following design criteria:

1. Anticipated total depth with this drillstring

2. Hole size

3. Expected mud weight

4. Desired safety factor in tension and/or margin of overpull

5. Desired safety factor in collapse

6. Length of drillcollars, OD, ID and weight per foot

7. Desired drillpipe sizes and inspection class


28/43


24

F igur e 14 : Axial load on the drillstring

7.4.1. Collapse Load

The criteria to be used as a worst case for the collapse design of drill pipe are typically a

DST. The maximum collapse pressure should be determined for an evacuated string, with

mud hydrostatic pressure acting on the outside of the DP. Use of this criterion also accounts

for incidence of a plugged bit or failure to fill the string when a float is used during trips

into the hole.

A design factor is used in constructing the collapse design line. The design factor to be used

for this full evacuation scenario is 1.0.

Collapse calculation

1. Drill Stem Testing (DST)

The collapse pressure can be calculated when the string is partially empty, with different

uid density inside than outside, using the following equation:

3 Where:

Pc = collapse pressure (psi)

Y = depth to fluid inside drillpipe

L = total depth of well (ft)

1= fluid density outside the drillpipe (ppg)

2= fluid density inside the drillpipe (ppg)


29/43

25


The drillpipe is completely empty, Y = 0, 2= 0, then it becomes:

........4

When the fluid density inside drillpipe is the same as that outside drillpipe, i.e. 1 = 2 = ,

then it becomes:

5

2. Design factor

.6 The valve of 1.125 is normally used for DF in collapse.

7.4.2. Tension Load

The tensile resistance of drill pipe is usually de-rated by a design factor. The tension

loading can be calculated from the known weights of the drill collars and drill pipe below

the point of interest. The effect of buoyancy on the drill string weight, and therefore the

tension, must also be considered. Buoyancy forces are exerted on exposed horizontal

surfaces and may act upwards or downwards. These exposed surfaces occur where there is

a change in cross-sectional area between different sections.

The tension design is established by consideration of the following:

Tensile Forces: These include:- weight carried

- shock loading

- bending forces

Design factor

Slip Crushing Design

Tensile Forcesa) Weight Carried

The greatest tension (P) on the drillstring occurs at the top joint at the maximum drilled

depth, see Figure 15. This is given by:

. 7


30/43


26

Where:

= length of drillpipe per foot

= weight of drillpipe per unit length

= weight of drillcollars

= weight of drillcollars per unit length

BF = buoyancy factor

Figure 15: TensionNote: P is the total weight of the submerged drillstring. It is highly dependent on mud

weight. The higher the mud weight the less weight seen at surface on the Martin Decker

weight indicator. The influence of mud weight is shown through the term BF: buoyancy

factor.

The drillstring should not be designed to its maximum yield strength to prevent the

drillpipe from yielding and deforming. At yield, the drillpipe will have:

- deformation made up of elastic and plastic (permanent) deformation

- permanent elongation

- permanent bend and it may be difficult to keep it straight

To prevent this, API recommends that the use of maximum allowable design load (Pa),

given by:

.8 Where:

= Max. Allowable design load in tension, lb

= theoretical yield strength from API tables 3, lb0.9 = a constant relating proportional limit to yield strength

From the above equation number 7 & 8 can obtain:

.9 10

Where:

MOP = Margin of overpull, lb

DF = Design factor, dimensionless


31/43

27


The Margin of Overpull is the minimum tension force above expected working load to

account for any drag or stuck pipe. The MOP used is usually of the order of 100,000 lbs.

When deciding on the magnitude of the MOP or DF, the following should be considered:

Overall drilling conditions Hole drag

Likelihood of getting stuck

Re-arranging equations 7, 8 & 9 gives the maximum length of pipe (Maximum Hole

Depth) which can be used from a given grade/weight of drillpipe:

11 b) Shock Loading

The additional tensile force generated by shock loading is given by:

..12 Where = weight of drillpipe per unit length, lb/ft

c) Bending

The additional tensile force generated by bending is given by:

..13 Where

= dog-leg severity in /100 ftD = outside diameter of pipe in inches

7.4.3. Design Factor

A design factor of 1.6 should be applied to the tension loads calculated above if shock

loading is not accounted for. If the shock loading is quantified and included in the load

calculation, a design factor of 1.3 can be used.

