Drill String Components

7/24/2019 Drill String Components

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Drill String ComponentsDesign ConsiderationsDesign

As the drill string moves downhole, it is subjected to a variety of stresses, includingtension, compression, vibration, torsion, friction, formation pressure and circulating

fluid pressure. It is also exposed to abrasive solids and corrosive fluids.

The drill string not only must be sturdy enough to withstand this hostile

environment, but it must be lightweight and manageable enough to be efficientlyhandled within the limits of the rigs hoisting system. At the same time, it must!

provide weight to the bit;

allow control over wellbore deviation;

help ensure that the hole stays "in gauge".

Drilling rates tend to increase with increasing weight on bit although this statement is anoversimplification, it is valid within certain limits. The drill string is the source of this applied bitweight. Drill string design depends largely on the amount of bit weight that is desirable andpractical for a given situation.

Drilling engineers have long observed that there is no such thing as a perfectly

straight or vertical hole. "ormation characteristics, along with the rotary drilling

process itself, cause wells to #drill croo$ed,# ma$ing a certain amount of wellboredeviation inevitable. A major consideration in drill string design is to control the

amount and direction of this deviation, either to stay as close to vertical as possibleor to direct the well along a programmed directional or hori%ontal course.

&roper drill string design is also important in avoiding doglegs 'abrupt changes inhole angle( and key seats 'slots worn into the side of the borehole by the drill

string(. These conditions can lead not only to stuc$ pipe and possible fishing jobs,but to difficulty in running casing and even to future production problems.

)it gauge wear, sloughing formations or heaving shales may result in a hole diameterthat is considerably less than the nominal diameter of the bit. This undergauge

condition can lead to such problems as stuc$ pipe and an inability to run casing.*election of the right drill string tools can alleviate this condition and help produce a

smooth bore, full+si%e, problem+free hole.

Components

The length and ma$eup of the drill string depends on such factors as well depth, holesi%e, operating parameters and directional considerations. Its major components are

the kelly ( or top-drive unit ), drill pipe and bottomhole assembly ' "igure (.
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Figure 1

A $elly is a s-uare or hexagonal length of pipe that fits into a bushing in the rigs

rotary table. As the rotary table turns to the right, the $elly turns with it.

The main function of a $elly is to transfer energy from the rotary table to the rest ofthe drill string. n modern rigs, this function is more commonly performed by a top

drive unit, power swivel or power sub located directly below a conventional swivel. f

course, when a downhole mud motor is used for directional or other applications,there is normally no drill string rotation.

The longest portion of the drill string consists of connected lengths of drill pipe. The

primary purposes of drill pipe are to provide length to the drill string and transmitrotational energy from the $elly to the bottomhole assembly and the drill bit. Drillpipe also serves as a conduit for the drilling fluid.

The bottomhole assembly is that portion of the drill string between the drill pipe andthe drill bit. Its individual components may be arranged in any number of ways to

promote drilling objectives, and can include!


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drill collars,which provide weight and stability to the drill bit, maintain tension on the drill

pipe and help keep the hole on a straight course;

heavy wall drill pipe, which serves as an intermediate+weight drill string

member between the drill pipe and the much heavier drill collars, thereby

reducing fatigue failures, providing additional hole stability and aiding in

directional control/

stabilizers, which centrali%e the drill collars, help maintain the hole at full+

gauge diameter and aid in directional control/

jars, which can provide sharp upward or downward impact to free stuc$

pipe/

rotary reamers, which help maintain a full+gauge hole diameter/

crossover subs, which join components having different types of

connections.

Some bottomhole assemblies may also include vibration dampeners, or shock subs which, undercertain conditions, can help absorb shock loads and vibrations that might otherwise contribute todrill string failure.

A well+designed bottomhole assembly helps maximi%e drilling rates, produce asmooth, full+si%e borehole, prevent drill pipe failure, maintain directional control,

avoid drilling problems, and prevent future completion and production problems.

0elly

The Kelly

The $elly is a primary lin$ between the drilling rigs surface e-uipment and the bit,and is therefore a critical component of the rotary system. Although top drive

systems have replaced $elly1rotary table combinations on many rigs, some$nowledge of their manufacture and operation is useful.

0ellys are manufactured with either s-uare or hexagonal cross sections ' "igure (.
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Figure 1

Their angled surfaces, or drive flats, are designed to fit into a drive roller assembly

on the $elly bushing, so that as the rotary table turns to the right, the $elly turnswith it. To allow for normal right+hand rotation of the drill string, $ellys have right+

hand threads on their bottom connections and left+hand threads on their topconnections

API Standards

The American &etroleum Institute has established manufacturing and design

standards for $ellys, and has included them in A&I 2& 34, Recommended ractice for!rill "tem !esign and #perating $imits.

A&I $ellys come in two standard lengths!

. 56 ft overall, with a 73 ft wor$ing space/

8. 95 ft overall, with a 9 ft wor$ing space.

Performance Considerations


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The ability of a $elly to turn the drill string depends on how well it fits into the $ellybushing. :ore specifically, it depends on the clearance between the drive flat

surfaces and the rollers in the $elly bushing. "or the $elly to perform properly, thisclearance needs to be $ept to a minimum.

