3.

THE DRILL STRING

3.1 INTRODUCTION
-

The conventional drillstring

components are:
➢ Kelly pipe(or Top drive)
➢ Drill pipe / Heavy wall drill pipe
➢ Tool joints
➢ Bottom hole assembly (BHA)
➢ Drill bit
The BHA includes :
➢ Drill Collars
➢ Stabilizers
➢ Reamers
➢ Jars
➢ Shock Subs,…….

1
 3 THE DRILL STRING
3.2 DRILL STRING COMPONENTS
3.2.1. KELLY
It is a hexagonal or square shaped joint of pipe, measuring 40ft or 54ft ,
that is attached to the swivel and to the drill pipe.

3 2
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS

3.2.1. KELLY
The kelly is attached at the top to the swivel
and at the bottom to the kelly sub and the drill
string.The kelly fits into a device called kelly
bushing, which in turn fits into the master
bushing mounted in the rotary table.
As the rotary table turns, the kelly also turns
making the whole drilling string turn.

The functions of the kelly are therefore:

➢ Transmit rotation and weight to the drill bit,
➢ Carry the total weight of the drill string
➢ To flow the mud to the drill string

NOTE : the Top Drive would replace the kelly and

rotary table.
3
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
3.2.2. DRILL PIPE (DP)
Drill pipe is the major component of the drill string (90-95%). In deep
and extended reach wells the drill pipe section can be over 10km!
DP is seamless pipe with threaded connections on both ends (tool joints,
box and pin):

DP is supplied in joints that are classified

in Range 1 ,2 ,3 according to their length:

4
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
3.2.2. DRILL PIPE
Each drill pipe is made according to certain specifications (size, length,
weight, grade) which have implications on the burst, collapse, tensile
and torsional strength of the pipe. The DP in common use is hot-rolled,
pierced, seamless tubing. OD varies from 2 3/8” to 6 5/8”.
The drilling engineer must select the most suitable DP for the well
conditions.
COMMON DRILL PIPE DIMENSIONS
DRILL PIPE GRADES

5
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
-

3.2.2. DRILL PIPE

RANGE 2 DP AVERAGE DISPLACEMENTS

6
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
-
3.2.2. DRILL PIPE

RANGE 2 DP AVERAGE DISPLACEMENTS

7
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
-
3.2.2. DRILL PIPE

DRILL PIPE INSPECTION METHODS

With utilization, the DP is subject to wear. To
determine the degree of wear (damage) , regular
inspection by non-destructive methods is carried
out. These tests determine the degree of wear and
any visible physical defects (cracks, indentions
from slips,…).
The strength of the DP is rated on basis of the
remaining wall thickness.
Example of a specification for a string of DP :

5”OD, 16.25lbs/ft, Grade G, Range 2

8
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
-
3.2.2. DRILL PIPE

9
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
-
3.2.2. DRILL PIPE
Each piece of DP is called a single or joint. While drilling, a single is added
periodically as the previous one “ is drilled out”. When tripping in/out of hole the
DP is pulled by stands (double or triple, depending on the rig mast).
The driller before running a joint of DP ( or any other piece of equipment) in
hole, measures carefully its length and registers it in the Pipe Tally (the only sure
way of measuring the depth of the well).

10
WHAT ARE THEY DOING ?

1 2

11
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
-
3.2.2. DRILL PIPE

The DP weight on air is different

from the weight when immersed in
the mud( wet weight), due to the
bouyancy force(BF).
This force is directly proportional
to the density of the mud in hole:

Wet weight= weight on air x BF

The Buoyancy Factor for steel is

shown in the table.

12
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
-
3.2.2. DRILL PIPE

When drilling ,the DP is subjected to several stresses :

❑ Tension: due to the weight of the string suspended below and any over pull
situation,

❑ Torque : if there are obstructions in the well the drill string could be
overtorqued while attempting to release the string,

❑ Cyclic stress failure: while drilling deviated wells the body of the DP is
subjected to alternate compressive/tensile loads that could cause fatigue of the
steel(cracks).

