Fatigue of Drillstring: State of the Art
Oil & Gas Science and Technology - Rev. IFP, Vol.
Fatigue of Drillstring: State of the Art
- Fatigue of Drillstring: State of the Art - Failure due to fatigue is a very costly problem in oil and gas industry. Many investigators have previously addressed this problem, but its frequency of occurrence is still excessive. Torque and tension can be correctly predicted but computations of fatigue duration are still approximate. Regarding the fatigue failure of drillstring, this paper summarizes the state of the art. Prediction and calculation of fatigue duration are stated, including both history of the simplified approach based on Miner's rule and a few elements of the fracture mechanics theory. Existing inspection methods, their limitations and further recommendations are provided. Moreover, the fatigue tests are performed when human life and environment may be at risk. The loading conditions, the test frequency, the number and the size of test specimens are given. Environmental effects such as corrosion are recalled. Prevention and inhibitors are mentioned. Last chapter focuses on enhancement of drillstring. Drillpipes geometry improvement, connections re-design, steel properties such as toughness, tool-joints hardfacing and inspection of drillpipes are discussed.
Failure due to fatigue is a very costly problem in oil and gas
industry. Although many investigators have previously
addressed this problem, its frequency of occurrence is still
Drillstring failure occurs on 14-percent of all rigs and the
resulting downtime costs roughly $106 000 per event [1, 2].
A survey of all drilling problems reported worldwide over a
15-month period shows that 36-percent were due to stuck
pipe. Stuck pipe cost estimates for the worldwide drilling
industry range as high as $250 million for this period .
Hill has analyzed 76 drillstring failures from 1987 to 1990
on three continents . These incidents are costly because of
the loss of rig time, tubular goods and even the well in some
time. In 1992, one in seven wells are concerned. Failure
causes can be estimated as follows.
– Fatigue is the main cause in 65-percent of the failures and
has a significant impact in 12-percent.
– Combined excessive tension and torque give failures in
13-percent of the cases.
– Low toughness of material is mentioned for only 8-percent
of the failures.
The same conclusion is issued in  where 73-percent of
inspected drillpipes were defective because of fatigue cracks.
Torque and tension are correctly estimated but fatigue is
still an approximate skill.
Mechanical stresses in drillstem, environmental and
unusual conditions, such as corrosive mud, horizontal well,
etc., should be predicted as accurately as possible in order to
define the best drillstring assembly and then reduce fatigue
failure. Planning an inspection program, before and while
drilling is an important step. Monitoring results while drilling
and tripping should be compared with theoretical models.
The first two points are developed in Section 1 and 2.
Fatigue tests, presented in Section 3, are necessary to have a
better understanding of both steel and equipment behavior.
Environmental conditions are listed in Section 4 but this is
not the main subject of this paper. Section 5 focuses on
improvement on drillstring, on manufacturing methodology
and on material properties. Anyway, state of the art,
limitations and improvement will be underlined.
1 FATIGUE CALCULATIONS
Fatigue damage is due to the reversed variations of the
stresses, such as those induced when the drillpipe rotates in a
curved section of a wellbore. Rotating a buckled pipe may
also lead to rapid fatigue failure (Fig. 1). Fatigue troubles can
be estimated from the number of cycles associated with the
amplitude of the stress cycles.
Drilling in Rotary
Bending in buckled area
Bending in dogleg
in buckled area
The material is indeed characterized by S-N curve also
called Wöhler curve where stress amplitude (S) is given
versus the maximum allowable number of cycles (log Nf),
(Fig. 2). Failure is likely to occur when the working number
of cycles is equal to the allowable number of cycles Nf. Other
representations are the Haigh diagram (Fig. 3)  or the
Reversed stress amplitude
for a fully
where c0 is the curvature of the drillpipe body near to the
tool-joint, c, the permissible curvature of the dogleg (DLS)
and L, half the length of the drillpipe. Note that gravity forces
are neglected hereabove. K is given by:
K = 2
c0 E ⋅ d
σb = 2
Goodman diagram . Cyclic stress amplitude is given
versus average stress.
Loads applied on the drillpipe should be known in order to
determine both permanent and cycling stresses. A calculation
methodology is presented in the next section. Using the
previous parameters, life duration can be estimated as detailed in
Section 1.3. Nevertheless, vibration effects will be neglected
as a first approach and we assume that they should be avoided
as much as possible. Anyway, the Institut français du pétrole
(IFP) is presently studying the effects of dynamic vibration
behavior of a complete drillstring using a finite element
software where large displacement and friction effects are
taken into account. For further details, refer to Section 6.
However, this simplified approach is empirical and lacks
the physical basis necessary to consider the fatigue as a
progressive and history dependent phenomenon. While
working, microscopic cracks come out in the structure. Those
cracks tend to gradually increase until their length is large
enough to create the drillpipes failure: washout or twist-off
may occur. Each step, initiation, propagation and failure can
be modeled as shown in Section 1.4.
In the present section, corrosion will be ignored as it is
described in Section 4.
1.2 Drillpipe Stresses
Most of the papers are based on Lubinski works [7, 8].
Regarding modified Goodman diagram, the reversed bending
stress is the cycle stress amplitude, which is given versus the
tensile or average stress.
In a modified Goodman diagram used at the endurance
level, Lubinski  assumed a reduction of the endurance limit
at low mean stress to allow for slip mark and wears on the
pipe body. In addition, he assumed a cutoff on the mean stress
level in noncorrosive mud at 67 ksi (462 MPa) (Fig. 4).
Therefore, maximum reversed bending stress can be
calculated in a maximum dogleg severity (DLS). Moreover,
the greater the average tensile stress, the smaller is the
maximum bending stress that the drillpipe may withstand.
Using modified Goodman diagram and tensile stress,
maximum allowable reversed bending stress can be figured
out. A maximum permissible dogleg severity can be found
when resolving the differential equation of the elastic
arc-ofcircle line for a given dogleg. This maximum allowable DLS
is dependent on axial tensile load, weight on bit, weight on
hook, bending moment and length between tool-joints and
reaction force on wall at contact point. To simulate the
relatively large bending stiffness of the tool-joint, the ends of
the drillpipes were fully restrained. Main results for drillpipes
under tension are as follows:
c0 = c
where T is the axial tension force, E, the modulus of elasticity
of pipe material and I, the moment of inertia of the cross
section of the drillpipe body.
The bending stress is finally given by:
where d is the diameter of the drillpipe body. Complete
relationships for any other drillpipes configurations in dogleg
are available in .
Lubinski has defined curves where the permissible dogleg
severity, below which no fatigue damage of drillpipes may
occur, can be estimated from the tensile load and the
drillpipes characteristics. These curves used to prevent static
failure are the bases of the “API-RP-7G”  (API is the
American Petroleum Institute).
] presents a model and a summary of Lubinski
works. For the jointed drillpipes located in a dogleg, the axial
tensile load tends to straighten the middle portion of the pipe.
Therefore, maximum bending stress is located next to the
tool-joint (Fig. 5). Regarding these maximum-bending
stresses, assumption is performed that the drillpipe body does
not contact the wellbore wall. If axial tensile loads are small,
the drillpipe weight becomes dominant: the maximum
bending stress may be located in the middle of the drillpipe.
The axial compressive load tends to deflect further the
middle portion of the pipe, where the maximum bending
stress may occur (Fig. 6). Moreover, the maximum bending
stresses calculated as before are on the conservative side
because the drillpipe bending deflection is confined within
the wellbore. No further calculations are carried out in order
to take into account several contact points in the pipe body.
Based on field failure data analysis, full scale fatigue
testing and finite element analyses, Sheppard [
that maximum bending stresses are in the vicinity of
Some authors suggest improvement on the Lubinski’s
model. Wu [
] or Paslay [
] add an “arc” boundary
condition, as the contact is not a perfect point. Howard [
overlays the well geometry by a sinusoidal profile in order to
better model the bottom hole assembly (BHA) crooked
This approach is empirical as calculation is performed in
the local dogleg area where the contact points are supposed
to be known. Assuming a corrosive or a notching
environment, the S-N curve used by Lubinski was modified by
reducing or canceling endurance limits. Because S-N curve is
the basic building block for this model, these effects may
ruin this theory. Moreover, they did not account the threaded
tool-joints as being a critical section; the whole analysis was
concerned with drillpipes. Anyway it does not address the
specification of cost-efficient nondestructive inspection
intervals to avoid fatigue .
Regarding extended reach drilling, Smith [
] and Hill
] have studied the reversed bending stress when the pipe
is buckled. The tension state, the stability forces and the
mechanical characteristics of the hole affect buckling.
The methodology to check buckling is the following:
– Check whether the drillpipe is buckled? Drillpipe areas
which are likely to buckle are above the bottom hole
assembly and above any severe dogleg. The drillpipe
remains stable as long as the magnitude of mechanical
compression does not exceed the critical buckling load
– If pipe is buckled, can we lower the weight on bit in order
to reduce the compression forces?
– If weight on bit cannot be decreased, buckling tolerant
components such as heavy weight drillpipes should be
introduced in the buckled areas.
This paragraph will focus on the critical buckling load
calculation. Assuming that stability and pressure forces are
ignored, i.e side loads applied on drillpipe body,
DawsonPasley relationship [
] is used provided that the drillpipes
are rotated in a straight-wellbore. The critical buckling
load in a straight wellbore could be predicted by the
FC = 2
EIwKB sin θ
where E is the young modulus, I, the moment of inertia, w, the
weight percent length in air of a drillstring component, KB, the
mud buoyancy factor, θ, the hole inclination departure from
verticality, r, the radial clearance between pipe and hole.
Formula (4) is thought to be conservative [
] when the hole
is not enlarged, as it does not consider the benefit gained from
the presence of tool-joints on the drillpipe.
In curved wellbores such as building or dropping
wellbores, He and Kylingstad Equation [
] is used. The
equation for dimensionless buckling load is the following:
FC4 − (φ')2 + (θ')2 FC2 − 2θ' (FC ) − 1 = 0
wher–e F c is the dimensionless critical buckling load, φ and
and θ are respectively the dimensionless walk rate and build
rate. They are defined as follows.
φ' = φ'
θ' = θ'
βEI sin θ
rWb sin θ
where β is a constant (4 for sinusoidal buckling when
rotating, 8 for helical buckling when sliding), φ' is the walk
rate (deg/inches), θ' is the build rate (deg/inches) and θ is the
wellbore inclination (radians). Other values have the same
meaning as those described in Equation (4). Critical buckling
for curved wellbore is therefore determined by finding Fc the
largest positive real root of Equation (5), solving for the
Dawson-Paslay buckling load FC (Eq. (4)) and multiplying
With a hole angle greater than 68°, friction coefficient is
close to 0.4 [
]. Extra compressive axial forces must be
applied to the pipe to push and advance the string and to put
enough weight on the bit.
When designing drillstring and bottom hole assembly, the
following recommendations for reducing buckling and
vibrations should be respected.
The neutral point should be located in the larger diameter
bottom drill collars. Larger size of heavy weight drillpipe
(HWDP) should be introduced to reduce the section modulus
ratios close to 3:1 between the drill collars and the HWDP.
For further details, see Section 5.4. Stiffness or inertia
moment is increased by around 15-percent with spiraled
HWDP compared to the standard construction featuring only
one central upset. Straight hole conditions should be
maintained by running a packed hole assembly or a
pendulum, depending on drilling conditions (Fig. 7). Large
diameter drill collars, close to hole size, near the bit, would
supply weight for the bit and reduce bending in the
connections. Proper stabilization should be calculated to
prevent bending and whipping action. See Figures 7 to 9 for
further information. Rotary speed should be reduced as much
as possible, e.g. 80-90 rpm (rotations per minute), to reduce
whipping action. Stabilizers should be carefully selected as
well as diameter, blade profile, coverage and hardfacing in
order to maintain a constant hole diameter.
Anyway, buckling behavior and stabilization should
always be calculated: rotating a buckled drillstring should be
avoided as the reversed bending stress will lead to rapid
1.3 Life Duration
Lubinski and Hansford outstanding works [7, 8] are quite
useful to give figures for the design step, i.e. to predict the
best permissible dogleg. However cumulative damage and
failure prediction could be found out as they are based on
stresses histogram versus cycles number for each drillpipe.