0ellys most commonly wear out due to a rounding+off of the drive corners, as shown

in "igure 'new kelly with new drive assembly( and "igure 8'worn kelly with worndrive assembly( .

Figure 1

This rounding is a natural wear process caused by the compressive force of the

rollers on the drive flats and accelerated by rotary tor-ue.
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Figure 2

As rounding progresses, it further accelerates the wear process by increasing the

clearance and the contact angle between the drive flats and the rollers.

"or minimal rounding, there must be a close fit between the $elly and the roller

assembly, with the rollers fitting the largest spot on the $elly flats. :anufacturingtechni-ues and rig operating practices play important roles in determining this fit.

)oth s-uare and hexagonal $ellys are manufactured either from bars with an #as+forged# drive section, or from bars with fully+machined drive sections. ;hile forged

$ellys are cheaper to manufacture, machined $ellys offer the following features,which tend to result in longer useful life!

achined kellys, unlike forged kellys, are not sub!ect to the metallurgical process of

decarburiation, or decarb. Decarburiation leaves a relatively soft layer of material#appro$imately %&'" thick( on the drive surface that can accelerate the rounding processand increase the potential for fatigue cracks;

:achined $ellys, because they are made to closer tolerances than forged

$ellys, are more li$ely to closely fit the roller assembly throughout theirlength.


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) s*uare drive section normally tolerates a greater clearance between flats and rollers than doesa he$agonal drive section.

To minimi%e rounding, rig personnel should follow these guidelines ')rinegar,


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p to a certain point, a worn $elly can be repaired either by reversing the ends, '

"igure 7 ( or by remachining it to a smaller si%e.

Figure 3

Auxiliary Equipment

% kelly saver sub should always be run between the $elly and the top joint of drillpipe. This protects the $ellys lower connection threads from wear, as joints of drill

pipe are continually made up and bro$en out. A saver sub is much less expensive

and much easier to replace than the $elly itself, and it can also be e-uipped with a

rubber protector to help $eep the $elly centrali%ed and to protect the top joint ofcasing against wear.

A kelly cockis a valve installed above or below the $elly, which prevents fluid fromescaping through the drill string if the well should begin to flow or #$ic$.# As an extra

well control precaution, an upper $elly coc$ 'having left+hand threads( should beinstalled directly above the $elly, while a lower $elly coc$ 'having right+hand threads(

should be installed below the $elly. Installing two $elly coc$s ensures that at leastone of them is always accessible, regardless of the $ellys position.
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Automatic chec$ valves, designed to close when the mud pumps are shut off, arealso available, and can be installed below the $elly to prevent mud from spilling onto

the rig floor during connections.

Drill &ipeDimensions and Strengths

=i$e other oilfield tubulars, drill pipe comes in a variety of lengths, outside diameters,weights and grades of steel. Drill pipe is also specified according to its upset 'i.e., the

type of end section that is provided for weld+on connections or tool joints(.

?ole si%e, well depth, casing and cementing re-uirements, subsurface pressures,

circulating system and drilling mud parameters, hoisting capacity, pipe availabilityand contract provisions are among the factors that influence drill pipe selection.

The American &etroleum Institute has established standards for drill pipemanufacturing practices, dimensions, strengths and performance properties. These

standards appear in the following publications!

)/0 Spec 1D, Specification for Drill /ipe;

B A&I )ul 9C8, )ulletin on &erformance &roperties of Casing, Tubing and Drill&ipe/

B A&I 2& 34, 2ecommended &ractice for Drill *tem Design perating =imits.

)/0+standard drill pipe is available in three length ranges2 3ange &4+55 ft(, 3ange 5 #56+78 ft(

and 3ange 7 #74+91 ft(. 3ange 5 is the length most commonly used, making the "average" lengthof a drill pipe !oint about 78 feet.

Table 1., below, lists outside diameters and nominal weights for A&I standard drillpipe. ote that these diameters and weights apply only to the drill pipe tube+in

drilling operations, the engineer also must account for the weight and diameter of

the tool joints and upsets. This information is available in A&I *pec *D and A&I 2&34.

Outside diameter, inches Nominal weights, lb/ft*

5 6:4 &8.987 &:5 .18 &7.78 &1.18

9 &9.88

9 &:5 &7.61 &'.'8 58.88

1 &'.51 &.18 51.'8

1 &:5 5&.8 59.68

' 1:4 51.58 56.68
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Table 1. Diameters and nominal eights o! API"standard drill pipe.

There are four standards for measuring drill pipe strength!

torsional yield strength, a measure of the pipe


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Figure 1

"igure 8 ,


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Figure 2

and "igure 7 'group &(,


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Figure 3

and"igure 5 , "igure 9
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Figure 5

, and "igure


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Figure

'group '((.


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Figure !

0n an internal upset!oint, e$tra wall thickness is added by decreasing the pipe


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Torsional yield strength is an important consideration in tool joint design, withrespect to both tool joint ma$e up and the rotational forces encountered while

drilling. Tool joint performance specifications therefore include information ontorsional yield strength and on recommended ma$eup tor-ue. &roper ma$e+up

tor-ue is a function of tool joint type, si%e, outside diameter, inside diameter andcondition.

API Standards

%* R +lists standards for various tool joint types used for the different drill pipe

upsets, including!