❑ Stress induced by other reasons: friction, abrasion, vibration and pounding of

the bit on bottom.

13
NOTE : the DP must always work in tension!
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
-

3.2.3. HEAVY WALL DRILL PIPE (HWDP)

HWDP has a greater wall thickness than regular DP, which makes it 2-3
times more heavier than DP.
In the drill string they are run between the DP and the drill collars (DC),
where the stress concentration is higher.

HWDP has the following major features:

➢ reduces failure at transition zone DP/DC,
➢ reduces down the hole torque and drag in directional drilling,
➢ reduces differential sticking,
➢ increases performance of small rigs in shallow wells by replacing
some DCs.

HWDP should always be operated in compression.

14
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
-

3.2.3. HEAVY WALL DRILL PIPE (HWDP)

HWDP has a greater wall thickness than regular DP, which makes it 2-3 times
more heavier than DP. In the drill string it is run between the DP and the drill
collars (DC), where the stress concentration is higher.
The stress concentration is higher due to the difference in cross section
between DP and DC and also because of the vertical bouncing effect of the bit.

HWDP

DC

15
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
3.2.3. HEAVY WALL DRILL PIPE (HWDP)
-

16
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
-
3.2.4.TOOL JOINTS
At both ends of the DP/HWDP joints are welded the tool joints (box and
pin). The tool joints serve to screw together the DP joints. To protect them
from abrasion they are often protected with a hard material band welded
onto them.
The tool joint strenght depends on the cross sectional area of the box and
pin. With continual use the threads become worn and there is a decrease in
the tensile strenght. Regular inspection is required.
API Tool Joints Minimum tensile yield strenght for new DP

17
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
-

3.2.4.TOOL JOINTS

PIN

SEAL

BOX

The ID of the connection

is smaller than the ID of
the pipe

18
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
3.2.3. HEAVY WALL DRILL PIPE (HWDP)
-

19
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
-

3.2.5. BOTTOM HOLE ASSEMBLY( BHA)

The BHA is located between the bit and the DP (or HWDP). The main
component of the BHA are the Drill Collars. Other components are:
stabilizers, jars, reamers, hole openers, shock absorbers and a variety
of subs.
Some BHAs can also use down-the-hole motors, rotary steerable
systems, measurement while drilling (MWD) and logging while drilling
(LWD) tools.

The main functions of the BHA are:

➢ Protect the DP of excessive bending and torsional loads by keeping
the drilling string in tension,
➢ Due to its stiffness drill more vertical and straight holes,
➢ Reduce severity of dog legs and key seats,
➢ Reduce rough drilling that cause harmful vibrations to the string
and rig)
20
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
-

3.2.5. BOTTOM HOLE ASSEMBLY (BHA)

3.2.5.1 DRILL COLLARS (DC)
Drill collars (DC) that have a much larger outside diameter and a
much smaller inside diameter than the DP (Example: 9”OD drill collar
run with a 5” OD drill pipe, has an ID of 2 13/16” versus an ID of 4
¼”of the DP).

DC main advantages:
➢ to provide extra weight and rigidity on the bit for efficient drilling
(make bit cutters to bite into the rock)
➢ to keep the drilling string (DP) in tension to prevent buckling,
thereby reducing failures due to fatigue
➢ to provide stiffness to the BHA for better directional control
➢ to stabilize the bit

21
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS

3.2.5. BOTTOM HOLE ASSEMBLY (BHA)

3.2.5.1. DRILL COLLARS (DC)
DC´s are made of special chrome-molybdenum alloy, fully heat treated,
and they are usually supplied in Range 2 (30-32 ft).