7.4.4. Slip CrushingThe maximum allowable tension load must also be designed to prevent slip crushing of the

pipe. Reinhold and Spini 6 proposed an equation to calculate the relationship between the

hoop stress caused by the action of the slips and the tensile stress in the pipe resulting from

the load of the pipe hanging in the slips. The equations used are as follows:

.. .14

Where:

TS =Tension load due to slip crushing

TL =Static load tension


32/43


28

SH/ST = Hoop stress to tension stress ratio as derived from the equation

below:

...15

Where:

SH =Hoop stress (psi)

ST =Tensile stress (psi)

D =OD of the pipe (in)

K =Later load factor on slips (1/tan (y + z))

y =Slip taper (typically 9.4625 degrees)

z =Arctan

=Coefficient of friction, typically 0.08 - 0.25

Ls =Length of slips, usually 12 - 16 in

When all tension loads are calculated, the pipe grade selected in the collapse calculation

can be assessed and modified for the tension requirements. It is usually preferable to

increase the grade rather than the weight, as increasing weight usually has negative effects

in terms of smaller clearance and high pressure drop.

Couplings are then selected based on the tension design. For highly deviated well or

horizontal wells torque and drag modeling is performed to evaluate tension strength

requirements of the pipe and couplings and the computed torque is used for determining

coupling requirements.

7.4.5. Additional Design Variables

Torsion

The drillpipe torsional strength, when subjected to pure torsion is given by:

..16 Where:

Q = minimum torsional yield strength (lb-ft)

Ym= minimum unit yield strength (psi)

J = polar moment of yield inertia = = 0.098175 * D = outside diameter (in)

d = inside diameter (in)


33/43

29


When drillpipe is subjected to both torsion and tension, as is the case during drilling

operations, equation 16 becomes:

17

Where:

QT = minimum torsional yield strength under tension (lb-ft)

A = cross-sectional area (in2)

P = weight carried, (lb)

Pipe Stretch of Submerged Drillstring

e1 = stretch due to weight carried (i.e. weight of drillcollars)

..18 e2 = stretch due to suspended weight of drillpipe

.19 Where:

P = load carried in lbf

L = length of drillpipe

= mud density in ppg


34/43


30

8. Appendix

Table 11 : Ratings for New and Premium Class Drillpipe


35/43

31


F igur e 12: Ratings for Class 2 Used Drillpipe


36/43


32

F igur e 13 : Drillpipe/Drillcollar Combinations


37/43

33


9. Calculations

Example 1// Dimensions and weight of drillpipe

a) The weight (in air) of 30 ft, of 5 19.5lb/ft Grade G drillpipe with 4 1/2

connections:

19.5 lb/ft (Approx. wt.) x 30 ft

= 585 lbs

b) The weight of this string in 12 ppg mud:

585 lbs x 0.817 (buoyancy factor)

= 578 lbs

Example 2// Drillcollar dimensions and weights

a) The weight (in air) of 200 ft of 9 1/2 x 2 13/16 drillcollaris:

220.4 lb/ft (Approx. wt.) x 200ft

= 44080 lbs


44080 lbs x 0.801(buoyancy factor)

= 35308 lbs

Example 3// Length of Drillcollars for a given WOB

a) The weight (in air) of 10,000 ft of 5 19.5 lb/ft Grade G drillpipe with 4 1/2 IFconnections:

21.5 lb/ft (Approx. wt.) x 10,000 ft

= 215,000 lbs


215,000 lbs x 0.817 (buoyancy factor)

= 175,655 lbs

c) The length of 9 1/2 x 2 13/16 drillcollars that would be required to provide 25,000lbs WOB in 12 ppg mud:

An additional length of drillcollars is required to ensure that the drillpipe is in tension when

drilling. This additional length of collars will be required to overcome the buoyant force on

the drillpipe and from the above will be equal to:


38/43


34

With an additional 15% length of drillcollar the total length of collar will be:

(139 x 1.15) + 219 = 379 ft

Example 4// Tension design with a single drillpipe

A drill string consists of 600 ft of 8 in x 2 13/16 in drillcollars and the rest is a 5 in

drillpipe, 19.5 lbm/ft Grade X 95 drillpipe. If the required MOP is 100,000 lb and mud

weight is 10 ppg, calculate the maximum depth of hole that can be drilled when (a) using

new drillpipe (Pt = 501,090 lb) (b) using Class 2 drillpipe having a yield strength (Pt) of

394,000 lb.

Solution

a) For new drillpipe (Pt = 501,090 lb), from using equation 11:

Wight of the 8 in x 2.13/16 in drillcollars can be found from Table 10, which is equal to

161.3 Ibm/ft.

Buoyancy factor, BF could be calculated as follow;

16,287 ftThe maximum hole depth that can be drilled with a new drillpipe of Grade X 95 under the

given loading condition is

= length of drillpipe + length of drillcollars

= 16,287 + 600 = 16,887 ft

b) For class 2 drillpipe (Pt = 394,000 Ib), from using equation 11:

10,452 ft

Maximum hole depth = 10,452 + 600 = 11,052 ft


39/43

35


Example 5// Drill Pipe Design Using Pressure-Area Method

Well Data:

Hole size =12 "

Bit Depth =11,000 ft

Collar length =500 ft

Drill Pipe (premium) =5" OD 4.276" ID (Available Grade X-95)

Drill Collars =8" OD 3.0" ID

Overpull =100,000 lbs

Mud Weight =11.5 ppg

DST packer depth =10,700 ft

Length of Slips =16"

Maximum anticipated surface pressure = 5000 psi

Design Factors:

Tension = 1.3 - 1.6

Collapse = 1.0

Burst = 1.1

Solution

A graphical method will be used to select drillpipe grade/weight:

1. Construct the collapse load line by calculating the maximum collapse pressure at the

bottom of the drill pipe, using equation 5.