E *nternal flush (*) includes C8,F C7, C7G, C5 and C96

connections/

E ull hole (/) includes C56 connections/

0 #pen hole (#/)1

E "lim hole ("/) includes C8, C7 and C7G connections/

E "lim line ("$) ?+


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Figure 1

Table 1. , below, illustrates the differences between some of these basic tool joint

types for the case of 5 #, .6 lb1ft, new 4rade


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Identi!i$ation

An examination of the tool joint connections listed above, indicates that some ofthem are identical1 "or example, the C 8 connection applies to both Internal "lush

and slim hole upsets. This is indeed the case/ A&I 2& 34 lists these interchangeableand e-uivalent connections.

Tool joints are identified by a series of 9 mar$ings stenciled at the base of the pin

connection!

E The first mar$ing designates the company symbol/

E The second mar$ing is a number from to 8, indicating the month that thetool joint was welded/

E The third mar$ing denotes the last two digits of the year in which the tool

joint was welded 'e.g., G


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2epublic *teel 2

*umitomo :etal Ind *

TA:*A T

Jallourec J

)abcoc$ H ;ilcox ;

Algoma K

Loungstown L

TI *teel Tube Div. M

American *eamless Tube AI

Tubemeuse T

Joest JA

'sed(

E The fifth symbol is the pipe grade code, designated as follows!

ipe rade "ymbol

+G6

@ @

C+39 C

K+


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at the base of the pin designate the company initials %%, and indicate that the tooljoint was welded in :ay


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compared to the rest of the drill string. *uch wea$ening can lead to pipe or tool jointfailures. To avoid such failures 'and the fishing jobs that usually result(, drilling

personnel need to handle pipe with care.

Although the actual handling of drill pipe is the job of the rig crew, it is important forengineers to be familiar with proper pipe handling procedures and to observe that

they are being followed. *uch attention to detail will, in the long run, prevent wellproblems. The guidelines in this section, ta$en from 2owe and ;ilson ' run in slowly enough to avoid

sudden impact on ridges or shoulders, to avoid tagging bottom and to preventhigh surging or swabbing pressures/

E Do not use the slips as a bra$e to stop the downward drill pipe movementwhen tripping in the hole/

E Do not allow the slips to #ride# the pipe when tripping out of the hole/


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E se bac$up tongs when brea$ing connections/ do not depend on the weightof the drill string to $eep the pipe from turning in the slips/

E *et the slips with the tool joint as near as practical to the rotary table> this

minimi%es the possibility of bending the pipe during ma$e+up or brea$out/

E ;hen pic$ing up, laying down or standing bac$ pipe, ma$e sure that thecatwal$, J+door and derric$ floor are clear of foreign objects that could cause

impact damage, and that the pipe is cleaned of any damaging or corrosivefluids.

Conne$tions

Initial ma$e+up is probably the most important factor affecting the life of tool joint

connections. The following practices should be a part of ma$e+up procedures!

E &re+determine proper ma$e+up tor-ue, as specified for the particularconnection, si%e, outside diameter and inside diameter/

E se care when stabbing the pin connections into the box end, ma$ing sure

that the pin does not stri$e the box shoulder or glance off the box threads/

E :a$e up connections slowly+high+speed $elly spinners or the spinning chain,

when used on initial ma$e+up, can cause galling of the threads. he drillershould never jerk on the tong line to obtain proper make-up tor7ue1

E se a properly wor$ing, accurately calibrated tor-ue gauge to measure there-uired line+pull as joints are made up to the re-uired tor-ue. This line pull is

e-ual to the length of the tong arm 'measured from the center of the tooljoint, with the tongs in the set position at a 899 angle to the pull line(

multiplied by the tong line pull.

Inspe$tion

The IADC and the A&I have established detailed inspection guidelines for drill pipeand tool joints, which can be found in A&I 2& 34 .

Drill string failures result primarily from fatigue. The A&I defines a fatigue failure asone #which originates as a result of repeated or fluctuating stresses having maximum

values less than the tensile strength of the material.# These stresses are products ofthe bending, torsion, vibration, tension and friction inherent in drilling operations,

and are aggravated by corrosion, erosion, poor handling and other factors.

"atigue failures are progressive/ they generally begin as small crac$s, which

propagate as continued stress is applied. nfortunately, fatigue is hard to detect in

its early stages, and there are no accepted procedures for determining the amount ofaccumulated fatigue damage or the remaining life of pipe.

Accepted methods for inspecting the drill pipe tube involve!


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E visual or magnetic particle inspection to locate crac$s, pits and other surfacemar$s/

E remaining wall thic$ness measurement, using either!

> pipe+wall micrometers/

> sonic pulse echo 'resonance measurements(/

> gamma ray devices, calibrated to within 8Q accuracy/

> outside diameter measurement/

> cross+sectional area measurement, either by means of adirect+indicating instrument calibrated to within 8Q accuracy, or

by integrating wall thic$ness measurements ta$en at +inch

intervals.

2e-uired A&I procedures for inspecting tool joints involve!

E measuring outside diameter/

E chec$ing shoulders for galls, nic$s, washes, fins or other evidence of wear/

E randomly chec$ing 6Q of the joints for manufacture mar$ings and

installation dates to determine if the tool joint has been rewor$ed.

ptional tool joint inspection procedures include!