DC´s are subject to stresses due to:

➢ buckling and bending forces,
➢ tension,
➢ vibration,
➢ alternate compression/tension

Due to these solicitations is very important to handle them properly. The

weakest point in the DC is the connection; therefore the correct make-up
torque must be applied.
The shoulders and threads must be lubricated with the correct lubricant

22
DRILL COLLARS CYCLIC LOADING

23
 3. THE DRILL STRING
3.2. DRILL STRING COMPONENTS
-

3.2.5. BOTTOM HOLE ASSEMBLY (BHA)

3.2.5.1. DRILL COLLARS (DC)

24
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
3.2.5. BOTTOM HOLE ASSEMBLY (BHA)
3.2.5.1. DRILL COLLARS (DC) - SPECIAL TYPES

SPIRAL DC: the spiral grooves machined in the body of the DC reduces the
contact area by 40%, while the reduction in DC weight is only 4%. This
reduction in contact area decreases the risk of differential pressure sticking of
the BHA.
They are usually employed in directional drilling.

SQUARE DC: are usually 1/16” less than the bit size and are run to provide
maximum stabilization of the BHA.
The square design increases the stiffness and rigidity to prevent buckling. Also
contributes to a more stable and stiff BHA ideal for drilling hard formations.

MONEL DC: also known as non-magnetic drill collars they are made of monel (a
special non-magnetic steel alloy) . They are run in the BHA, above and below
magnetic survey instruments , to reduce the interference of the magnetic fields
associated to the BHA, with the earth´s magnetic field.
25
 3. THE DRILL STRING
3.2. DRILL STRING COMPONENTS
-
3.2.5. BOTTOM HOLE ASSEMBLY (BHA)
3.2.5.1. DRILL COLLARS (DC)

26
 3. THE DRILL STRING
3.2. DRILL STRING COMPONENTS
-
3.2.5. BOTTOM HOLE ASSEMBLY (BHA)//3.2.5.1. DRILL COLLARS (DC)
MUD DENSITY, GRADIENTS AND BUOYANCY FACTOR ( FOR STEEL ONLY)

27
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS

3.2.5. BOTTOM HOLE ASSEMBLY (BHA)

3.2.5.2. STABILIZERS
Basically stabilizers are a short lenght of pipe with blades (straight or
spiral) on the outsider.

The stabilizer is placed above the bit, to:

➢ reduce buckling/bending stresses on DC,
➢ increase bit life and performance,
➢ allow higher WOB,
➢ ensure full gauge of hole,
➢ help prevent wall sticking

28
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS

3.2.5. BOTTOM HOLE ASSEMBLY (BHA)

3.2.5.3. ROLLER REAMERS
Also called drilling reamers, they are basically a stabilizer with rollers
embedded in the surface of the blades. They act as a stabilizer and
maintain the hole in gauge, due to the action of the rollers. They are
also helpfull in reaming potential hole problems like dog legs, key
seats and ledges.

29
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS
-
3.2.5. BOTTOM HOLE ASSEMBLY (BHA)
3.2.5.4. SHOCK ABSORBERS
Shock absorbers or vibration dampeners are located above the bit ( or
between reamers and/or stabilizers)to reduce the stresses caused by the
bouncing of the bit when drilling hard rock or fractured formations.
They have a strong steel spring, or rubber element inside ,that absorbs
the vibrations. They can have a positive effect on extending the bit life
and the drill string by reducing or eliminating vertical oscillations.

30
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS

3.2.5. BOTTOM HOLE ASSEMBLY (BHA)

3.2.5.5. DRILLING JARS
Drilling jars are tools that are used to deliver a sharp blow to free
stuck pipe (or fish). They are located at the top of the drill collars.
They are classified as hydraulic or mechanical:

➢ Hydraulic jars are stimulated by straight pull of the drilling string, and
give an upward blow,
➢ Mechanical jars are preset at surface to operate when a certain
compression load is applied on the drilling string and give an upward
blow.
They are installed in the string when drilling
sloughing formations, sensitive shales or when
there is expensive equipment incorporated in the
BHA (ex MWD).