Figure 10 gives one of the common methodologies to
estimate cumulative damage . Palmgren-Miner’s rule is
used, where the total damage is the addition of each damage
occurred at each cycle, regardless of pipe's previous load
history. However, it is known that the sequence of cyclic
loading could have an effect on the damage accumulation,
e.g., if the loading sequence is from low-to-high loads, then
cumulative damage could be more than 1; conversely, for
high-to-low loads, cumulative damage could be less than 1.
1 ft = 0.3048 m
Typical assemblies with several stabilizers in vertical hole.
Typical assemblies with one stabilizer in nonvertical hole.
] reports that fatigue life increases by 1.5-2.0
times for full-scale tests carried out under dynamic loads
lower than the fatigue limit.
The alternating bending stress should be increased by
stress concentration factor (SCF) provided that it is not
already accounted for in S-N curves. The stress concentration
factor is the ratio of maximum stress calculated (e.g. finite
element analysis) in the high loaded area to nominal
pipebody stress. For examples, Rahman [
] recommends SCFs
figures of 1.07, 1.15 and 1.6 respectively for die-marks depth
of 0.0004” (0.0102 mm), 0.0012” (0.0305 mm) and 0.01”
(0.254 mm). Therefore, dies of gripping system which mark
the pipe surface during making and breaking operation
should be minimized as they cause stress concentrations.
These SCFs can be computed by finite element analyses.
] indicates that maximum stress concentration
factors for standard internal-/external-/upset geometry are
1.19 for axial tension and 1.13 for pure bending.
Tafreshi and Dover [
] have carried out finite element
analyses on several standard tool-joints. SCF figures are
given for standard and modified NC46 connections.
Maximum SCF may vary within a range of 3.29 to 8.56,
depending on the pin or box thread profile.
Anyway, all flaws should be reflected by appropriate
stress concentration factors.
After evaluation of a stress concentration factor, a safety
factor should be applied to account for static, dynamic,
vibration loads, corrosion, make-up torque, etc. Baryshnikov
] recommends a safety factor between 1.5 to 2.0
depending on the drilling technology and well conditions.
Empirical functions exist such as the following equation,
given in [
M fl 1 −
where Ks is the safety factor, Mfl, the fatigue limit as a
bending moment, M , the largest long-duration cyclic
bending load, Qt, the axial tensile load, and Qty, the
maximum axial tensile load for downhole tool yield.
While drilling, one of the equations that gives the number
of cycles that pipe has experienced in a dogleg is also given
by Zeren [
n = 60 ⋅ rpm ⋅
where n is the number of cycles, rpm, the rotary speed, L, the
dogleg interval (ft) and DR, the drilling rate (ft/h). Note that
one foot equals 0.3048 m.
The fatigue damage after passing a dogleg at known
tension and curvature is:
where n is the number of cycles, N, the total useful life
(in cycles). N is given by S-N curve at the stress level
corresponding to borehole curvature and pipe tension.
While drilling, more damage is done at higher rotary
speed (rpm) and at lower drilling rate. The fatigue damage is
inversely linearly proportional to the drilling rate and
proportional to rpm.
During rotating off bottom, the fatigue damage is not
negligible in the pipe passing through a given dogleg interval.
Existing fatigue damage for a given drillpipe will be
added to damage cumulated when passing “new” dogleg
] has compared Lubinski’s life duration
results with a finite element analysis: Lubinski’s approach is
conservative due to the fact that he has ignored the
secondorder nonlinear effects of contact. Thus, the bending stress
is overestimated whereas the noncorrosive S-N curves are
] alters the bending stress by a ratio in order to
take into account mean stress due to nominal tension. The
modification is based on Goodman line where the ratio R
depends on axial stress σm and ultimate tensile strength of
drillpipe material Su as follows:
SU − σ m
This approach uses finite element analyses in a local
] changes the typical S-N curves to take into
account the effects of axial load. The Goodman line is used
to consider this mean stress effect as axial tensile load
reduces fatigue bending stress whereas axial compressive
load increases fatigue bending stress (Fig. 11).
S-N curves must also be modified to reflect corrosion
effect. This is the Section 4 purpose.
1.4 Fracture Mechanics
Due to the increase of fracture mechanics studies, fatigue life
duration of structure highly loaded in low cycles can be
predicted quite accurately. High reversed bending loads and
low cycles fatigue may modify the steel hardening essentially
made for high tensile loads. Theory  developed hereunder
is at ambient temperature i.e. without corrosion nor creeping
effects. Plastic viscosity is negligible as well.
Life duration of a structure can be broken down in three
main stages as recalled in Figures 12 and 13. Firstly, under
cyclic stresses, accommodation is the prevalent mode.
Initiation is the next step when microscopic cracks appear
near surface discontinuity and grow across several grains
controlled mainly by shear stresses. These phases correspond
to roughly more than 80-percent of life duration and
unfortunately they can hardly be reliably inspected. Keeping
cyclic loads, one of the microscopic cracks will grow. It is
perpendicular to and controlled by the maximum tensile
stress. Propagation of this crack leads rapidly to failure by
either brittle fracture or gross plastic deformation. High stress
concentration areas such as threaded connections, upset area
or slip die-marks tend to accelerate the crack propagation.
The total predicted fatigue life is the addition of the
fatigue-crack-initiation duration NI plus the
fatigue-crackpropagation duration NP.
Fatigue life calculation using fracture mechanics can be
summarized as follows:
1 estimation of stress history as a function of time σ(t);
2 representation of the stress history by ni stress ranges σ∆ i
at ni cycles;
Further details are given hereunder regarding point 3.
The stress-concentrated area ahead of a notch root, such as
die-mark, thread root or groove, is the location where
accumulation of dislocations yields to initiation of a
microscopic crack at the surface.
The theoretical stress concentration factor should be used
as proposed by Ikiwa and Ohira and reported by Placido [
where the micro-discontinuities are considered as notches.
The equation is the following:
where Kt is the approximated theoretical stress concentration
factor, t is the notch depth and r, the notch tip radius. Less
conservatively, the notch factor Kf proposed by Peterson is
also given by Placido [
] as follows:
where a is the length parameter estimated for steel by
Kt = 1 + 2
Kf = 1 +
Kt − 1
a = σu
where a is in inches and σu is the ultimate tensile strength in
ksi. Note that one inch equals 25.4 mm and one ksi equals
Point 4 is developed hereafter. The fatigue-crack-initiation
life NI is calculated for a threaded connection by
elastoplastic finite element analyses as a function of the stress
parameter according to relationship (15):
NI = K [σ∆ r(d 0)]
where K and n are constant depending on steel characteristics
and determined by fatigue tests. Parameter d0 is a distance
measured from the notch root. These parameters are
independent of the tool-joint geometry but they only depend
on the steel properties. ∆σ r is the reversed stress or the
representation of the stress history range.
The crack initiation size ai is the initial fault size, which
can be measured by microscope for example.
The mean stress has significant impact on the fatigue
crack-initiation life [
], particularly when the cyclic stress is
small. The fatigue initiation life is usually a function of the
completely reversed stress or strain amplitude. The tensile
mean stress increases the effective or equivalent completely
reversed stress and then shortens fatigue life. Chen [
a mean stress of 80-percent yield strength to simulate
makeup torque stress in the pin, and 40 to 50-percent yield
strength to simulate make-up torque stress in the box. He
proposes an equation to predict the mean stress effects as a
geometric mean of Morrow and Smith's equation as follows:
σ∆ r = σa
((σ + σa ) ⋅ σa ) 2
where the first factor is given by Morrow's Equation and the
second one by Smith's Equation. σ∆ r is again the equivalent
completely reversed stress amplitude, σa, the applied stress
amplitude, σ–, the applied mean stress and Ms, a fatigue
The fatigue-crack-propagation life (point 5) is calculated
from the predicted crack-initiation size ai to a critical crack
size, aC, or to penetration of wall thickness, whichever occurs
first. This oligocyclic propagation is given by Paris’s
], which yields a crack distance of progression per
cycle as follows:
= C ⋅ ∆ K n
where C and n are coefficient depending on steel
characteristics. Paris’s law is the representation of the central part
of the da/dN versus ∆ K curve as represented in Figure 14.
However, there are two asymptotes. The first one is defining
final failure (18), the second one is a threshold Kth below
which crack propagation is said to be null (19).
KI → KIc ⇒
KI → Kth ⇒
Lemaître and Chaboche propose a modified-Paris’s law
which includes the latest limits [
]. Mean stress is not
correctly represented in Paris’s law, but it can be easily
corrected by a polynomial coefficient [
Final failure is characterized by criterion KI as per
relationship (20), where for each failure area, a critical fault
size noted a is measured. Calculus shows that:
with σr, the reversed stress applied, and Q is called flaw
shape parameter. Ertas [
] proposes the following
estimation of Q:
As a conclusion, the method presented in this section is
more accurate than the Miner's law but the condition aF > aC
is determinist. Moreover, close to the threshold, the Paris’s
law is not available for calculation due to the asymptote
Another improvement is the probabilistic approach. The
method is the same as the latest but stress history is a
spectrum of stresses and spectral calculation uses Fourier
] concludes that fracture approach is less
conservative than cumulative fatigue damage approach.
Wall thickness (WT)
Leak before failure
Crack growths from size aI to aF
aF = WT
Semi-eliptical surface crack in drillpipe.
However, S-N curve plus Miner’s rule is still largely used
because this method is quite easy to use. But S-N curves are
the average of a band obtained from the scatter of a large
number of plotted points, and they are representative of
reduced scale specimens failure.
2 METHODOLOGY AND INSPECTION
The purpose of this section is to describe existing inspection
methods, their limitation and then to provide
Hill has issued interesting studies [
] on inspection and
qualification of drillpipes. Due to the additional economic
risks of deep, hard or horizontal drilling, the inspection and
acceptance of drillstring components should be based on
their compliance with API and user standard.
Proper drillstring inspection should not be considered as
reliable according to a “report” or a “certification” because
API guidelines or quality control steps may not be followed
by Inspection Companies. Moreover, API standards for used
drillstem may not take into account deep or critical drilling.
2.2 Inspection Procedure
Inspection can be broken down in three steps [
– determining the acceptance standards to be applied;
– deciding which inspection methods will be used by
contractor and then conducted by inspection contractor;
– ensuring that the inspections are performed correctly in
economically involving the operator.
Point 2 is unfortunately not addressed in “API-RP-7G”
. This quality process control should always be specified;
Hill has defined complete recommendations in “Standard
], where a category from 1 through 5 is stated. For
further details, see the Section “Inspection Tables” in [
Likewise, Shell Expro and Exxon [
] have issued a North
Sea inspection specification document. Table 1 summarizes
the inspection methods given in this specification (see also
Figs 16 to 18).
] reports that point 3 can be monitored according
to three levels depending on the probability of confidence
in getting what the customer has asked: specifying, auditing
or enforcing. Local company personnel or third party
inspection services to supplement local inspection services
should be required if necessary. Audits will also extend to
machine and fabrication shops to ensure components are
refurbished and manufactured in accordance with the
The customer is responsible for listing the drillstem to be
inspected, setting the inspection program and acceptance
Typical flaws in drillpipe.
3- Inspection of swell (bell shape)
2- Wall thickness of shoulder
2- Visual inspection of shoulder
2- Visual inspection of threads profile
Optional inspection recommended.
criteria. Therefore, he specifies inspection apparatus,
preparation of drillpipes, calibration, standardization and
inspection procedure. The inspector is responsible to
examine each piece listed in strict compliance with the
processes. The inspector accepts or rejects each piece based
on whether its attributes meet the customer's acceptance
criteria. All the results must be communicated.
A partly inspection is not recommended but if decided, a
representative sample should be selected and an acceptable
reject rate should be stated.
2.3 Methods and Specifications
Specific characteristics of drillstring inspection methods are
pointed out by Kahil [
]. The inspection of tubular strings is
clearly divided into new pipe inspection, aimed at the
detection of manufacturing defects, and used pipe inspection,
aimed at the detection of service induced defects.
The most common defects found in new pipe are tight
spiraling seams, jagged overlaps and slug-pits of irregular
shape. Wall thickness is not said to be a major problem. As
the surface is generally smooth and free of scale, contact
inspection apparatus can be used.