E determining minimum acceptable shoulder width, as specified in%* R+1

E measuring for box swell and1or pin stretch/

E examining thread profile for indications of overtor-ue, insufficient tor-ue,

lapped threads, galled threads and stretching/

E conducting a magnetic particle inspection if evidence of stretching or

swelling is found.

"atigue failure can occur rapidly under certain conditions. In areas that experience a

high incidence of washouts or pipe failures, drilling personnel must be particularly

selective about what they run in the hole, even if it means discarding joints for whichthe only signs of fatigue might be a few gouges in the slip area.

A&I 34 lists standards for classifying and identifying used drill pipe/ "igure shows

where identification mar$s are applied.
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Figure 1

Automati$ Pipe andling

Automatic pipe rac$er systems provide a means of handling drill pipe by remote

control. perated from consoles on the rig floor 'and, in some systems, from aderric$ console( they use hydraulic, pneumatic or air power to latch and unlatch

elevators, pull and set slips, ma$e or brea$ pipe connections, and lay down and pic$

up pipe. These systems are used primarily on floating drilling vessels, but are alsoavailable for use on platforms, jac$+up rigs and land rigs.

Automatic pipe handling systems can provide dramatic savings on trip time and

manpower, but their greatest benefit is increased safety. *afety is an especiallyimportant consideration on floating drilling vessels, where rough weather and heavyseas fre-uently render manual methods of pipe handling not only impractical, but

dangerous.


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Drill CollarsDrill CollarsFor a number of years after the introduction of rotary rigs and rolling cutter rock bits, atypical bottomhole assembly consisted merely of a short crossover sub, or collar,

between the bit and the drill pipe.

As rotary drilling technology improved from these early beginnings and bettere-uipment became available, operators observed that increasing the amount of

weight applied to the bit resulted in faster penetration rates. They began insertingmore and longer part sections of heavy pipe in the drill string to replace the old

crossover subs 'although the original term #collar# remained in use(. Today, drillcollars are routinely used to provide weight to the bit and optimi%e drilling rates.

sing drill collars in the bottomhole assembly, however, can also increase the

potential for drill pipe failure. As the driller slac$s off more weight from the bra$e tota$e advantage of the added weight provided by the drill collars, the compressive

force on the drill pipe increases, causing the drill pipe 'which is thin and flexible

compared to the drill collars( to bend or buc$le. This bending occurs in the body ofthe pipe between the end upsets. The abrupt change in cross+sectional area between

the pipe body and the upsets sets up stress concentrations just above and below themuch stiffer tool joint.

;hen drill pipe rotates in this compressed state, it experiences cyclic stressreversals. @ach rotation of the string causes the drill pipe fibers to go from

compression to tension to compression. This high cyclic stress bending causes metal

fatigue, which is cumulative and eventually leads to drill pipe failure ' "igure (.
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Figure 1

To avoid fatigue failures, the drill pipe and uppermost drill collars need to be $ept in

tension at all times. Tension can be maintained by running an ade-uate number ofcollars in the bottomhole assembly to ensure that the neutral point 'that is, the point

below which the drill string is in compression, and above which it is in tension( will

always be below the drill pipe ' "igure 8 (.


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Figure 2

4eight 5equirements

The weight of drill collars re-uired to $eep drill pipe in tension may be determined as

follows!

Feight of drill collars in air G #F.B..:C( #SC( # 1(where2

F.B.. G re*uired weight on bit, pounds #based on manufacturer recommendations(

)" N buoyancy factor of drilling fluid

*" N predetermined safety factor

The weight of the pipe in fluid is e*ual to its weight in air times the buoyancy factor. Table 1.,below, lists buoyancy factors for various mud weights.

Fluid Weight, lb/gal uo!anc! Factor

4.77 .465


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4.1 .468

.8 .4'5

.1 .411

&8.8 .496

&8.1 .498

&&.8 .475

&&.1 .459

&5.8 .4&6

&5.1 .48

&7.8 .48&

&7.1 .69

&9.8 .64'

&9.1 .664

&1.8 .66&

&1.1 .6'7

&'.8 .61'

&'.1 .694

&6.8 .698

&6.1 .677

&4.8 .651

&4.1 .6&6

&.8 .6&8

&.1 .685

58.8 .'9

Table 1. Buoyancy factors for steel pipe.

*afety factors may range from .6 to .89, depending on hole conditions anddrilling location. In any case, the safety factor must be high enough to ensure that

the neutral point will always be in drill collars or heavy+wall drill pipe, never in thedrill pipe string.

The number of drill collars needed to attain the re-uired weight on bit is simply e-ual

to the total weight of the collars in air divided by their weight per foot and length ofeach collar!

@xample!

it weight re*uired G 11,888 lbud weight G &5 lb:gal

)uoyancy factor N 6.G8

*afety factor N .9

Drill collars available2

-ine 4" BD 5 " D 7&< length, &18 lb:ft

B # D 8 # ID 76 length, 66 lb1ft


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0f all nine 4" BD collars are used, how many ' " collars are neededH

"olution

3e*uired weight of collars in air G #11,888:8.45( &.&1 G 66,&79 lb

;eight of G# collars N < 7 96 N 5,G96 lb

;eight of # D collars re-uired N 33,75 + 5,G96 N 79,8G5 lb

umber of # D collars N '79,8G5(1'66 76( N .33

&ic$ up twelve '8( # drill collars

There are also graphical methods available for determining drill collar re*uirements

Dimensions and Strengths

Drill collars are available in both A&I and non+A&I si%es. =ength ranges for A&I collars

are 2ange 8 '76, 7 ft( and 2ange 7 '58, 57 ft(.Drill collars are also specified

according to their outside diameters, inside diameters and weights.