31
 3. THE DRILL STRING
3.2 DRILL STRING COMPONENTS

3.2.5. BOTTOM HOLE ASSEMBLY (BHA)

3.2.5.5. HOLE OPENERS
Hole opener is a tool used to enlarge the size of the hole drilled by the bit. It
can be positioned right above the bit or above it.
There is a large choice of models and sizes ( up to 50”)

32
 3. THE DRILL STRING
3.3 DRILL BITS
-

3.3.1. TYPES OF DRILL BITS

At the very bottom of the drilling string is located the drilling bit. The bit
function is to cut the rock by percussion or rotation.
Basically there are two types of bits: fixed cutter and roller-cone bits.
Hybrid bits are a combination of fixed cutter and roller-cone bits.

33
 3. THE DRILL STRING
3.3 DRILL BITS
-

3.3.1. DRILL BITS (FIXED CUTTER): STEEL CUTTER BITS - DRAG BITS
The first bits used in rotary drilling up to 1900, were the drag bits,
consisting of rigid steel blades, rotating as a single unit. They were
mostly employed in soft formations:

These bits were discontinued with the introduction of the more

efficient roller cone bits.
Drag bits could not take too much WOB as they could fail. They also had
a tendence to drill crooked wells.
34
 3. THE DRILL STRING
3.3 DRILL BITS
-

3.3.1. DRILL BITS (FIXED CUTTER): DIAMOND BITS

Diamond bits are fixed cutter bits where diamonds are used as the
cutting tool. The cutting action is done by scrapping the rock at high
RPMs. They are used in hard, non brittle, abrasive formations.

Diamond bits can be classified as :

➢ Natural Diamond bits
➢ Polycrystalline Diamond Compact bits ( PDC)
➢ Thermally Stable Polycrystalline bits ( TSP)

35
Natural Diamond Bits
 3. THE DRILL STRING
3.3 DRILL BITS

3.3.1. DRILL BITS (FIXED CUTTER): NATURAL DIAMOND BITS

In the natural diamond bit, the face of the bit is covered with
diamonds set in a specially designed pattern and bonded into a matrix
on a steel body.
Diamonds although they have a high wear resistance they are sensitive
to shock and vibration. To prevent overheating and bit balling is
important to have a good mud circulation across the face of the bit.
Main disadvantage is the bit cost (up to 10 times the cost of a roller cut
bit).
Major advantage is the long rotating hours (200-300 hours per bit),
that reduce the number of round trips for bit exchange.
They are best in drilling soft to medium hard formations.

36
 3. THE DRILL STRING
3.3 DRILL BITS

3.3.1. DRILL BITS (FIXED CUTTER): PDC BITS

Polycrystalline diamond compact bits (PDC) employ as cutters a
sintered polycrystalline diamond drill blank . The drill blank is a layer of
synthetic polycrystalline diamond about 1/64 inch thick that is bonded
to a cemented tungsten carbide substract. The blank contains many
small diamonds crystals bonded together (about 90 to 97% vol).

They are better in soft, firm and medium hard, non abrasive formations
that don´t have a tendency to bit balling.
37
 3. THE DRILL STRING
3.3 DRILL BITS
-

3.3.1. DRILL BITS (FIXED CUTTER): TSP BITS

The Thermally Stable Polycrystalline bits appeared in late 80´s as
an improvement to the PDC bits. The TSP bits can tolerate much higher
bottom hole temperatures (above 730ºC).

38
 3. THE DRILL STRING
3.3 DRILL BITS
-

3.3.1. DRILL BITS (FIXED CUTTER): IMPREGNATED BITS

The impregnated bits are bits in which the body of the bit is impregnated
with small natural and synthetic diamonds. The advantage of these bits is
that the diamonds are protected against impact by the matrix body of the bit.
Because the diamonds are very small the ROP must be achieved through
increased RPMs. For this reason they are usually run with turbo drills or
PDM motors, capable of higher RPMs (500-1500 rpm).
The ROP is low, they are extremely expensive and cannot be repaired.
However they are usually used when nothing else seems to work.