New component specifications widely used are for
example SQAIR (Shell Quality And Inspection Requirements),
NORSOK (North Sea recommendations; note that
NORSOK was closed down the 7th June 2000 following a
decision made by OLF and TBL Offshore the 25th February
2000), “API Specification 5D” [
] (for tubes and upset
definition), “API-RP-7G”  (for drill collar and tool-joints
definition) for acceptance criteria and “API-RP-5A5” [
for inspection procedure. However, API does not address
any specification for heavy weight drillpipes, jars, motors,
underreamers, hole openers, kellys, subs, stabilizers, etc.
Table 2 lists some important properties of drillstring
]. Table 3 recalls the properties covered by
API specifications, as per [
The most common defects in used pipes depend on the
application. Usually corrosion pits, transverse fatigue cracks,
starting cracks, holes, diameter reduction and nonstandard
dimensions can be detected. Due to high service loads or
remachining, drillstring dimensions can be changed in
diameter, in tool-joint length, in taper (pin length or box
depth), in bevels diameter or in wrench bearing. The surface
of used pipes is generally rough because of corrosion and
mechanical damage, and is often covered with scale, mud,
paraffin and other contaminants. Therefore, cleaning must be
planned and contact probes should be used with care.
Existing specifications for used component are
“API-RP7G”  for acceptance criteria and “Standard DS-1” [
inspection process quality control.
The acceptance criteria are broken down in three drillpipe
classes: Class 1 or new pipe, Premium Class or 80-percent as
strong in tension and torsion as nominal new drillpipe with
standard sized tool-joints, Class 2 drillpipe or 70-percent as
strong in tension and torsion as nominal new drillpipe with
standard sized tool-joints. Hill [
] has added another class
(i.e. Premium Class with reduced torsion strength ratio)
which recognizes long-standing industry practice of using
smaller tool-joints outside diameter to gain better fishing
clearance (see Table 4 for further details). When
“API-RP7G”  was first issued, Class 3 and Class 4 were considered
usable in many circles, but by now they are considered too
worn for most needs.
Many inspection methods are available, their
characteristics are compared in Table 5 as per Hill [
ultrasonic and electromagnetic methods will be mainly
described hereunder. Anyway, visual inspection should
always be performed for all inspections.
Minimum yield strength
Minimum tensile strength
Maximum yield strength
Internal upset geometry
Determines the stress concentration effect of the change in wall section at the internal upset on a
drillpipe tube. This in turn affects the fatigue life of the tube (higher stress and then shorter life)
(1) Minimum remaining wall thickness must be ≥80% under transverse cuts and gouges.
(2) Cuts and gouges may be removed by grinding provided the remaining wall is not reduced below the minimum remaining wall shown in this table.
(3) Average adjacent wall is determined by averaging the wall thickness on each side of the imperfection adjacent to the deepest penetration.
(4) OD is outside diameter.
(5) TSR is tensile strength ratio.
(6) ≤0.006" in 2" is equivalent to ≤0.1524 mm in 50.8 mm.
Common inspection methods for used drillpipes and BHA(3) components (as per Hill [
(1) OD is outside diameter.
(2) MPI is magnetic particle inspection.
(3) BHA is bottom hole assembly.
(4) BSR is bending strength ratio.
(5) BOP is blow out preventer.
2.4 Visual Inspection
Ultrasonic wall thickness
Dry magnetic particle inspection (MPI(2))
of end areas
Electronic end area inspection
Wet magnetic particle inspection (MPI(2))
Wet magnetic particle inspection (MPI(2))
Disassembly and visual
Wet MPI internal threads
Fatigue cracks, corrosion pits, mechanical damage
OD(1) wear, crushing, necking, swell
Fatigue cracks in end areas
Fatigue cracks, corrosion pits, mechanical damage
in end areas
Mechanical damage, weight/grade identification
Mechanical damage, wear
Fatigue cracks in threads
Mechanical damage, wear, inadequate BSR(4)
Fatigue cracks in threads
Fatigue cracks in threads
Improper components, worn or damaged components
Naked-eye examinations can detect gross fatigue cracks and
thread damage, particularly with the aid of a profile gauge.
However, they may not detect the discontinuities. Therefore,
inspection should not be limited to a visual examination.
Visual inspection is required for internal and external
surface inspection of drillpipe tubes. Surface imperfections
and coating wears should be notified. Crooked pipe must be
rejected. Pipe outside diameter can also be inspected using an
OD gauge, (note that OD is outside diameter). Accuracy is
close to ±0.002 inch (±0.0508 mm) [
Upset external surface, seal, threads, hardfacing, bevel,
box swell, box shoulder width, pin stretch, tong space,
shoulder flatness, etc., should be visually inspected.
Regarding refacing of pin or box threads, their pitch
diameter should be equal in order to avoid any thread
interference and subsequent leaks. API refacing benchmarks
show the position of the original shoulder, so the inspector
can determine if too much refacing has occurred. An audit of
local machine shop facilities including equipment and skilled
personnel should be made to determine the availability of
qualified service [
2.5 Electromagnetic Inspection
Electromagnetic methods are widely employed as they can
be used in different ways.
Electromagnetic inspection (EMI) is a widespread method
used to locate three-dimensional flaws. The system could be
made up of a motorized drive unit which has an inspection
head scanner. The head is encircled by a strong active field
DC (direct current) electromagnet. As the drive unit moves
along the length of the tubular, the head sends signals from
suspected defect locations back to the chart recorder where
they are displayed graphically. Upon passing over a
discontinuity in the induced magnetic flux path, a wire search
coil may be excited with a voltage in any of eight shoes
located in the head.
However, the search coils have a great sensitivity to speed
changes, they have a dead point at the ends and the output
signal is nonlinear. Erroneous signals may be received due to
abrupt changes in wall thickness at the transition area. Wade
] proposes to improve the latest method by using a
solid state sensor and its associated electronics packaged in
integrated circuit chips.
] thinks that EMI is not reliable enough as
further prove-up is typically necessary, for example by using
magnetic particle application.
The Wellhead Scanalog described by Kahil from Baker
Hugues Tubular Services [
] is a computerized system for
the inspection of used tubing at the wellhead during a trip.
Corrosion pitting are detected and measured by a
magnetic method: the magnetization of the pipe is provided
by stationary coil arrays distributed around the pipe and
driven by computer-controlled currents in order to produce a
rotating magnetic field. Signal detection is provided by
separate stationary coil arrays and it is based on magnetic
flux leakage method.
A low-frequency eddy-current scan is added for the
detection and identification of full-penetration holes and splits.
The cross-sectional area of the pipe and therefore the wall
thickness is measured by using a new magnetic flux density
However, detection threshold, which is not provided in
], might be higher than the crack initiation size.
This inspection method is essentially based on a wall
The MPI (wet fluorescent magnetic particle or black-light
inspection) is conducted by Hill [
] to detect transverse
surface flaws in tool-joints. Magnetic flux, created by a DC
coil, an AC (alternating current) coil or an AC yoke, leaks
out in the presence of a sharp geometric discontinuity, e.g. a
fatigue crack. This flux leakage attracts and holds soft iron
particle suspended in a liquid carrier and poured or sprayed
onto the test piece. The iron particles are coated with a
fluorescent material that shines brightly when the surface is
viewed under ultraviolet or black light.
An expert should conduct this method because results are
dependent on the strength of the field (flux density), on
particle concentration and on black-light intensity. An active
field method is therefore recommended. As described in
Section 3.5 (item 1), this method can also be performed for
crack detection on small-scale test specimen.
Penetrative dye inspection [
] is used to examine
connections that cannot be inspected with MPI. Like in
magnetic particle methods, a dye carrying liquid is applied to
the surface and allowed to penetrate surface discontinuities.
After removal of excess remaining fluid, a developer blotting
powder is applied. Visible indications are drawn when the
penetrating fluid moves out of defaults. This inspection is an
expert-method mostly used for surface flaws detection in
nonmagnetic BHA tool-joints.
Moreover, the penetrative methods are slow processes that
require more than 30 min for a complete penetration of the
fluid. Smooth and clean surface is required. Discontinuities
require to be open to the surface to be detectable, but the best
resolution is close to 0.005 inch (0.127 mm) [
2.6 Ultrasonic Inspection
Ultrasonic inspection is mentioned by Stanley [
] as a more
accurate method than MPI. Anyway, it is mainly based on a
wall thickness measurement.
In the piezoelectric technology, widely employed for its
efficiency in ultrasonic, ultra sound is generated by a
ferroelectric ceramic which transforms electrical energy in
mechanical energy. This sound is fired in the material via a
thin coupling fluid such as oil or water based liquid.
One of the following ultrasonic methods presented
hereunder is performed using a contact sensor [
Transverse fatigue cracks may be detected in the critical
areas of the drillpipe tube with a shear wave ultrasonic
system that fires sound toward the upset region. It detects
sound reflected from imperfections. Time to cover the
distance between receiver and transmitter heads is measured;
it is directly proportional to the wall thickness. Flaws are
detected by an array of several transducers with sound beams
overlapping. Detection of a notch approximately 0.1 inch
(2.54 mm) deep is the best sensitivity obtainable. Horbeek
 reports that the main difference in cost between
“APIRP-7G”  and the Shell Expro Drillstring Inspection
Specification was the ultrasonic inspection of the drillpipe
upset area with an increased average cost of £11.20 per joint
of drillstring inspected. “API-RP-7G”  does not address
this type of inspection in this critical area, where the majority
of drillpipe fatigue failures may occur.
Regarding probe selection [
], a high frequency
transducer, e.g. 5 MHz, provides better resolution, but attenuation
and noise limit its penetration. Frequency below 2.25 MHz
may not provide enough resolution. For a given frequency, a
large probe diameter gives less beam spread and better
penetration of the material, but sacrifices some resolution.
The most useful probes appear to be those with diameters
between 0.25 inch and 0.5 inch (between 6.35 mm and
12.7 mm) with frequencies of 2.25 or 5 MHz. Surface
condition such as machining grooves, galling and stabbing
damage or corrosion, pits and gouges can increase the scatter
of results and make coupling difficult. Probe orientation also
greatly affects the sensitivity. Thus, specialized equipment
and highly trained personnel are required.
] proposes another version of ultrasonic
measurement dedicated for crack inspection in threaded
box connections. The use of a 4-degree wedge allows
compression wave ultrasound of frequency around 10 MHz
to enter the ends of a shouldered connection at a suitable
angle for directing the beam along the roots of the threads.
The reflections should be observed on an appropriate screen
so that the sound reaches the last threads, and small
indications at regular intervals can be seen from ultrasound
diffracted from each thread.
Another ultrasonic inspection available is a
noncontactsensor method as described in [
]. Regarding benefit, no
coupling-fluid is required and surface to be inspected can be
quite rough. The ultra sonic imager tool (USIT) was
introduced by Ananto to evaluate the quality of the cement
around the casing and at the same time measure the internal
radius and the thickness of the casing, even when the casing
is not round or inside high-deviated wellbore. Oil or water
base mud is necessary as it is a transmission liquid. These
measurements are performed in five-degree increments
around the casing. The transducer located in the rotating
head, spins at 6.5 to 7.5 revolutions per second. The
maximum vertical resolution of the measurement is 2 inches
(50.8 mm). However, this method may not be accurate
enough for fatigue crack detection, as it was not developed
for such a use.
In order to avoid any coupling fluid as well as
contactsensor, the Centre technique des industries mécaniques
] has developed an electromagnetic-ultrasonic
inspection method, called EMAT. Impulsive and
highintensity eddy currents are generated by a coil in the steel. A
Lorentz’s force is created from interaction between these
eddy currents and a magnetic field created by permanent
magnets. This Lorentz’s force is directly applied to the
current lines and then is transmitted to the material atoms by
ultra sounds. Generated sounds propagate through material
and perturbed echoes are measured in the same way.
Frequency is 2.5 MHz. However, this interesting method has
not been conducted yet in field and may be adapted for
drilling inspection environment.
It is important to note that a reference standard is needed
to calibrate the ultrasonic instruments for distance and
As a conclusion, some standardization of existing
inspection procedures in the industry is necessary as
consistency and repeatability of inspection results is to be
achieved. Nevertheless, some other inspection methods may
be investigated as they may enhance the existing procedures.