Collapse load at 10,700 ft = 0.052 x 10,700 ft x 11.5 ppg = 6399 psi

The design factor for collapse is 1.0. The design load is the calculated load

multiplied by the design factor. In this case the design load is also 6399 psi .

2. Plot the load and design lines graphically (see Figure 16) and select an appropriate pipe grade using API tables of pipe collapse resistance data.

3. Check the burst rating of the pipe grade chosen against the maximum anticipated

applied surface pressure. Plot burst load and burst design (see Figure 16)

In this instance the maximum applied surface pressure will be 5000 psi. Use of a design

factor of 1.1 gives a design load of 5500 psi.


40/43


36

F igur e 16: collapse and burst design loads

4. Calculate the tension load line using the following steps and plot graphically (figure

17).

i. Calculate the buoyancy force (BF1) acting on the bottom of the drill collars

using:

BF1 = - (P x A)

= - (0.052 x 11,000 x 11.5) x (( /4) x (82 - 3

2))

= - (6,578 psi) x (43.197 in2)

= - 284,149 lb

ii. Calculate the buoyancy force (BF2) acting at the top of the drillcollars.

BF2 = (P x A)

= (0.052 x 10,500 x 11.5) x [/4 (8 2 - 5 2) + /4 (4.276 2 -32)]

= (6,279) x (30.631 + 7.292)

= + 238,119 lb iii. Calculate the drill collar weight

DC Weight = 150 x 500 ft = + 75,000 lbs

iv. Calculate the drill pipe weight

DP Weight =19.5 x 10,500 = + 204,750 lb

v. Calculate the shock load

Shock load = 1500 x pipe weight per foot

= 1500 x19.5 lb/ft

= 29,250 lb


41/43

37


vi. Now calculate the total dynamic load at surface

Total dynamic load = - 284,149 (BF1) + 238,119 (BF2) + 75,000

(drillcollar weight) + 204,750 (drill pipe weight) + 29,250 (shock

load)

Total dynamic surface load = + 262,970 lbs

Note: static load at surface = 233,720 lbi.e. Without shock load

Static load at top of drillcollars = -284,149 + 75,000 (DC weight in air)

= -209,149 lb

Static load at bottom of drillpipe = 238,119 (BF2) + (-209,149) = 28,970 lb

Dynamic load at bottom of drillpipe = 28,970 + 29,250 = + 58,220 lb

Plot the static and dynamic load as shown in figure 16.

5. Calculate the design line for the tension load by multiplying the load on the drill

pipe at surface and at the top of the collars by the 1.3 design factor (since shock

loads have been included) and plot as in figure 17 .

F igur e 17: static and dynamic loads

6. Calculate the design line for the MOP by adding the 100,000 lb overpull factor to

the static tension load values calculated earlier and plot as in figure 18.

7. Calculate the design line for slip crushing using equation (14):


42/43


38

K = (1/tan (y + z))

y = 9.4625 degrees

z = Arctan

Arctan 0.08 = 0.0798

Ls = Length of slips, usually = 16 in

TL = static tension at surface = 233,720 lb

Therefore at the top of the well where the static tension load (i.e. excluding drag) is

233,720 lb. The slip crushing load:

TS =T L (SH/ST)

=233,720 X 1.42=331,882 lb

The slip crushing value is then recalculated at the bottom of drillpipe (28,970 x 1.42) and

the slip crushing design line plotted through the two points as shown in figure 18.

F igur e 18: complete tension design


43/43


8. The tensile rating of the pipe in lb is computed from the cross sectional area of the

pipe and the yield strength as follows:

Drillpipe area = ( /4) (5 2 - 4.276 2) =5.281 sq. in

Tensile strength = area x yield strength =5.281 x 95000 psi=501,695 lb

9. Calculate the tension design factors (TDF) at surface:

Example 6// Pipe Stretch

A 3.5 drillpipe, 13.3 lbm/ft. Grade S135 premium class, is used to run a 4.5 OD liner to21,000 ft. If the length of drillpipe is 17,500 ft, the mud weight is 16 ppg and the totalweight of the liner is 50,000 lb, calculate the total stretch in the drillpipe.

Solution:

e1 = stretch due to weight carried:

e2 = stretch due to suspended weight of drillpipe

Total Stretch = e1+ e2 = 89.5 +134.9 = 224.4 in

Documents

3 Drill String