39
 3. THE DRILL STRING
3.3 DRILL BITS
-

3.3.1. DRILL BITS (ROLLER CONE BITS)

Roller cone bits (or rock bits) appeared first in 1909 and today, after
several improvements, are the most used bits in rotary drilling. They can be
classified as:

➢ Insert bits
➢ Milled tooth or stell tooth bits
➢ Tungsten carbide inserts (Tci)

The 3 cones rotate on bottom of the hole and they cut the rock by a grinding
and chipping action. The 3 cones allows for an even distribution of the
weight, and drill a better gauge hole than the previous 2 cone bit version.

INSERT BIT MILLED TOOTH BIT 40

 3. THE DRILL STRING
3.3 DRILL STRING COMPONENTS
3.3.1. DRILL BITS (ROLLER CONE BITS)
Main parts of a rock bit (insert and steel teeth)

Gauge surface

Outer

41
 3. THE DRILL STRING
3.3 DRILL BITS

3.3.1. DRILL BITS (ROLLER CONE BITS)

A roller cone bit has either steel teeth or tungsten carbide inserts.
When the bit rotates on the bottom , the cutting action is done
primarily by a grinding and chipping action.

The 3 cones design have the advantage of equally distributing the

weight (WOB), which results in a longer bit life and a better hole gauge
when compared with the 2 cone bit design. Improvements made to the
3 cone design include :

➢ Adding jet nozzles to improve cleaning of rock cuttings,

➢ Utilization of tungsten carbide for gauge protection and hard facing,
➢ Introduction of sealed bearings for extended bit life.

42
 3. THE DRILL STRING
3.3 DRILL BITS
3.3.1. DRILL BITS (NOZZLES)
Bit nozzles are usually described in 32nds of an inch. For example, a tricone
bit with 3 nozzles could have the following nozzle configuration: 10-12-12,
meaning one nozzle with a diameter of 10/32” and two nozzles with
diameters of 12/32” .
The choice of nozzles is important to make sure that the recomended velocity
of the drilling fluid is available at the rock face.
The bit manufacturer usually specifies the recommended drilling fluid flow
rate or pressure drop across the bit.

43
EXAMPLE OF HYBRID BIT

44
 3. THE DRILL STRING
3.3 DRILL BITS
-

3.3.2. DRILL BITS SELECTION

There are many types of rock formations and for each there is a type of
bit (or bits) that is (are) best suited to drill them.

The selection of the best bit is easier, if there is a record of previous bit
performance in the area (from offset well data).

A careful analysis of the bit records pulled from previous wells is the
best clue to choose the right bit.

The most valid approach for comparing the performance of various

drill bits is the drilling cost per foot drilled.

45
 3. THE DRILL STRING
3.3 DRILL BITS
-

3.3.2. DRILL BITS SELECTION

The drilling cost per foot drilled can be calculated by the expression:

Cost/ft =((Cost of bit+( time drilling+round trip time)x cost rig

operating time))/interval drilled , $/ft drilled

Theoretically, the bit should be changed when the bit drilling cost per foot
is at the minimum.

46
 3. THE DRILL STRING
3.3 DRILL BITS
-

3.3.2. DRILL BITS SELECTION

When bit records are not available, the following approach could be
followed :

1) If the formation hardness is known, then use the IADC charts

(International Association of Drilling Contractors).
2) A good choice for the initial section of the well is a tricone roller bit with
the longest tooth size possible.
3) Bit cost is an important consideration when evaluating alternatives.
4) Select diamond bits for uniform sections of carbonate rocks and bottom
portions of the well( longer bit life means reduced round trips for bit
change).
5) PDC bits should not be used in gummy formations (to avoid bit balling)

Dull bits must be carefully evaluated for future reference, and the records
saved.