2.7 Quality and Frequency of Inspection Methods
Conventional inspection methods as already described allow
detection of only macroscopic cracks. Many referenced
papers confirm this. Propagation of fatigue cracks, which
represents a few percent of the remaining life before failure,
is the only detectable step.
As per Dale [
], electromagnetic inspection method
applied on drillpipe body has a probability of detection
(POD) of 90-percent providing that crack depth is larger than
0.039 inch (1 mm). POD is close to 99-percent when
minimum crack depth is 0.049 inch (1.25 mm). These figures
are not available for tool-joint inspection. POD represents the
combined effects of inspection methodology, human factors,
equipment variability and measurement repeatability.
Magnetic-particle inspection mainly applied for connection
inspection has a probability of detection of only 40-percent.
This method is highly dependent on the way the inspection
procedure is carried out and how the inspector operates. For
], a Linalog service inspector will spend two to
three years in training, in the field or in the classroom, before
taking up a supervisory or advisory role. Unfortunately, most
of the fatigue failures occur in the tool-joints area.
Based on these results, Dale proposes the following
example on the pipe body inspection [
]. If three
inspections are planned during life duration of a drillpipe,
probability of detection of cracks in body is 90-percent. If six
inspections are performed, POD increases to 99-percent.
This probability of detection figure is available for only
one pipe. Probability of failure (POF) of the whole drillstring,
assuming n pipes, is given by (24).
1 – POF = (1 – POD)n
Therefore, existing standard inspection methods are far
from a high-reliable required method (e.g. POD of
Drillpipes should be inspected regularly in service life,
e.g. standard figures at every 200 to 300 rotating hours is
reported in [
] for entire bottom hole assembly,
including the first 20 drillpipes, every 1500 rotating hours for
the remaining drillpipes. For bottom hole assembly run in
extended reach wells, Yoder  recommends to increase
inspection frequency to a minimum of 150 rotating hours.
Life duration may be divided roughly in two stages:
incubation plus initiation of microscopic cracks is the first
stage, flaws are however considered undetectable. Second
step is the propagation of a macroscopic crack. Detection is
available but propagation duration is dramatically shorter
than initiation. Frequency of inspection should be planned
periodically using the cumulative fatigue calculations, the
fatigue crack growth rates, the probability of crack detection
and the engineering statistics, but must include the drilling
field limitations [
Formulae are existing to calculate life duration [
(25) where fatigue crack propagation may be expressed as a
function of cyclic bending stress σb, outside diameter D,
crack plane diameter dc, and fatigue constants F0 and n,
depending on steel characteristics (typically 7.25 105 < F0
< 1.35 106, 2.52 < n < 2.94).
N = F0 D
] has issued a tool to estimate the
performance of a given drillstem with small set of data. It is
based on Blom’s algorithm, see (26), which gives the
decrease estimation of the probability of success of an item i
R(ti ) =
where R is a reliability estimator and we suppose a small set
of n failures occurred at certain time ti. For each drillstring
component, a reliability threshold that can be met with proper
tuning of the non-destructive tests has been established.
Hill has reported  that many of the inspection failures
experienced in the field are not caused by technical
limitations but are the consequence of the poor application of
the methods. The inspection contractor frequently operates in
a conflict of interest environment.
] reports an interesting example of failures and
lost time per well with and without nondestructive tests
Due to the low reliability of the existing inspection
methods and the lack of standard recommendations, we do
believe that the field is still open to improvement.
2.8 Flaws Detected
built into drillpipes tool-joints and upset areas, the adjacent
tube body is more susceptible to the rotary stresses of
A statistical analysis given in [
] notifies that failures are
located in the 920 mm-area from the box or pin ends.
Anyway, most of the failures are in a zone between 250 mm
and 640 mm from the ends.
Failures initiated from threads are often reported. Based in
the latest statistical analysis , areas are located between 0
and 120 mm from the ends. However, the number of thread
failures is lower than the nonthreads failures.
As a conclusion of this section, geometrical defaults are
always involved in fatigue failure. Geometrical defects can
be summarized as follows:
– Length of tool-joints may be modified by remachining.
– Tool-joints geometry: bevel length must be larger than
API recommendations, bevel diameter should not be to
strong when remachining, length for wrench must
be adapted, die-marks of gripping system must be
minimized. Some companies discard drillpipes when
die-mark depth is higher than 0.02 inch to 0.0315 inch
(0.5 mm to 0.8 mm).
– Tool-joint inside geometry: diameter reduction should be
carried out with a conical profile with a minimum length
of 0.492 inch (12.5 mm).
– Tensile residual stresses when tool-joint is welded on pipe
body could be the location of fatigue cracks [
and heating are cheap and easy solutions if correctly
3 FATIGUE TESTS
In conditions where human life and the environment may be
at risk, equipment is usually tested in laboratory under
dynamic and static load conditions. Fatigue tests are
recommended to better understand material characteristics as
well as to reflect downhole conditions, which may cause
damage. They are one of the first steps for modelisation of
both cumulative fatigue damage and fracture approaches. The
main aspects to be considered are the loading conditions, the
test frequency and the number and the size of test specimens.
Static load test results are usually compared to the
mechanical characteristics guaranteed by the manufacturer
and in practice failures due to static loads are quite rare.
However, strength in dynamic load conditions is not studied
in depth and therefore fatigue test should be carried out.
Fatigue test results obtained under controlled load
conditions are used to define the familiar fatigue S-N curve.
For tools that do not have an asymptote towards horizontal
(endurance limit) in the S-N curve, the fatigue limit is usually
chosen as the load amplitude corresponding to a life of 107
cycles for steel and 2.107 cycles for nonferrous metals [
These figures are the minimum number of cycles
recommended by Baryshnikov as a basis for fatigue tests for
downhole equipment. Sometimes full-scale comparative
fatigue tests are carried out without obtaining the fatigue
limits. These results are interesting only if the dynamic load
level corresponds to an actual downhole dynamic load
3.2 Nature of the Different Tests
Three types of fatigue tests are usually conducted:
– Cyclic axial tension tests are performed on a
servohydraulic test machine (Fig. 19). This had a built-in load
cell connected to the servo-control loop, which maintained
constant amplitude loading, regardless of the axial
displacement. Load, displacement or strain should be
servo-hydraulic computer-controlled [
6, 52, 53
] using any
cycle shapes such as ramp, sinus, square signal, etc.
Quality control must be focused on specimen
endmounting, alignment of gripping system, calibration of
cells and PID (pipe internal diameter). When specimen
stiffness may change during test, algorithm including
adaptive PID must be carried out in order to balance load
– Simple bending fatigue tests are described by Grondin
. Specimens are tested in flexure using a span with
two-point loading in the central portion of the span. A
servo-hydraulic jack applies fluctuating loads on the
loading points via a distributing beam. Load is cycled
such that the stress at the bottom fiber of the specimen in
the constant moment region varied from maximum to
minimum tension. A superimposed static axial load can
also be applied to simulate the weight of the drillstring at a
– Rotating bending tests with or without axial tensile loads
are also available in [
1, 2, 21, 52
]. See Figure 20 for
further details. On a four-point bending situation,
hydraulic jacks applied constant loads on the center of the
string creating a permanent deflection and thus bending
loads. One end mounting is structurally fixed. An axial
load can be added if wanted. A variable frequency
electric motor is connected to the other end to provide
fully reversed cyclic stressing of the stem. Pipe body
should be instrumented with load cells and strain gauges
Regarding full-scale fatigue tests on connections,
] reports an interesting case history where he
discusses the experience of downhole tool full-scale fatigue
tests published since 1950. A lack of requirements for fatigue
tests in existing specifications causes significant dispersion of
the results and no database is available.
Fatigue testing machine (compressive and tensile loads).
3.3 Specimens Size
Many papers refer to full-scale tests [
1, 2, 19, 21, 52, 54-56
To obtain a better simulation of field operating conditions,
full-size fatigue tests should be conducted. No scale effects
intercede with the results providing that applied loads reflect
drillpipe stresses encountered in wellbore. Specimens can be
easily prepared so that the whole tool-joint, upset region and
part of the pipe body could be included in the test. High
stress areas, discontinuities, microscopic characteristics of
steel (e.g. inclusion and grain sizes) as well as tensile axial
loads are accurately represented at full size. However,
specific testing rig must be created.
Tests on samples at reduced scale are sufficient to obtain
material characteristics such as S-N curves and endurance
]. These specimens can be easily machined
providing that shape, dimensions and manufacturing
procedures are respected, e.g. as per . Moreover, standard
testing machines are widely available on the market.
For S-N curves determination, specimens should be
cylindrical and have toroïdal profile . Final machining is a
longitudinal and fine adjusting. Specimen heat is hence easily
removable and failure is located in the calibrated area.
It is worth to mention that fatigue S-N curves are not
meant to be a definite line but the average of a band obtained
from the scatter of a large number of plotted points. This
band is broad at the upper left where the stress loads are high
and tapers downward in a curved fashion to a narrow band at
the right part of the diagram at the fatigue endurance level.
For oligocyclic fatigue, parameters of elastoplastic
material laws can also be fitted from small-scale sample tests
conducted in constant strain amplitude for example.
This paper will not discuss in detail the geometry and the
use of the notched specimens whereas they are widely
employed for fatigue crack propagation tests. Crack lateral
location coupons such as KT (tension test specimen), KF
(bending test specimen), CT and RCT (compact tension test
specimens) and crack central location coupons (CCT) are the
most employed specimens  (see Figures 21 and 22 for
further details on geometry). CT coupons are tested in
corrosive environment by Gonzalez-Rodriguez [
] or Hatcher
] because of space limitations in the autoclave. Crack root
geometry is also important as crack initiation and propagation
is shape dependent. Rafter shape is widely used. Prior to
testing, the specimens should be abraded to a 600-grade
emery finish and degreased with acetone [
Test frequency at full-size should be from 0 to 7 Hz as the
bending reversed stresses are a quite low frequency
W 4 < W/B < 8
W 2 < W/B < 8
H = 0.6 W
H1 = 0.325 W
Under corrosive environment, tests should be carried out
at low frequency, lower than 1.5 Hz, in order to have a better
flow of the corrosive fluid in the crack root [
21, 50, 53
frequency upper than 5 Hz, corrosion effects should be
]. It is worth to mention that pH can be
modified by H2SO4 (sulfuric acid) or NaOH (caustic soda) —
respectively for acid or basic adjustment in an autoclave
nitrogen-pressurized brine environment [
At reduced scale, if specimen is not heated by itself and if
testing machine is still reliable, frequency can be increased to
50 Hz in air and noncorrosive environment .
The main procedures conducted to detect cracks on tested
specimens and monitor their propagation can be split into
two sections: with or without precalibration. Some methods
are common with those described in Section 2.
Nonprecalibrated systems are the following:
– Magnetic particle inspection (MPI) or black light
inspection is mostly used [
] for carbon steel
drillpipes inspection, but it can be easily conducted to
detect and monitor cracks on full-scale specimens. In this
process, the component is magnetized and sprayed with a
medium containing magnetic particles in suspension.
These particles move preferentially on surface defects.
Under an UV light, the surface breaks can be seen as
bright lines. Therefore, surface should be polished and
cleaned as close to bright metal as possible. Regarding the
drawbacks, the process detects only surface defaults and
hence no depth can be measured except with grinding.
Fatigue cracks almost invariably began at the root of the
grooves introduced by grinding when these marks were
φ < 5 mm
Lateral crack small-size specimens (as per ).
Central crack small-size specimen (as per ).
oriented transverse to the direction of loading [
Therefore, surface grinding was found to introduce a
notch effect and modifies residual stresses in the surface
layer. Moreover, accessibility can be a major problem, e.g.
when cracks are monitored in box connection.
– Optical measurement such as magnifying binocular
system is recalled as it is one of the simplest devices.
Magnifying ratio of 30 to 80 allows crack propagation
measurement of 0.1 mm . A calibrated grid microscope
can be set up for visual inspection of compliance during
the tests conducted in air .
– Eddy-currents are created in specimen using two coils
mounted in a Wheatstone bridge. Perturbations of the
signal induce a small displacement of the sensor along the
crack and then measurement of surface crack propagation
with an accuracy of 0.05 mm. However, precision will
be lost if material is said to be unstable or when striction
of specimen is large enough (e.g. due to local plasticity in
the crack root area) to induce a current decrease
independently of crack propagation .