Tapered Strings

;hen using large+diameter drill collars 'for example, on a deep well(, it is necessaryto taper the drill collar string so that changes in cross+sectional area from the larger

to the smaller drill collar are not too abrupt. therwise, there is an increasedpotential for connection failures and fatigue damage.

The largest+diameter collars should be placed at the bottom of the string, and shouldgradually be tapered upwards toward the smallest drill collars or heavy+wall drill

pipe.

The following rules of thumb apply to running tapered drill collar strings!

The stiffness of the larger+diameter collar should never e$ceed 7.1 times that of the

smaller ad!acent collar;

-ever reduce drill collar outside diameter #BD( more than two inches at any crossover

#for e$ample, if the bottom collar BD is &8", the collar above the crossover should havean BD no smaller than 4"(;

3un at least three collars one stand of the ne$t smaller sie with each sie change.

Special Features

*pecial features of drill collars include fishing nec$s, stepped bores, slip and elevator

recesses, spiral grooves and hard+facing ' "igure ,


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Figure 1

"igure 8 ,


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Figure 2

"igure 7 , and "igure 5 (.


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Figure !


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Figure 3

% fishing neck 'so called because of its ability to receive a fishing overshot andgrapple in case the collar parts in the hole( is a section of reduced outside diameter

at the end of a drill collar. It is machined to allow smaller connections, which can beproperly tor-ued using available rig tongs and catheads. "ishing nec$s are common

in drill collars of more than G# outside diameter, but are occasionally found onsmaller si%es when the clearance between the collar and the hole is very small.

"tepped bores are reduced ID sections through pin connections of drill collars/ theyare used to increase the pin strength in small and medium diameter collars when

large bores are needed for circulating fluid. A typical example would be a # drill

collar with a 8 # bore that is reduced to 8 15# through the pin.

"lip and elevator recesses eliminate the need for safety clamps and lift subs,

enabling the rig crew to simply change elevators and handle drill collars as they

would handle drill pipe. :achining and repairing these recesses, however, re-uiresextreme caution and close adherence to manufacturer specifications > even slight

deviations in recess depth, curvature on the ends, surface finish and cold rolling cancause serious high stress problems. *lip and elevator recesses should not be used in

highly corrosive environments because of the increased potential for stress corrosion.


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*mall+to+medium D drill collars with spiral grooves help prevent differential stic$ingby reducing the contact area between the collars and the borehole wall, and by

allowing the hydrostatic mud pressure to e-uali%e around the drill collars. 6ote thatthe weight of a round drill collar will be reduced by approimately :; by spiral

conversion.

:any drill collars are hard-faced with tungsten carbide for areas where abrasiveformations cause rapid D wear. As is the case with machining slip and elevatorrecesses, hard facing re-uires extreme care. The steel used in drill collars is very

sensitive to -uench effect, and can easily be crac$ed or left with high residualstresses that can cause crac$s to form later. An additional concern is that rough

hard+facing can result in costly casing wear.

Conne$tions

Design of the best rotary+shouldered connection for a drill collar calls for the pin andbox to be balanced in bending fatigue. It has been found that the pin and box are

e-ually strong in bending if the section modulus of the box in its critical %one '%)( is

8.9 times greater than the section modulus of the pin at its critical %one '%P(. These%ones are shown in "igure .

Figure 1


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In the box connection, the critical %one is just short of the end of the pin at the root

of the last engaged thread. It is not supported by the mating pin threads, and it is

the wea$est section in the box. The critical %one of the pin is about # from the

shoulder, at the root of the thread.

*ection modulus ratios from 8.89 to 8.39 wor$ very well under most conditions, andin some cases, ratios from 8.6 to 7.8 give satisfactory performance. These numbers

for bending fatigue balance are only valid if the connection is properly tightened sothat the pin gets sufficient shoulder support.

Torsional strength is another important structural property of rotary+shoulderedconnections. Critical areas of pin 'AP( and box 'A)( that are used for torsional

strength are also shown in "igure . This torsional strength determines the re-uiredma$e+up tor-ue.%* R +provides complete tor-ue information for the various

si%es of connections and collars.

Drill Collars 6s. Drill Pipe

The difference between the treatment and properties of drill collar connections anddrill pipe tool joint connections is often misunderstood. A drill collar connection can

never be made as strong as the drill collar body. It is a sacrificial element > when itbecomes worn, it is cut off and replaced by machining new threads.

Drill pipe tool joint connections, on the other hand, are much stiffer and strongerthan the pipe itself. They seldom experience bending fatigue damage. The most

common damage to tool joint threads results from lea$ing joints, rough handling,thread wear and swelled boxes made thin by D wear. Damaged tool joints can often

be rewor$ed and returned to service by chasing 'that is, straightening and cleaning(the threads, thus losing only a fraction of an inch in length.