47
 3. THE DRILL STRING
3.3 DRILL BITS
-
3.3.2. DRILL BITS SELECTION
The IADC developed a system to describe any tricone bit through a simple 3 digits
and one letter :

48
 3. THE DRILL STRING
3.3 DRILL BITS
3.3.2.
-
DRILL BITS SELECTION

49
 3. THE DRILL STRING
3.3 DRILL BITS
3.3.2.
-
DRILL BITS SELECTION

50
 3. THE DRILL STRING
3.3 DRILL BITS
3.3.2.
-
DRILL BITS SELECTION

51
 3. THE DRILL STRING
3.3 DRILL BITS
3.3.2.
-
DRILL BITS SELECTION

52
 3. THE DRILL STRING
3.3 DRILL BITS 3.3.2. DRILL BITS SELECTION
-

53
 3. THE DRILL STRING
3.3 DRILL BITS
-

3.3.2. DRILL BITS SELECTION STEEL TOOTH BITS

54
 3. THE DRILL STRING
3.3 DRILL BITS

3.3.2. DRILL BITS SELECTION INSERT BITS

55
 3. THE DRILL STRING
3.3 DRILL BITS
3.3.2. DRILL BITS SELECTION
The table below (Bourgoyne et al. 1986) indicates bit types usually run
in various formations:

56
 3. THE DRILL STRING
3.3 DRILL BITS
3.3.2. DRILL BITS SELECTION

57
 3. THE DRILL STRING
3.3 DRILL BITS
-

3.3.3. DRILL BIT EVALUATION

When a bit is POOH it must be carefully inspected and its condition

registered. This information is essential to:

➢ Help in bit type selection ( for the next bit runs),

➢ Select the most appropriate WOB, RPM, mud circulation
rate/pressure, for the following bit runs,
➢ Help the driller to recognize when to POOH the next bit,
➢ Evaluate bit performance.

The IADC has developed a chart to classify worn out bits (IADC Dull
Grading System), that applies to all types of bits.

58
EXAMPLES OF DAMAGED BITS

59
 3. THE DRILL STRING
3.3 DRILL BITS

3.3.3. DRILL BITS EVALUATION

60
IADC DULL BIT GRADING

61
 3. THE DRILL STRING
3.3 DRILL BITS
3.3.4. BIT PERFORMANCE
Bit performance is evaluated based on :
➢ footage drilled,
➢ rate of penetration (ROP),
➢ cost per foot drilled

Of those, the most important factor is the ROP, which depends on 4 factors:
- WOB, RPM, mud properties and hydraulic efficiency.

1) After the WOB exceeds a certain value (compressibility of the formation),

the ROP increases linearly with WOB, assuming that bit cleaning is
efficient.
A proper design of the bit nozzles will provide enough hydraulic
horsepower to clean properly the interface rock/bit. Other way of
increasing hydraulic horsepower at the bit is to increase the pumping rate
or volume pumped.
However the increase in WOB has to be properly calculated as it can
result in increased torque (without improvement in ROP), excessive hole
deviation, reduced bearings and teeth life. 62
 3. THE DRILL STRING
3.3 DRILL BITS
3.3.4. BIT PERFORMANCE
Variation of ROP due to hole cleaning on WOB (log-log):

ROP ( ft/hr) 1

WOB ( lbs)

Impact of hydraulic horsepower (HP) at the bit, on the ROP:

1- High
2- Medium
3- Low
63
 3. THE DRILL STRING
3.3 DRILL BITS
3.3.4. BIT PERFORMANCE
1) Once WOB is higher than the compressibilty of the rock, the ROP increases
linearly with the WOB.
However, the maximum WOB that can be effectively applied could be conditioned
by :
➢ Mud pumps ( Pressure/Volume) (change liners; check annular velocities)
➢ Formation (in soft formations , WOB is limited)
➢ Bit (tooth and bearing life) (reduced bit life, fishing)
➢ Hole deviation (too much WOB could bend the drill string)

The hydraulic HP at the bit can be calculated by the following formula :

HPb= (ΔPnxQb)/1714 , hp
where,
ΔPn= pressure drop across the nozzles, psi
Qb= mud flow rate through bit , gpm

The pressure drop across nozzles can be easily controlled by changing nozzles
64
size.
 3. THE DRILL STRING
3.3 DRILL BITS
3.3.4. BIT PERFORMANCE
2) The adequate RPM must be applied, so the teeth of the bit have time to
penetrate and sweep the cuttings (see next Fig.). The speed at which the
bit rotates is a function of :
➢ the bit type : lower RPMs for insert bits versus milled tooth bits,
➢ type of formation: hard formations can damage the bit if high RPMs
are applied.
PDC bits tend to drill faster with low WOB and high RPM.