– Ladder-shape thin gauges mounted in parallel and bonded
along the crack will progressively failed as soon as
propagation occurs. Measurement is performed in surface and
high velocity of propagation can be monitored (between
0.0001 and 1 mm/cycle for a 0.5 mm gauge interval) .
– Utrasonic wave measurement is based on the displacement
of a 10 MHz sensor. Precision is 0.01 to 0.03 mm .
Precalibrated systems are mainly based on current field
– Direct current (with intensity from 5 to 50 A) or
alternating current potential difference (e.g. square tension
signal) have been in common use for offshore structure
and aerospace inspection for several years. The methods
are based on detection of anomalies in a current flow
along a metal surface [
– Alternating current field measurement (ACFM) has been
recently conducted by Gaynor [
]. ACFM induced an
electrical field on the metal surface of the component. If a
perturbation is detected in the magnetic field created in the
free space above the surface, a crack or defect is present.
The severity of any break can be determined by measuring
perturbations in the magnetic field. Length and depth can
then be estimated.
Current field measurement methods allow monitoring of
cracks in surface as well as in depth. Accuracy is about
0.05 mm for carbon steel. Moreover, system can be used
on all metals, at any temperature.
ACFM does not require an experienced operator as it is
recommended for MPI thread inspection [
– A gauge can be added to measure the crack mouth
opening displacement (CMOD) especially for
highstrength less-tensile steel [
2, 6, 50, 53
]. This CMOD
gauge can be used for ambient tests in air as well as in
pressurized environment such as in an autoclave system.
– Brennan  and Dale  have used beach-marking
technique. It is based on fracture surface inspection. In
order to determine the rate of fatigue crack growth, a
procedure is used to generate marks on the fracture
surface at prescribed intervals by employing cyclic load
reductions. These beach marks recorded crack shape and
position from which measurement and calculation of
fatigue crack growth rate where made.
3.6 Precraking Method
In order to accelerate tests and reduce the time to initiate a
fatigue crack, specimens should be cracked before starting
Material can be precracked by a high electric shock, e.g.
by an electric-discharge-machining (EDM) as used by Dale
. EDM has been used to produce a small starter notch in
the thread roots of connections. This flaw serves as a crack
initiation site and results in propagating fatigue crack at the
beginning of each test.
] has decided to precrack compact
tension specimens in air at a frequency of 20 Hz with a
sinusoidal waveform for the applied load using a closed-loop
electro-hydraulic testing system. The compliance method
was applied to find out the crack length as an empirical
function of the applied load and the crack opening
displacement. Applied load is measured by means of a load
cell and the crack displacement with a clip gauge situated at
the mouth of the specimen (CMOD gauge).
During the test, crack propagation velocity can be adjusted
by frequency (from 1 to 150 Hz) and applied load .
3.7 Open Literature Results
Some fatigue test results at full size are recalled in [
Characteristics of steel tested are also mentioned in papers
50, 52, 56
4 ENVIRONMENT EFFECTS
Corrosion probably plays a role in all drillstring fatigue
failures. This section will list the environment effects and
their consequence on the fatigue behavior of the drillstring.
Prevention and mud inhibitors will be discussed.
4.1 Corrosion Fatigue Factors
] has investigated drilling mud parameters that affect
corrosion fatigue life. They are the following.
Dissolved oxygen is the main cause of drillpipe corrosion.
As little as 3 ppm dissolved oxygen cut fatigue life by as
much as one-half compared with mud without dissolved
Increasing CO2 (carbon dioxide) concentration also
reduces fatigue life but not as rapidly as increasing dissolved
The pH has appreciable effects on fatigue life beyond a
pH of 10.5. Anyway, mud pH control is necessary.
] has reported rapid failure through hydrogen
embrittlement in drilling muds containing H2S. Under the
harmful action of H2S, hydrogen atoms diffuse easily into
steel and accumulate as molecular hydrogen in voids on the
interface of nonmetallic inclusion and matrices. By the action
of stress, a mechanical crack initiates from the pit and
propagates through the hydrogen-embrittled area. These
microcracks tend to connect and form a continuous crack.
] has studied influence of
temperature, chlorides level and pH in water-based drilling
mud. Moreover, he has tested specimens in zinc or copper
environment: lubricants containing metallic zinc or copper
are used to prevent galling of the threaded joints.
Conclusions are the following. Increasing chloride concentration
reduces fatigue life. The degree of susceptibility to corrosion
fatigue increases with decreasing potential and pH. With
increasing temperature up to 80°C and addition of
Zncontaining dope (25% in weight), the crack growth rate is
increased as well as the steady state hydrogen permeation
current density. Similarly, the addition of Cu-containing dope
(25% in weight) decreases the value of hydrogen, and also
decreases the crack propagation rate.
4.2 Corrosion Effects
Hill  reports at least two corrosion effects:
– corrosion accelerates the crack initiation phase by creating
high stress areas;
– corrosion can accelerate the crack growth rate by attacking
the newly exposed metal at the crack tip.
Moreover, corrosion reduces or eliminates the endurance
limit of any S-N curves. The corrosion fatigue cracks seem to
invariably start at the corroded interface between the MnS
inclusions and the matrix [
] and then grow under the cyclic
As already stated in Section 3.4, the lower is the
frequency, the more are increased the corrosion effects.
H S (hydrogen sulfide) precursor effects were noticed by
], which is in accordance with pipe exposure
to hydrogen sulfide. One of these effects, only measured in
laboratory tests, is a decrease in elastic stiffness of the pipe.
The second effect reported is an increase in the bulk
electrical resistance of specimens exposed to H2S.
4.3 Prevention and Inhibitors
Enhancement of steel characteristics such as nitriding
and nitrocarburizing thermochemical surface treatment,
phosphatization, and oxidation treatment may delay the
corrosion effects. Better chemistry, quenching and tempering
to a low hardness would make steel more resistant to sulfide
stress corrosion cracking and also more resistant to hydrogen
Nitrocarburizing involves the diffusional addition of both
nitrogen and carbon to a steel surface at temperatures
typically between 510°C and 590°C, in gaseous and plasma
atmospheres and in salt baths [
]. Additional improvements
of wear resistance, fatigue strength and corrosion resistance
are attributed to oxidation treatment at temperature below
570°C after the nitrocarburizing treatment, as per [
Because mean stresses are known to be an important
factor in corrosive environment, compressive stresses applied
on high stress concentration areas of drillpipes may restrain
the crack propagation. These residual stresses can be applied
mechanically by light grinding or polishing for example, but
this partly reduces the corrosion resistance gained by the
oxide layer. Nitriding and nitrocarburizing also lead to the
formation of compressive residual stresses in the surface
microstructure, moreover this compound layer acts as an
Coating of both internal and external side of drillpipe may
protect steel from corrosive and abrasive environment such
as mud. A sacrificial cathode such as aluminum or zinc
coating might diminish the potential difference and then
increase the fatigue life despite the H+ accumulation.
Double-shoulders connections may help to avoid any mud
penetration in the thread roots.
Corrosion inhibitors and scavengers directly added in the
mud are another way to improve the fatigue life. pH should be
maintained at 10.5 or higher to help prevent corrosion .
Caustic soda should be used to control pH, not lime. Lime
causes a scale to form on the drillpipe outside diameter, which
causes corrosion . Regarding H2S-containing mud,
inhibitors, such as zinc oxide or zinc carbonate, suppress the
hydrogen ion discharge reaction, which releases hydrogen atoms in
the crack tip and then diffuses them into steel. The hydrogen
sulfide concentration in the drilling mud should be monitored
using a Garrett Gas Train as per “API-RP-13B” [
Regarding polymer mud, O2 scavengers, such as catalyzed
ammonium bisulfite, would reduce crack initiation and growth.
Chemical injection pumps designed for continuous
treatment should be purchased and installed [
]. A batch
mixing and storing reserve mud in a separate surface tank
should be designed. Extra time is available to release air and
foam before adding the mixture. The mud is then added to
the active system without mixing additives and make-up
water through the hopper system.
Protection methods must be investigated in order to reduce
the corrosion effects.
Another way to monitor and prevent corrosion effects
is to insert small coupons inside the drillpipes and then
to periodically check their shape. “API-RP-13B” [
provides information on the use of corrosion coupon rings.
When selecting mud, most of the drilling engineers focus
on parameters that influence hole stability, penetration, well
control and formation compatibility. To prevent fatigue,
corrosion parameters must be highlighted on the list of mud
Because corrosion can cause localized pitting on the pipe
surfaces, which act as stress concentration areas and crack
initiation sites, it is of major importance of monitoring and
keeping drillpipe surfaces clear of these pits.
5 HOW TO IMPROVE DRILLSTRING
It is not the purpose to present herein new designs of
drillstring or to present comparative tests on existing designs,
although actual basic fatigue data on various designs seems
to be lacking. Rather, it is intended to present information
regarding possible methods of improvement which are
applicable to almost any drillstem design. Section will be
divided in five parts as follows. Firstly, drillpipe, drill collar
and heavy weight drillpipe improvements will be listed. Next
chapter will present how the connections may be enhanced as
well as the characteristics of steel. Finally, classification and
marking will be discussed.
5.1 Drillpipe Improvement
Drillpipes (DP) are engineered to work in tension, to transmit
torque to the bit and to resist to internal pressure due to mud
Regarding manufacturing of drillpipes, they are made of
three parts. The pipe body is welded on the two threaded
ends. Thickness of welded cross section is increased by
forging because of the friction weld.
These forged sections and mainly the upset regions are
highly loaded. Improvement in these areas are described in
most of the paper and are discussed hereafter.
Many authors [
] agree that the internal upset
transition region of drillpipes is a singular area where stress
First and last engaged thread roots
concentration factors are the greatest. Figures 23 and 24 show
the critical drillstring fatigue areas. The problem is amplified
further by poor application of the internal plastic coating
where corrosion protection is then lost.
] noticed that 93-percent of the drillpipes
failures were near the ends of the pipe body, in the internal
upset runout area. The failure distribution was 40-percent on
the box and 60-percent on the pin end.
Noble Drilling [
] recorded 18 premature failures
in one drilling pipe string in the first 2800 rotating hours
where normal life expectancy was 18 000 h. Most of the
failed pipes had an internal taper upset length of less than
Geometry changes are recommended on the length of the
upset region (Miu length i.e. minimum internal upset length)
but also on the radius between the drillpipe inside diameter
and the tapered portion of the offset. Based on finite element
analyses and on full-scale fatigue tests (size tested is 5” pipe
diameter, i.e. 127 mm pipe diameter), conclusion is to
increase transition length and radius as much as possible.
Upset design concept is based on the following: the
maximum stress at any point in the bore of the pipe is less
than the maximum stress at any point on the outside
diameter. This insures that crack initiation will be on the
outside surface, which is easier to detect with normal
inspection methods. Stress concentration factor (SCF), which
is the ratio of the inside maximum stress to the outside
maximum stress, should be less than 1.0. These studies
resulted in the adoption of a 2-inch (50.8 mm) minimum Miu
length for Grade E 4 1/2-inch (114.3 mm), 16.60 livres/ft
(24.7 kg/m) drillpipe in “API Specification 5D” [
], in April
1989. No API recommendations are issued for the other
grades. However, SQAIR includes a single minimum internal
upset taper length of 3.15 inches (80 mm) covering all
drillpipes grades, sizes and weights [
According to Wilson , the stress concentration factor
in the upset region can be reduced if new stress relief
tooljoint is designed. Fatigue life of new stress relief tool-joint
added with the long taper upset as described previously is
approximately four times the life duration of the API upset
drillpipe. Anyway, addition of 2 1/2 inches (63.5 mm) of
Internal - External
Critical drillstring fatigue areas.
steel is needed in the weld neck of the tool-joint in order to
machine the relief groove. These stress relief grooves in the
tool-joint reduce the stiffness and allow some flexing,
thereby reducing the bending stresses in the drillpipe tube
and in the weld area.
Wilson  presents a new drillpipe design in order to
reduce slip damage problems. Slips are engineered to bite
into the pipe to prevent it from slipping down the hole while
connections are made up or broken out. Slip cuts are the
cause of high stress concentration factor in the drillpipe
body (see also Section 1.3). These die-marks are well known
to initiate the fatigue cracks. The proposed solution consists
of a thick wall tube being welded in between the box
tooljoint and the drillpipe upset. This tube has the same wall
thickness as the drillpipe upset and the tool-joint weld neck.