API 7umbered Conne$tions

?istorically, the nominal si%e of a rotary+shouldered connection was the actual drill

pipe D that the tool joint was designed to fit. The same connections have beenused on drill collars, although the nominal si%e has no meaning when applied to drill

collars. :any old connections have been incorporated into the A&I umberedConnection series.

The numbered connection series provides a good selection of connections for almost

any si%e drill collar. Any other A&I connection with four threads per inch wor$s well. Athread with a 6.67G# root radius will have less notch effect than a thread with asmaller radius.

Sele$tion Criteria

Avoid using drill collar connections with five threads per inch. The


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tor-ues result in reduced shoulder loads. ?igher hoop stresses are developed andthin boxes must be avoided.

4ood connections are designed to fit drill collars through # D. A problem,

however, is that only large rigs may have tongs and line pull capacities to handle a 3

# joint that would be used on a


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Figure 3

In some cases, a combination of fishing nec$s and low tor-ue faces may be used.

he important thing to remember is that sufficient tor7ue on a modified end or, ifnecessary, a smaller joint is far better than inade7uate tor7ue on a full-size end and

a larger joint.

A feature recommended for all drill collars is cold rolling of thread roots. Cold rolling

forces metal fibers into compression in the thread root area, ma$ing the connectionmore resistant to bending fatigue. This is standard procedure for most

manufacturers. 4ood repair shops are also e-uipped to cold roll re+cut drill collars.This process improves resistance to notch fatigue and has not shown any adverse

effects.

*tress relief features are highly recommended for drill collars, and are almost

universally used on drill collars five inches in diameter or larger ' "igure 5 (.


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Figure !

The only disadvantage of these features is that more of the collar must be removed

to re+cut a joint. ?owever, a damaged drill collar joint is usually in such poorcondition that it is good practice in any event to remove most of the old joint before

cutting.

Drill collars smaller than five inches D are seldom damaged by fatigue. :ost

damage while in service results from high tor-ue. Drill collars with a 5 # D 8# IDare manufactured about e-ually with and without relief features. In this case, no set

rules apply, and operating conditions dictate the preference.

*tress relief features only slightly reduce the torsional strength of a connection. n

medium and large connections, this strength reduction is insignificant > it should,however, be considered on small connections. Collars with a 8 # internal flush bore,

or smaller joints, should never be supplied with stress relief features.

?eavy ;all Drill &ipe-ea/ 0all Drill Pipe


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?eavy wall drill pipe is an intermediate drill string member > heavier, stronger andstiffer than regular drill pipe, but at the same time more flexible than drill collars.

)ecause it has the same external dimensions as regular drill pipe, it is much easier tohandle than drill collars. "igure and "igure 8illustrate some of its important features.

Figure 1


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Figure 2

The most important drill string application for heavy wall drill pipe is in the so+called

zone of destruction < the area above the topmost drill collars where drill pipe fatiguefailure is most li$ely to occur. To reduce fatigue failures in this area of the borehole,

G to 8 joints of heavy wall drill pipe should be run above the drill collars. Thisprovides a gradual change in stiffness between drill collars and drill pipe. Also, the

ability of the heavy wall drill pipe to bend 'unli$e drill collars( serves to relieve high

stresses at the connections.

To prevent too great a change in stiffness between the drill collars and the heavy walldrill pipe, the guidelines in Table 1., below, can be used.

-ea/ 0all Drill Pipe D inches 4aimum Drill Collar D inches"

7.18 '.88

9.88 '.18

9.18 6.51

1.88 4.51

Table 1.*i%ing guidelines for heavy wall drill pipe and drill collars


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?eavy wall drill pipe was first used in directional drilling, which generally re-uiresflexibility in the drill string. It is now widely used in vertical and hori%ontal drilling as

well. ;ith less wall contact than would be experienced with drill collars, its usagereduces tor-ue and wall+stic$ing tendencies. Its smaller degree of wall contact,

together with its greater stiffness relative to regular drill pipe, results in increasedstability and better directional control. ?eavy wall drill pipe is also useful in reducing

hoo$ loads, ma$ing it ideal for smaller rigs drilling deeper holes.

In certain special applications 'most notably hori%ontal drilling( heavy wall drill pipe

may be run in compression. It is important to $eep in mind, however, that a joint ofheavy wall drill pipe is not as strong as a drill collar, and that it is still susceptible to

buc$ling and fatigue failure. *n a vertical hole, heavy wall drill pipe must bemaintained in tension.

)ottomhole Assembly ToolsStabili6ers

*tabili%ers, by centrali%ing the drill string at selected points in the borehole, can beused to!

ensure that the weight of the drill collars is concentrated on the bit;

reduce tor-ue and bending stresses in the drill string/

prevent wall+stic$ing or $ey+seating of the drill collars/

build, drop or maintain hole angle in directional drilling/

maintain constant bit direction in straight+hole drilling.

The type and placement of stabiliers in the drill string depends on local drilling conditions andwell ob!ectives.

In areas with a tendency toward croo$ed drilling, the stabili%er's( immediately abovethe bit must have ade-uate wall contact to provide bit stability and guidance. The

stabili%er's( must also have wear properties which will permit them to stay in gaugefor the life of the bit, and must be able to centrali%e the drill string without digging

into the borehole wall.