3) Mud properties: are very important as they create a pressure

overbalance at the bottom of the hole as well as a filter cake, which can
affect the removal of the cuttings, and have therefore a negative impact
on the ROP (bit balling).
PDC bits have a better performance if drilling with oil based mud
(increased lubricity and decreased cutter wear temperature).

4) Hydraulic efficiency: is directly related to hydraulic horsepower which

must be sufficient to ensure good bit cleaning and lower mud
65
temperature
 3. THE DRILL STRING
3.3 DRILL BITS
3.3.4. BIT PERFORMANCE
5) The ROP is also directly affected by the rotary speed, since the teeth of the
bit require some time to bite the rock and to remove the cuttings.
The log-log plot shows the impact of variations in RPM in the ROP, in soft and
hard formations.
ROP ( ft/min)

RPM

In hard rocks, the relationship between ROP and RPM for higher RPMs,
deviates from a straight line due to the fact that the bit requires more time
to overcome the compressive strength of the rock. 66
 3. THE DRILL STRING
3.4. DRILL STRING DESIGN
-

The drill string design is required to make sure that the optimum length,
size and grade of the different parts (DP, HWDP and DC) are selected
properly.
Furthermore, the design must be done taking into consideration the
depth of the well, vertical or deviated well, margin of pull (MOP), mud
weight, burst, tensile and collapse loads, torsion, stretch, shock loading
and critical speed.
Resistance to burst is not generally considered as it is very unlikely that
the burst resistance of the pipe be exceeded.
The basic requirements for designing a drill string are:

➢ collapse, tensile and burst strength of drill string parts must not be
exceeded,
➢ bending stresses must be minimized,
➢ the required WOB must be provided by the DCs,
➢ to control the direction of the well, the BHA must be stabilized
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 3. THE DRILL STRING
3.4 DRILL STRING DESIGN
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Estimation of length of DCs
The weight required for the bit to operate in optimum conditions is given
by the DCs (the DP works in tension).
Therefore the length of DCs necessary to apply the required weight on bit is
calculated by dividing the required WOB by the buoyancy weight per foot
of the DCs, multiplied by a safety factor of 1,15.

Drill pipe design

The DP to be used in the drill string has to satisfy the requirements for
collapse and tensile loads at which it will be subjected.
Collapse pressures that could collapse the DP will be higher at the
bottom of the string , with the pipe empty (like on a DST situation).
The maximum external load (Pext) is calculated as follows:

Pext= 0.052xMWxTVD
where,
MW = mud weight in ppg
TVD= True vertical depth in ft
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A safety factor of 1,125 is applied .
 3. THE DRILL STRING
3.4 DRILL STRING DESIGN
Drill pipe design (cont.)

Tension design
The tension load at a given point of the DP string is the result of the
combined weight of DPs and DCs below that point, corrected by the
buoyancy effect.
The following safety factors are considered:
➢ MOP (Margin of Overpull): when attempting to pull out stuck pipe is
required to pull in excess of the drill string weight (MOP usually in
the range 50,000-100,000lbs).
➢ To account for extra loads imposed by rapid acceleration of pipe
(x1,3)
➢ The crushing action of the slips over time cause a reduction on the
allowable tension load ( for 5”DP : 1,32 to 1,66 , depending on slips
length).
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 3. THE DRILL STRING
3.4 DRILL STRING DESIGN
Drill pipe design (cont.)