Length is about 3 ft (0.914 m) so the gripping system can be
set on the thick wall section. Crushing and bending would
be improved, as die-marks will not be located in the high
] note that the current allowable wall thickness
tolerance is 12.5-percent. This means that the margin for
erosion, corrosion and mechanical damage is very short
before pipe is reclassified to Class 2 condition. Specifying
5-percent tolerance should be available and acceptable for
most of the pipe manufacturers.
Based on Lubinski's  analytical work, Zeren [
that one of the most important factors affecting the bending
of pipe in a dogleg is the distance between two tool-joints.
Because it eliminates the problems caused by contact of the
pipe with wall of the borehole and therefore reduce the
bending stresses, adding one or two protectors, i.e. thickened
section the same diameter as the tool-joint is a solution for
pipe fatigue improvement.
] has reported the following rate. Approximately
87-percent of all drillpipes failures occurred within 4 stands
of the top of the HWDP. Based on these figures, it is
recommended to move the bottom 4-5 stands of drillpipes on
each trip. Moving the fatigued pipe to a less stressful location
should extend the time to failure.
5.2 Drill Collar Improvement
Drill collars (DC) are designed to work under compressive
loads, to transmit torque to the bit and to resist to internal
pressure due to mud flow.
They are trepanned from forged bars. Internal hole is
bored and turned. Threaded connections are directly
machined on the rod, and most of the time cold rolling is
used. Coldworking of the roots of the threads produces
residual compressive stresses, which increase the resistance
to initiation of fatigue cracks of about 40-percent. Further,
gall resistant coating should be applied on new and reworked
Improvement is focused on threaded connections,
particularly on the last engaged threads because they are the
weakest points of the drill collars (Fig. 23). Sweet [
reported that 77-percent of the drillstring failures were in the
BHA. Approximately 75-percent of the drill collar failures
occurred in the bottom (back) of the box connections, near
the last engaged thread.
A few papers have dealt with redesigning threads to
reduce stress concentration, but most of them restrict
interchangeability with API standard connections.
] proposes to redesign the last engaged thread
(LET) of the pin by reducing its height of about 70-percent
(Fig. 25). This is a quite simple method which allows
interchangeability with any standard API connections and
then reduces stress concentration on the thread roots. Finite
element analyses plus full-scale tests on a four-point bending
fatigue testing machine have confirmed this design. The
practicability of this connection was tested through
overmake-up, make-and-break and full-size tensile and
rotating tests. The fatigue limit of the redesigned connection
is 1.13 times greater than that of the standard connection.
However, it cannot prevent any box failure at the LET.
This type of failure could be avoided by stress relief grooves.
Weiner  suggests machining an external stress relief
groove in the unengaged portion of the pin and box threads.
These stress relief grooves pin or bore back box reduce the
stiffness and then allow some flexing. A direct issue is the
reduction of the stress concentration factor and then the
bending stresses in the drill collar connections. However, it
reduces the number of recut and threads remachining. The
optimum relief groove, as per , should have a diameter
which has a cross sectional amount of inertia of about
30-percent of the cross sectional moment of inertia of the
drill collar. See Figures 26 and 27 for further details.
Fullsize fatigue tests were conducted on a rotating-bending
machine, where the specimens were strain gauges monitored.
Testing results show that external stress relief groove
connections have life duration 10-times greater than
APIInternal Flush (IF) modified connections. For information,
API-IF means API-IF connections where the internal
diameter is constant. API-IF modified connection has
internal relief grooves machined at the last engaged thread
roots. Note that API-IF connections might now be obsolete.
Based on a detailed two-dimensional finite element
analysis, Knight [
] has shown that any stress concentration
combined with a modest amount of bore eccentricity in the
drill collar may result in a notable reduction in the fatigue life.
Whereas the lack of recommendations on drill collar bore
eccentricity , the bore eccentricity, combined with bending
loads, is an important parameter which govern the fatigue life.
] recalls that on large diameter connections,
the low torque face feature is available for drill collar outside
diameter larger than 9-inches (228.6 mm). The low torque
face is designed to decrease the make-up torque required and
Redesign of the last engaged thread (LET).
Boreback stress-relief feature
API pin stress-relief feature
Box and pin stress relief feature.
Tool-joint weld neck stress relief groove.
to increase the bearing stress on the shoulder. Impermeability
of the connection is then improved. Compressive stress area
of the box is reduced by machining the box to a larger
diameter, but tensile stress area remains unchanged in the pin.
Wilson  recommends using drill collars close to hole
size to reduce bending stresses in the connections and to
provide a stiff BHA for controlling deviation. Tapering the
drill collar is also important to reduce stress.
5.3 Heavy Weight Drillpipe Improvement
Heavy weight drillpipe (HWDP) can withstand tension
and compressive loads. They are also calculated to transmit
the torque to the bit and resist internal pressure due to the
Variation of the cross section inertia of the whole
drillstring is reduced when HWDP are run between drill
collars and drillpipes. Kirk [
] recommend that the polar
section modulus (PSM) ratio should be used to control this
change in cross section. The PSM is defined as follows:
where D is the outside diameter and d, the inside diameter.
PSM ratio should not exceed 5.5 in normal drilling condition
and 3.5 in a corrosive environment.
Moreover in extended reach wells, HWDP increase the
weight on bit if they are run in the vertical section of the hole,
whereas drill collars are nearly horizontal and their weight on
bit is then very low. The buoyed drillstring weight must be
multiplied by the cosine of the angle of inclination to
determine the amount of usable bit weight. In horizontal
wells, drillpipes are sometimes run in compression: drill
collars or HWDP must be placed in the vertical or near
vertical section of the hole to provide a component of weight
for the bit. By using lightweight drillpipes in the horizontal
section of the hole, there is less torque and drag which allows
drilling a longer horizontal section of hole. But when too
much weight is applied, the drillpipes will buckle and
HWDP are made of three parts. Two threaded connections
are welded on a forged, bored and turned rod.
Available papers are very poor on HWDP improvement as
they are mainly focused on drillpipes and drill collars.
However, Schock [
] proposes to modify the
conventional manufacturing procedures. The HWDP are made of a
homogeneous one-piece forging of AISI 4145 modified low
alloy steel. This integral rotary forging eliminates the weld at
the tool-joint, because threads are directly machined on the
rod. This HWDP has high strength steel pipe and has a center
upset the same diameter as the connection upset. The larger
center upset tends to reduce bending loads and can be easily
rebuilt. Taper area can also be easily remachined if
necessary. Rotary forging provides a smooth grain flow
through tapered areas and allows heat treatments.
Continuous-line heat-treating increases the depth of
hardening to improve the material mechanical properties.
Complete transformation to martensite is achieved. This
HWDP should enhance fatigue life and reduce stress
corrosion cracking tendencies due to the lack of welds.
This is not the purpose of this paper to describe all the
connection nomenclatures and formulae associated, but
general information will be reported hereafter. In this case
the most effective methods to increase connections reliability
consist in the optimization of the make-up torque and the
selection of the most suitable rotary shouldered connection
under certain drilling conditions.
Long thread root radius should be required such as NC
(numbered connection), REG (regular) , H90 (Hughes 90)
but obsolete connections such as IF or FH (full hole) must be
avoided. For further details, see [
] or [
and selection of the best-shouldered connections should be
calculated with the bending strength ratio BSR, which
compares the box and pin stiffness.
where Z is the section modulus [
BSR = Zbox
Zbox = 0.098
Zpin = 0.098
(D4 − b 4)
(R 4 − d 4)
where D is the outside diameter, b, the box thread root
diameter at pin end, R, the thread root diameter of pin threads
3/4 inch (19.05 mm) from the shoulder, and d, inside
diameter of pin.
“API-RP-7G”  recommends that BSR varies within the
range of 2.25 through 2.75. The lower figure means a weak
box whereas the higher threshold means a weak pin.
] and Hill [
] propose other BSR figures
such as 1.9 to 3.2.
Based on full-scale fatigue test results, Baryshnikov [
proposes to enhance the bending strength ratio: the ratio of a
box versus pin fatigue limits (FSR) provides the real fatigue
resistance in a given environment and allows the selection of
the most suitable connections. FSR definition is as follows.
FSR = M box
where Mbox is the calculated box fatigue limit as a bending
moment for a connection and Mpin is the calculated pin
fatigue limit as a bending moment for a connection due to
optimum make-up. Mbox and Mpin depend on connection
fullscale fatigue test results. This method should be quite useful
providing that a full-scale fatigue database of all the
tooljoints is existing. However, fatigue tests on threaded joints
are usually very costly and time-consuming compared to a
calculation approach, e.g. using finite element analysis and
Most standard tool-joints are weaker in torsion than the
tubes to which they are welded. All API tool-joints, except
those on HWDP or those in Grade E 75, have the same
minimum yield strength of 120 000 psi (827.4 MPa),
regardless of the grade of pipe to which they are attached.
Therefore, make-up torque for connections is determined
only by the tool-joint pin internal diameter or box outside
diameter. Make-up torque of a tool-joint is the maximum
torque to be applied on the drillstring and not the torque
capacity of the tool-joint. Make-up puts elastic stretch in pin
and compression in box. Recommended make-up torque for
rotary shouldered connections is the amount of torque
required to achieve a 60-percent of its minimum yield
strength, i.e. 72 000 psi (496.4 MPa) for used tool-joints. For
new tool-joint, intended for break-in only, 50-percent of its
minimum yield strength is required. 57-percent for drill
collars with diameters of less than 7” (177.8 mm) and
62-percent for drill collars with diameters of more than 7”
(177.8 mm) are recommended by “API-RP-7G” . API
make-up torque figures should be taken from tables given in
] or [
] proposes to calculate the optimal
makeup torque value from the actual material yield strength and
not the minimum yield strength as suggested by API .
If pin and box are not correctly preloaded, the seals may
separate under downhole side loads. If insufficient preload is
applied, the torque shoulder may open allowing drilling fluid
to pass through the threads and across the torque shoulder.
This effect called wobbling may lead to washout, then
rapidly to failure. Likewise, excessive make-up torque will
result in high tool-joint stresses and can also lead to more
rapid fatigue failure. A basic rule to avoid downhole
makeup is to limit operational design torque value lower than
make-up torque value.
“API-RP-7G” Equations  are defined with a safety
factor of 1.1. Bailey [
] has reported that this safety margin
may not be sufficient for cases involving high pressure,
severe bending or downhole dysfunction caused by
Moreover, the friction factor of the thread dope must
always be reported, as the make-up torque equation should
be revised. Range is from 0.8 for lead or zinc based
compounds through 1.27 for copper based compounds [
The friction factor standard laboratory test procedure is
fully described in “API-RP-7A1” [
]. However, this API
recommendations is based on small diameter bolt results and
cannot be applied to correct the recommended make-up
torque directly at the rig site. The previous API version [
is closer to reality as it is based on full-scale tool-joint, but
it is not operative and not applicable at the rig site.
] proposes to evaluate periodically the
friction factor directly on the real connections at the rig site
using existing equipment and then correct the recommended
make-up torque value. This friction factor is determined as a
function of actual make-up and breakout torque periodically
measured on site.
] has reported that high-friction thread
compounds have now been successfully implemented on critical
extended reach well operations with increased make-up
torque. Baryshnikov [
] reports that friction factor may
widely change when threads get used. The API tool-joint
classification (New, Premium and Class 2) is based on
outside diameter variations and does not reflect the actual thread
state. Therefore, Baryshnikov recommends to periodically
establish a rotary shouldered connection friction capacity
depending on the number of make-up and break out carried
out during the drillstring service. Connection friction
capacity may vary within a large range, more than 50-percent,
during connection life and from one assembly to the other
]. Recommended make-up torque values are thus
corrected based on the thread connection wear classification
and the combined loads such as tension, torsion and make-up
In order to increase the drilling torque, the make-up torque
value should be increased with the remaining 40-percent of
pin yield capacity. But as make-up is increased, the pin is
exposed to higher tension at make-up and is then able to
support less subsequent applied tension. When the operating
tension can be confidently forecast and monitored below the
maximum tension available at nominal make-up torque,
torque capacity can be increased by an engineered reduction
in tension capacity.