In an angle+holding, orpacked-hole assembly, which re-uires maximum stiffness to

#loc$ in# the direction of the drill string, the stabili%ers should have the largest

possible cross+sectional area that will permit ade-uate circulation passage.

"or pac$ed+hole drilling techni-ues, stabili%ers act li$e drill bushings to minimi%e drift

and hole angle change by centering the drill string. ;hen utili%ing apendulum, orangle+dropping assembly, stabili%ers are fre-uently used to increase the effectiveness

of the pendulum. They similarly serve to increase the effectiveness of an angle+building assembly. *tabili%ers are also designed to prevent wall+stic$ing of the drill

collars and to guide them out of $ey seats.


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There are a variety of stabili%er types available for different drilling environments,the most common of which are!

integral blade stabiliers;

replaceable sleeve stabili%ers/

replaceable wear pad stabili%ers/

non+rotating sleeve stabili%ers/

welded blade stabili%ers.

These stabilier types are designed either for bottomhole configuration #to be run !ust above thebit(, or string configuration #to be run at various points in the drill string(.

The integral blade stabilizer ' "igure ( is designed for use in all degrees of formation

hardness.

Figure 1


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Its long ribs are designed to provide the wall contact necessary for properstabili%ation, and are contoured to minimi%e tor-ue while drilling. The ribs are milled

directly on the stabili%er body.

"or larger hole si%es, the integral blade stabili%er can be manufactured with a shop+replaceable sleeve. Its long ribs are milled directly on the sleeve to provide uniti%edconstruction, thus preventing loss of ribs in the hole as sometimes happens with

welded rib stabili%ers.

These stabili%ers can be provided with pressed+in tungsten+carbide compacts or

welded+on hardfacing on the wear surfaces to increase gauge life. Integral bladestabili%ers are available in both string and bottom hole types.

The replaceable steel sleeve stabilizer ' "igure 8 ( has the benefit of being replaceable

at the wellsite.

Figure 2

*leeves can be changed in the rotary table, ma$ing this stabili%er type economical


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for remote locations. 2eplaceable sleeve stabili%ers are available both in bottomholeand string configuration. They can be used for more than one hole si%e by changing

sleeve si%e. Deep+grooved passages between the sleeve ribs assure ade-uatecirculation past the tool.

The replaceable wear pad stabilizer, with rig+replaceable wear pads ' "igure 7 'string(

and "igure 5'bottomhole((,

Figure 3

is very effective for pac$ed+hole assemblies, and can be used in all types of

formations.


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Figure !

The wear pads, which can easily be changed out in the rotary table with hand tools,

provide long wall contact area, and pressed+in tungsten carbide and carburi%ed wearsurfaces provide maximum downhole life. ;ithin limits, changing wear pads permits

body use in more than one hole si%e ' "igure 9 (.


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Figure 5

)uilt+in wear indicators are available to indicate the need for replacement before

body damage occurs. The stabili%er body has a fluted configuration to provide forade-uate circulation. This stabili%er type is available in either bottomhole or string

configuration, so that two or three tools can be run in tandem hoo$ups to provideadditional wall contact as re-uired.

The non-rotating sleeve stabilizer ' "igure ( is one of the most effective stabili%er

types.


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Figure

A true #drill bushing,# it can be used in hard to medium+hard non+abrasive

formations, since the sleeve does not rotate or dig into the borehole wall. The one+piece, rig+replaceable sleeve is molded over a mild steel inner bushing to prevent it

from being lost downhole, and has fluted marine+type inner bearings, designed to

allow continuous cleaning by the circulating fluid. Drilling fluid acts as a lubricant andcoolant to avoid friction between the mandrel and the non+rotating sleeve. The non+rotating sleeve stabili%er is always a string+type tool.

The welded blade stabilizer ' "igure 3 ( is designed to centrali%e drill collars and

provide better borehole alignment.


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Figure 7

Its rotating blade is especially effective in soft formations, where balling+up of mudand cuttings on the drill string can cause problems.

%ars

=arsare used to provide -uic$, sharp, upward or downward motion to free stuc$

pipe. Although we most commonly associate them with fishing operations, they canalso be run on drilling bottomhole assemblies as a precautionary measure. They are

especially appropriate for drilling in stic$y, heaving, sloughing or croo$ed holes. arsalso have applications in controlled+weight directional drilling, as well as in coring

operations. "igure shows a mechanical rotary drilling jar.


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Figure 1

ars are usually identified according to type, inside and outside diameter, threadconnection and stro$e length. There are a number of jar types available, and the

type of jarring action utili%ed will depend on the jar being used and the specific

operating conditions. "or typical mechanical or hydraulic jars, upward or downwardmotion is initiated by pulling up or slac$ing off on the drill string until a pre+set

triggering load is reached, initiating a sharp blow. A few such blows may be sufficient

to free a stuc$ drill string without the expense and ris$ of a fishing job.

In drilling operations, jars are generally run high in the drill collar string, with some

drill collars above them. ptimum jar placement and triggering load, along with theneed to enhance the jarring impact by running a companion tool $nown as ajar

accelerator, is best determined individually for each bottomhole assembly, with inputfrom the service company providing the tools.