For design purposes the total weight carried by the top joint of DP must
be calculated as follows:

P= ( DP weight+HWDP weight+DC weight)x BFx SF +MOP , lbsf

Where,
BF = Buoyancy factor( for steel imersed in mud),
SF = Safety Factor for tension ( 1,3)
MOP= Margin of Overpull ( 50,000 to 100,000lbs)

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 3. THE DRILL STRING
3.4 DRILL STRING DESIGN
Drill pipe design (cont.)
Other drillpipe solicitations that usually are not considered for drill pipe
design are :
1-Torsion: only a consideration in highly deviated wells,
2-Burst : will be only a consideration when carrying out a DST or when
applying pressure to unplug obstructions inside drill string ( ex; plugged
bit nozzles). But even in these situations it is unlikely that the pressure
applied will exceed the burst resistance of the drill pipe.

Other design factors like shock loading, stretch of pipe and critical
rotating speed need to be considered for a more compreensive design.

Therefore to design a column of DP it is usually only necessary to

calculate the collapse and tension loads. With that information it is then
possible to select the suitable DP weight and grade .

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 3. THE DRILL STRING
3.4 DRILL STRING DESIGN
Drill pipe design (cont.)

(Courtesy of E. Hossain ) 72
 3. THE DRILL STRING
3.4 DRILL STRING EXERCISES
-

DRILL STRING EXERCISE #1

While drilling at 8,000.ft with a 9 7/8” bit, the wellsite geologist
requested to circulate for samples. The string in hole consisted of 7500
ft of 5”, 19.5 lbm/ft of drill pipe and 500 ft of 8” OD by 2.75”ID drill
collars. Assuming that the hole remains in gauge, calculate the number
of pump cycles required to circulate bottoms up.
The triplex pump factor is 0.1781 bbl/cycle.

In field units :

Ap= d²/1029.4 bbl/ft

Aa= (d2²-d1²)/1029.4 bbl/ft

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 3. THE DRILL STRING
3.4 DRILL STRING DESIGN
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DRILL STRING DESIGN EXERCISE #2

The suplier of a 12 ¼” bit recommends that a weight of 25,000lbs be

applied on the bit to optimize the rate of penetration. The well is full
with mud weighting 12.2 ppg.
The driller wants to know how many drill collars 9 ½”OD x 2 13/16”
ID have to be run to obtain 25,000lbs on the bit and to keep the drill
pipe in tension.
The remainder of the drilling string is made of 10,000 ft of 5”,20.6
lb/ft Grade G DP with 4 ½” xtrahole tool joints.

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 3. THE DRILL STRING
3.4 DRILL STRING DESIGN
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DRILL STRING DESIGN EXERCISE#3

The drilling program for a vertical well to be drilled to 13,000ft will use a
drill string composed of 5” DP and 22 joints of 6 ¼” x 2 1/2” DC
( each joint is 30ft long).
The well will be drilled using 12ppg mud. The Overpull Margin ( MOP) is
set at 100,000lbs. The Company uses the following safety factors:
Collapse – 1.125
Tension – 85%.
The drill pipe available on location is :
- 15,000ft of 5” Grade E, 19,5lbs/ft and 10,000ft of 5 ½” Grade E
,25.6lbs/ft

Design the 5 “ drill pipe string.

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 3. THE DRILL STRING

END OF CHAPTER 3
In The Oilfield:
A SALESMAN starts out knowing a great deal about one thing and goes on
learning more and more about less and less, until he knows practically
everything about nothing.

An ENGINEER starts out knowing a little about many things and goes out
learning less and less about more and more, until he knows practically
nothing about everything

TOOLPUSHERS and COMPANYMEN start out knowing everything about

everything, but end up knowing nothing about nothing because of their
association with SALESMEN and ENGINEERS.

DRILLERS, on the other hand, know everything about everything and end
up knowing everything 'bout everything due to their total disregard of
advise given by SALESMEN, ENGINEERS, TOOLPUSHERS and COMPANYMEN

76