It is worth to mention that Slack [
] has developed a new
contact pressure measurement technology. Application of
this measurement for connection make-up should
differentiate connections with inadequate prestress either due to
manufacturing out of tolerance, defects or insufficient
makeup torque or rotation. This method is based on an ultrasonic
reflection amplitude pressure correlation (URAP), and it
enables direct evaluation of the integrity of metal-to-metal
seals within premium connections.
Another way of increasing the torsion capacity of
tooljoints is the introduction of the multiple torque shoulders.
Double-shoulder tool-joints offer 40-60 percent higher
torsion capacity than conventional API single shoulder [
Further, they provide better hydraulic capacity due to their
Based on finite element analysis, Tafreshi and Dover [
have shown that a further decrease in stress concentration
factor (SCF) was possible with slight modification to the
thread geometry. Their results showed that the thread root
should not be modified for the box because it creates very
high SCF on unengaged teeth in the box, but some
improvement is possible for the pin. Assuming a constant
cutback, increasing root radius is recommended to reduce the
SCF, but a limit would be reached after which the SCF
increases. The maximum SCF in the first engaged tooth of
the pin depends on the ratio root radius r on cutback length L
(i.e. r/L) and reaches a minimum value when r/L = 0.8. Other
thread profiles have been analyzed through sensitive studies
using the following parameters: thread root radius r, blend
radius R, cutback length L and length of the pin stress relief.
Grant Prideco has put on the market the “H-Series
SST”, a proprietary pin connection that provides increased
durability and fatigue resistance. The SST involves a
modification to the pin thread only. The mating box thread
remains standard and the connection is completely
interchangeable with the standard API NC connections. The SST
pin incorporates two primary features. First, the thread form
has an enlarged root radius. Second, the pin thread body is
machined on a slightly flatter taper than that of the box,
effectively behaving like a variable pitch thread. These SST
features provide improved fatigue life.
Anyway, these analyses confirm that for any type of
loading the location of maximum SCF is at the root of the
first engaged tooth of the pin and the last engaged tooth of
5.5 Improvement of Steel Properties
Another way of improvement is to enhance the steel
mechanical properties instead of modifying the geometry.
Section 5.3 has proposed to use conventional AISI 4145
steel pipe with higher mechanical properties by changing the
manufacturing methods .
] suggests employing 165-ksi (1137.6 MPa)
grade material to redesign the drillpipes. The stress
concentrations at upset transitions were completely redesigned in
order to prevent any fatigue failures. With standard
tooljoints manufactured from 120 ksi (827.4 MPa) yield material,
a 165 ksi (1137.6 MPa) drillpipe product, with 165 ksi
(1137.6 MPa) tool-joints, offers a 38-percent increase in
tooljoint torque and tension capacities. The hydraulic loss
through the drillpipe was also considered. Moreover, the pipe
weight has been reduced by decrease of the wall thickness
using high strength steel. The author claims that the corrosion
fatigue property is superior to that of S-135 and the resistance
to high temperature is also good. Full-size tests such as
torsion tests, tensile tests, fatigue tests, burst and collapse
tests were conducted to validate the design. However, no
economic point of view versus standard drillpipes is
5.6 Aluminium and Titanium Alloys
A very few papers deal with aluminum drillpipe, as it is not
widely used (except in Russia). Glagola [
] recalls that
aluminum drillpipe provides solutions for many problems
encountered in directional drilling such as lighter weight than
steel, reduction of drillstring drag and torque, increase of
fatigue life, and therefore decrease of wears on tool-joint,
pipe body and casing. Aluminum has a great flexibility when
the drillstem is subjected to unusual stretching, bending and
twisting loads. However, Glagola has compared aluminum
with only E and D grade steel. Payne [
] stated that
aluminum drillpipe has not made the market penetration that
might have been anticipated, given its advantages over steel
drillpipe. Firstly, because the relatively low yield strength
compared to high strength steel limits its applicability in
complex wells. The aluminum alloy used for drillpipe has
yield strength of 58 000 psi (400 MPa). The tool-joints for
aluminum drillpipe are manufactured from steel. Secondly,
aluminum drillpipe requires new procedures for planning and
executing drilling operation. Moreover, Payne has reported
that several aluminum drillpipes have suffered significant
mid-body wear and corrosion problems, mainly due to mud
pH, chlorides and oxygen, high temperature and storage.
Mainly due to the reduced hookload capacity, the field is
open to optimized drillpipe design for extended reach wells
where the use of an aluminum drillpipe at the bottom of a
S-135 grade steel drillstring is possible. According to Grant
Prideco, aluminum cost is about 4-times the cost of a
comparable steel product.
Titanium drillpipes are described by Payne [
alloys have a lower density and elastic modulus than steel,
and can achieve higher yield strength. Advantages are the
weight saving combined with the increased buoyancy.
However, helical buckling and torsion twist remains an area
for further investigation due to its low elastic modulus. Wear
resistance is also very bad and the cost is about 8-10 times
the cost of a comparable steel product.
5.7 Tool-Joints Hardfacing
Regarding tool-joints abrasion, Schenato [
] recommends to
use tool-joints with consistent layers of hard material welded
on the external side, when drilling in abrasive deep hard
rocks. This can dramatically increase the fatigue life of the
connections and the worn out material in the tool-joint can be
easily restored. However, the selection of an appropriate
tooljoint hardfacing is critical, as the result can be a rapid casing
wearing. Payne [
] reports that chromium based hardmetals
eliminate casing wear problems compared to tungsten
] reports that 57-percent of the joints of the
Auger's drillstring had cracks in tool-joints. Heat checking is
the main cause of these discovered cracks. Heat checking
phenomenon can be explained as follows. After being heated
by friction, steel is quenched by the drilling fluid. Heating
above the critical temperature yields to austenite creation.
Rapid cooling of the metal transforms the austenite to hard
untempered martensite which is susceptible to crack
formation. Hardbanded tool-joints with metamorphic alloy
may help to reduce heat generation and thus heat checking.
Moreover, it has shown lower casing wears.
Another way to reduce heat checking is to decrease the
side loads, the velocity of tool-joints at contact surface and
EC = C(%) +
the coefficient of friction at this point. Side loads are a
function of drillstring tension and dogleg severity. Lubinski
has defined empirical curves in “API-RP-7G”  where the
lateral force on tool-joint is given versus the dogleg severity
and the buoyant weight suspended below the dogleg. These
curves are the only available data to estimate the maximum
allowable side loads without computer. Note that a flex joint
above a subsea blow out preventer (BOP) stack is said to be a
severe dogleg where the side loads are important. The
velocity at a point on the outside diameter is proportional to
the change in tool-joint outside diameter. The friction factor
depends on the mud being used, e.g. from 0.15 for an oil base
fluid to 0.33 for a water based fluid.
The same phenomenon is reported when hardbanding is
welded on tool-joints without pre-heating or post-heating.
Steel is heated during the welding and quenched by the air,
hard untempered martensite is then created from the
austenite. The equivalent carbon (EC) relationship is an
empirical relationship as recalled in (32) where percentage of
steel cheminal elements are taken into account. Pre- or
postheating is recommended when EC > 0.4%.
[Cr(%) + Mo(%) + V (%)] [Cu(%) + Ni(%)]
Toughness is a measure of material’s ability to resist crack or
notch extension. Thereby, tough material can sustain a larger
crack before final failure. “API Specification 5D” [
adopted in 1992 minimum toughness recommendations for
drillpipes. The Chevron Corporation has issued this
empirical criterion and it suggests 54 J at room temperature
for 3/4 size Charpy impacts. It is based on field observations.
However, no requirement is existing for tool-joints and
bottom hole assembly (BHA). Hill has reported that five of
the six brittle fractures observed in his study  occurred in
tool-joints or BHA connections. Therefore, minimum
toughness standard should be issued for the whole drillstem
including BHA and tool-joints.
] proposes the same approach. This has
allowed the application of a room temperature, 80 J, 3/4 size
Charpy criterion in Shell Canada drilling contracts.
However, material in accordance with Shell's criterion is 30
to 50-percent more expensive than API steel. Shell's
recommendations for HWDP and drill collars are an impact
resistance of 42 J at room temperature [
These reasonable requirements could mean the difference
between a detectable washout and a final twist-off. This
washout would be detectable by instrumentation and/or the
rig crew through the loss in mud pump pressure.
5.9 Classification and Marking
Most of the effort in drillstem design is usually concentrated
on the operating characteristics of the pipe and tools.
However, fatigue failure could be significantly reduced by
involving people both in planning, indexing and selecting
drillpipes with appropriate mechanical and performance
] focuses on the connections by analyzing
and identifying their characteristics in order to minimize
weaknesses. To reduce the risk of failure, the author
recommends to select the connectors based on the following:
– selecting the connection outside diameter based on a
wellby-well drilling plan, availability of drillstem equipment
and rig equipment capacities;
– optimizing the connection choice by checking coefficients
such as bending strength ratio, torsion strength and area
ratio and by selecting stress and damage resistant
– establishing operational limits for make-up torque,
dimensional wear limits and for external load capacity to identify
potential source of failure while the equipment is in use.
] insists on the pipe follow-up. People should
be involved in reliability enhancement as well as in
followup. Among all personnel, an awareness should be created and
procedures should be implemented to highlight how failures
occur and how they may be reduced. The development of a
standardized “Report Form” should be used for recording
and analyzing reported failures.
As per Horbeek [
], the greater awareness benefits are
made during drillstring failure prevention training courses. A
twist-off free footage award scheme has been achieved in
Shell's rigs in order to encourage washout detection by
everyone. Each twist-off costs Shell Expro on average
£250 000. Washout on the other hand cost ten times less than
]. New generation gauges which can utilize
“Smart Alarms” to account for the pressure lost when
washout occurs should be implemented. A further benefit
identified by Horbeek [
] was that the voltage generated by
the tool's turbine is proportional to the flow through it and as
such could be used to detect washout above the MWD
(measurement while drilling ) tool.
To improve the follow-up, Schenato from Agip [
proposes a two codes automatic system, one for the type of
pipe, and one for the pipe type numbering. Similarly, Shell
] has developed electronic pipe tagging and has
now more than a one-year field trial on two Brent platforms.
As per [
], Agip should set up an advanced drilling
information system. This expert system can help in decision
making support to both planning and supervision of drilling
activities. The first step is the creation of a historical database.
This step is essential, as fatigue failure is the result of
cumulative damages. Inspection results such as non-destructive
tests (NDT) should be included in this database. Further
improvement will be rig site sensors analysis as well as the
development of a data collection system.
Anyway, amount of logging-while-drilling data and
conventional wireline data collected are continuously
growing. Horbeek [
] reports that MWD shock logs can
warn of impending drillstring failure. Internal partnering
between drilling specialists and geologists may ensure that
only needed data is recorded. These data should be analyzed
at each step, then methodology would be improved as well
as planning. We are confident that a data base system such
as an electronic chip bonded on a drillpipe and wireless
linked to a computer able to read and write on this chip
is necessary to monitor fatigue using actual drilling
information as well as fatigue computation which are
described in the next section.
6 ON-GOING PROJECTS DEVELOPED
BY INSTITUT FRANÇAIS DU PÉTROLE
Institut français du pétrole (IFP) is currently working on a
global project where the fatigue of the drillpipes is
investigated with the cooperation of several companies
involved in the drilling industry. The aim is to issue
both recommendations regarding the fatigue failures and
enhancement on drillpipes geometry, steel properties and
fabrication procedures. This project is split in several tasks,
which are summarized hereunder.
6.1 Stresses Computation in a Whole Drillstem
The aim of this task is to compute the stresses in a whole
drillstem inside a borehole. A drilling package is being
developed from an in-house software which is existing and
validated. Specific boundary conditions can be introduced in
order to take into account the bit behavior.
The software enables to take into account the geometrical
definition of the bore and drillpipes as well as nonlinear
phenomena such as friction, contact and buckling in dynamic
conditions. Life duration and cumulative damage will be then
In the second year of the project, the vibrations will be
simulated through dynamic computation. Specific boundary
conditions on the bottom hole assembly (BHA) and bit will
be implemented to reflect the vibration dysfunction. They
will be validated using the Trafor database. Trafor is a
drilling equipment developed by IFP and dedicated to
record drilling parameters such as accelerations both near
the bit and on surface [
]. A large set of vibration
effects has been recorded during years of drilling campaigns
and is available.