8eamers

In very hard 'or hard and abrasive( formations, the outside cutting structure of a bit

gradually wears away if it is not protected. The bit becomes #pinched# or

undergauge, resulting in a hole diameter that becomes smaller with increasing

depth. "igure shows an extreme example of an under+gauge bit > this # bit,


51/56

Figure 1

with no stabili%ation, wore down to 5 # D after ma$ing 58G ft in 9< hours.

;hen a hole is severely undergauge, it is necessary to ream each new bit bac$ tobottom before drilling can resume. This not only costs rig time and reduces bit life,

but it increases the possibility of stic$ing the drill string.

2oller+cutter rotary reamers, with either three points or six points of wall contact

'"igure 8 and "igure 7(, have proven to be effective for $eeping holes in gauge.


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Figure 2

This not only prolongs bit life, but it also minimi%es wear on other tools used in

pac$ed+hole assemblies in croo$ed hole drilling areas.


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Figure 3

hree-point bottomhole reamers are designed to be run between the bit and the drillcollars, with the spacing from the bit to the reamer $ept to a minimum. This set+up

$eeps the hole in gauge to ensure minimum time spent reaming bac$ to bottom,protects the gauge of tools above the reamer and provides some stabili%ation to the

bit.

hree-point string rotary reamers are sometimes run in the drill collar or drill pipe

strings to centrali%e the strings in croo$ed hole areas. ;hen run above the drillcollars, they can be effective in reaming out dog+legs, $ey+seats and ledges. )oth

types of three+point reamers contain wall contact points spaced 86R apart.

"i-point bottomhole reamers are run between the bit and drill collars, and are used

when greater reaming capacity is re-uired than can be provided by the three+pointdesign. They are especially effective in hard, abrasive formations where extremely

hard cutters can be run in the lower points and regular hard cutters in the upperpoints. The six points of contact, spaced 6 RC apart, provide better stabili%ation

than a three+point reamer in croo$ed hole areas.


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A variety of roller reamer cutters are available for different formation types. "or hardformations that re-uire a scraping action, such as dolomite, hard lime and chert, the

#S# cutter ' "igure 7, top( may be used. "or extremely hard formations, the #0,# or$nobby cutter ' "igure 7, bottom( may be used. Its tungsten carbide compacts act as

teeth to fracture the formation.

The reamer bodies shown here utili%e drive+fit hardened reamer pins and bearingbloc$s, which can be easily replaced at the wellsite without the need for special toolsor welding.

Crossoer Subs

Crossover subs join drill string components of different si%es or thread connections.

"or example, a double+box crossover would be needed to join a bit with an A&I2egular pin connection to a drill collar with A&I "ull ?ole pin connection. It is

important to $eep trac$ of the types of connections on each component of the drillstring, and to ma$e sure that the appropriate crossovers are available.

9ibration Dampeners

ne of the more important considerations in drill string design is dealing with the

vibrations and shoc$ loads that are produced as the bit rotates on bottom. *uchvibrations can cause #rough running# at the surface, and can result in damage to the

bit, drill collars, drill pipe and other components.

There are a number of drilling parameters that determine whether vibration will

occur, including!

formation lithology #e.g., hard rock, broken formations, and formations with intermittent

hard and soft streaks(;

depth/

bottomhole assembly configuration/

weight on bit/

rotary speed.

=ngineers can use these and other parameters during the well planning process to developcomputer models for optimiing drill string design. They can also monitor vibrations during the

drilling of the well by means of surface or downhole #FD( sensors.

;e can often control or eliminate downhole vibrations by modifying the bottomholeassembly configuration, or simply by adjusting rotary speed and1or weight on bit. A

vibration dampener, or shoc$ sub ' "igure ,
http://figurewin%28%27../asp/graphic.asp?code=4188&order=2%27,%272%27)http://figurewin%28%27../asp/graphic.asp?code=4188&order=2%27,%272%27)http://figurewin%28%27../asp/graphic.asp?code=4190&order=0%27,%270%27)http://figurewin%28%27../asp/graphic.asp?code=4190&order=0%27,%270%27)http://figurewin%28%27../asp/graphic.asp?code=4188&order=2%27,%272%27)http://figurewin%28%27../asp/graphic.asp?code=4188&order=2%27,%272%27)http://figurewin%28%27../asp/graphic.asp?code=4190&order=0%27,%270%27)


55/56

Figure 1

"igure 8 , and "igure 7(, may be useful in some cases for absorbing vibrations and

shoc$ loads.

Figure 2


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Figure 3

A vibration dampener is a type of shoc$ absorber designed to prevent vibrations

generated by the bit from traveling up the drill string to the surface. It is commonlyrun between the bit and the drill collars, or above the large+diameter short drill collar

segment of a pac$ed+hole drilling assembly. ;hen properly used, vibrationdampeners can result in faster drilling rates, longer bit life, less damage to the drill

string and surface e-uipment, and reduced torsional impact.

)ecause of the complexity and magnitude of the forces acting on the bit and drill

string, vibration dampeners cannot be considered a cure+all for vibration problems.They should not be routinely added to drill strings without first modeling their

effects. Improperly applied, a shoc$ sub may not only fail to absorb severevibrations, but could even create additional vibrations, thereby accelerating, rather

than preventing, drill string failure.

Documents

Drill String Components