A set of loads from a piece of the drillstring can be
imported in a finite element model as boundary conditions in
order to perform a local analysis.
6.2 Lab-Tests and Finite Element Analyses
IFP is testing coupons of 4145H steel in order to obtain the
S-N curves. These toroïdal specimens were machined from a
piece of drill collar at two radii: close to the wall and in the
metal core. They are tested in cyclic axial tension loading
with a stress ratio of R = 0.1.
Oligocyclic fatigue is the second set of tests performed by
IFP. Cylindrical coupons are tested in cyclic axial tension
loading with a constant strain amplitude. A nonlinear
elastoplastic model is then fitted for the 4145H steel in order to
model the elastoplasticity behavior in a finite element
Finite element analyses are performed using the Abaqus
software, including nonlinear material laws fitted with
labtests. A set of loads is imported from previous computations
in the whole drillstring. Enhancement of geometry such as
thread shape and taper, steel properties and fabrication
procedures (e.g. cold-rolling) could then be optimized for a
given load set obtained by computations carried out in
6.3 Failed Specimens Examination
Failed drillstrings are examined in order to issue detailed
analyses of the failures. The survey identifies the cracks, their
location, their cause, the way they initiate and propagate.
Analyses procedures and recommendations are being issued
in order to understand better the fatigue failure.
Recommendations are provided on:
– identifying and protecting the failed drillpipe;
– cleaning and transportation of the specimen;
– recording on-rig information;
– how to perform a complete examination including
destructive and nondestructive tests.
Inspection of failed-drillpipes will be carried out by this
project in order to understand better fatigue cracks location,
the way they initiate and propagate and how to improve
Fatigue in drillstring may occur if pipe is rotated and
crooked, i.e. bent, buckled or submitted to vibrations.
Cracks may appear in stress concentration areas such
as slip cut, upset area, thread roots or corrosion pits.
Improvements will be mainly focused on these points.
Autopsies on fatigue cracks should always be carried out.
Fatigue cracks can be recognized as they are most of the time
flat and orientated perpendicular to the pipe axis.
The following summarized the actions to reduce fatigue in
– Reduce cyclic stress level. Dogleg severity should be
monitored in order to calculate the cumulative damage.
Buckling should be avoided, mainly in drillpipes.
Vibrations should be reduced and monitored. Rotation
should be limited as much as possible.
– Reduce effects of stress concentrators. Most of the
drillstring new designs are achieved in these high stress
– Reduce corrosion effects. Corrosion should be monitored;
inhibitors and scavengers should be used.
– Increase material properties such as fracture toughness.
Washout before twist-off is then possible.
– Fatigue tests are carried out in order to validate material
characteristics and to test any new designs before using
downhole. Fatigue tests on small-scale samples should
allow cost and time reduction.
– Inspection procedure and standard should be specified.
Anyway, we believe there is a lack of standard
recommendations in all the previous points. Enhancement is
necessary in fatigue damage calculations, where dynamic
effects such as vibrations should be taken into account in the
whole drillstring. Connection design may be improved as
8th Annual International Energy Week Conference and
Exhibition, Houston, Texas, January 28-30.
Weiner, P.D. (1972) A Means of Increasing Drill Collar
Connection Life. Transactions of the ASME, Journal of
Engineering for Industry, ASME 72-Pet-65.
11 Joosten, M.W. ( 1985 ) New Study Shows How to Predict Accumulated Drillpipe Fatigue . Word Oil, October.
12 Dale, B.A. ( 1988 ) An Experimental Investigation of FatigueCrack Growth in Drillstring Tubulars . SPE Drilling Engineering , 356 - 362 , December.
13 ( 1992 ) Ten Ways to Reduce Drilling Costs . Petroleum Engineer International, September.
14 Hill, T.H. ( 1992 ) A Unified Approach to Drillstem Failure Prevention . SPE Drilling Engineering, December.
15 Pitts, J.P. Trip Inspection , Testing Gain Favor as Insurance . Drill Bit , 303 , 885 .
16 Lieurade, H.P. ( 1982 ) La pratique des essais de fatigue . Commission Fatigue des métaux de la SFM , Pyc Edition , Paris, France.
17 Lubinski, A. ( 1961 ) Maximum Permissible Doglegs in Rotary Boreholes . Journal of Petroleum Technology, February.
18 Hansford, J.E. and Lubinski , A. ( 1966 ) Cumulative Fatigue Damage of Drillpipe in Doglegs . Journal of Petroleum Technology, March.
19 API ( 1998 ) Recommended Practice for Drillstem Design and Operating Limits . API-RP-7G , 16th ed., August.
10 Wu, J. ( 1997 ) Model Predicts Drillpipe Fatigue in Horizontal Wells . Maurer Engineering Inc., Oil and Gas Journal, February 3 .
11 Shepard, J.S. ( 1992 ) Extended Drillpipe Life with Tighter Specifications . Global Marine Drilling Co., IADC/SPE 23843 , February .
12 Wu, J. ( 1996 ) Drill-Pipe Bending and Fatigue in Rotary Drilling of Horizontal Wells . Maurer Engineering Inc., SPE 37353, October .
13 Paslay, P.R. and Cernocky , E.P. ( 1991 ) Bending Stress Magnification in Constant Curvature Doglegs with Impact on Drillstring and Casing . SPE 22547, October .
14 Howard, J.A. ( 1993 ) Systematic Tracking of Fatigue and Crack Growth to Optimize Drillstring Reliability . Enertech Engineering and Research Co., SPE/IADC 25775, February .
15 Smith, J.E. ( 1992 ) Drillpipe for Horizontal Drilling . SPE 23990 , March .
16 Hill, T.H. ( 1995 ) Designing and Qualifying Drillstrings for Extended Reach Drilling . SPE/IADC 29349, Drilling Conference , Amsterdam, February 28-March 2.
17 Dawson, R. and Paslay, P.R. ( 1984 ) Drillpipe Buckling in Inclined Holes . Journal of Petroleum Technology, October.
18 He, X. and Kylingstad , A. ( 1993 ) Helical Buckling and Lock-up Conditions for Coiled Tubing in Curved Wells . SPE Asia-Pacific Oil and Gas Conference, SPE 25370 , February .
19 Baryshnikov, A. ( 1997 ) Downhole Tool Serviceability Under Dynamic Loads . Drilling Conference SPE/IADC 37647, Amsterdam, March 4-6.
20 Rahman, M.K. ( 1999 ) Stress Concentration Incorporated Fatigue Analysis of Die-Marked Drillpipe . International Journal of Fatigue , Elsevier, 21 , 799 - 811 , January.
21 Grondin, G.Y. ( 1994 ) Fatigue Testing of Drillpipe . SPE Drilling and Completion , June.
22 Tafreshi, A. and Dover , W.D. ( 1993 ) Stress Analysis of Drillstring Threaded Connections Using the Finite Element Method . International Journal Fatigue , 15 , 5 , 429 - 438 , September.
23 Zeren, F. ( 1986 ) Fatigue Limits Analyzed for Drillpipe in a Dogleg . Oil and Gas Journal, September , 22 .
24 Ertas, A. ( 1989 ) The Effect of Tool-Joint Stiffness on Drillpipe Fatigue in Riser Ball Joints . Journal of Engineering for Industry , 111 , November.
25 Ertas, A. ( 1992 ) A Comparison of Fracture Mechanics and S-N Curve Approaches in Designing Drillpipe . Journal of Offshore Mechanics and Artic Engineering , 114 , August .
26 Placido, J.C.R. ( 1994 ) Drillpipe Fatigue Life Prediction Model Based on Critical Plane Approaches . OTC 7569 , Houston, Texas, May 2-5.
27 Chen, W.C. ( 1990 ) Drillstring Fatigue Performance . SPE Drilling Engineering, June.
28 Ertas, A. A Comparison of Fracture Mechanics and S-N Curve Approaches in Designing Drillpipe . Mechanical Engineering Department, Texas Tech. University, Lubbock, Texas.
29 Kral, E. ( 1984 ) Fracture Mechanics Concept Offers Model to Help Calculate Fatigue Life in Drillpipe . Technology, Oil and Gas Journal , August , 13 .
30 Lemaître, J. and Chaboche , J.L. ( 1996 ) Mécanique des matériaux solides . 2nd ed., Dunod, Paris, France.
31 Hill, T.H. ( 1985 ) Qualifying Drillstring Components for Deep Drilling . Journal of Petroleum Technology , August , 1511 - 1522 .
32 Hill, T.H. ( 1998 ) Standard DS-1 , Drillstem Design and Inspection. T.H. Hill Associates Inc., DEA Project 74 , 2nd ed., March.
33 Horbeek, J.H. ( 1995 ) Successful Reduction of North Sea Drillstring Failures . Offshore Europe SPE 30348 , Aberdeen , September, 5 - 8 .
34 Sweet, R.G. ( 1989 ) Case History of Drillstem Failures Offshore West Africa . Drilling Conference SPE/IADC 18653, New Orleans , February 28-March 3 .
35 Kahil, J. ( 1989 ) New Technology for the Inspection of Used Tubing and Drillpipe . Eighth International Conference on Offshore Mechanics and Artic Engineering, 327 - 332 , The Hague, March 19 -23.
36 API ( 1999 ) API Specification 5D , Drillpipe , 4th ed., August.
37 API ( 1997 ) Recommended Practice for Field Inspection of New Casing, Tubing and Plain End Drillpipe . API-RP-5A5 , 6th ed., December.
38 Wade Edens , C. () Recent Innovation in Flux Leakage Drillpipe Inspection Technology: Quality Control Enhanced. Oilfield Equipment Marketing Inc ., South Texas Chapter ASNT, 515 , 860 .
39 Shaffer, E.A. ( 1992 ) Drillstring Problems Related to Internal Upset-Run-Cut Area of Drillpipe. Tuboscope Inc ., Drilling Conference, New Orleans, February 18 -21.
40 Armstrong, G.M. ( 1985 ) Sensitivity and Application of the Normal Beam Ultrasonic Technique for Detection of Fatigue Cracks in Rotary Shouldered Connections . SPE/IADC 13430, March .
41 Chapman, P.W. ( 1986 ) Ultrasonics Finds Drillpipe Cracks . Drilco, Petroleum Engineer International, March.
42 Stanley, R.K. and Wells , L. ( 1994 ) Recent Advances in Used Drillpipe Inspection by Ultrasonic Methods . Material Evaluation , 1282 - 1285 , November.
43 Ananto, D. ( 1996 ) Determining Drillpipe Wear Inside Casing Using Ultrasonic Measurements. Twenty-fifth Silver Anniversary Convention, Indonesian Petroleum Association , Proceedings, October, 411 - 423 .
44 Walaszek, H. ( 1998 ) Le contrôle ultrasonore possible aujourd'hui sans couplant ? Présentation de quelques résultats obtenus au CETIM . CETIM, Service CND , Senlis, France, May.
45 Dale, B.A. ( 1988 ) Inspection Interval Guidelines to Reduce Drillstring Failures . Exxon, Drilling Conference SPE/IADC 17207, Dallas, Texas, February 28-March 2 .
46 ( 1982 ) Drillpipe Inspection Technique . The Oilman, November , 33 .
47 Ligrone, A. ( 1995 ) Reliability Methods Applied to Drilling Operations . Agip SpA, Drilling Conference, Amsterdam, February 28-March 2.
48 Yoder, D.L. ( 1991 ) An Integrated Approach to Enhancing the Mechanical Life of Drillpipe in Extended Reach Wells . OTC 6712 , Houston, Texas, May 6-9.
49 Gensmer, R.P. ( 1988 ) Field Correlation Between Internal Taper Length and Tube Failures in 4.5 -in. 16.60E, IEU Drillpipe . Noble Drilling Corp ., Drilling Conference IADC/SPE 17205, Dallas, Texas, February 28-March 2 .
50 Gonzalez-Rodriguez , J.G. ( 1992 ) Corrosion Fatigue of AISI 4145 Steel in Drilling Mud . NACE Annual Conference and Corrosion Show , 151 .
51 Seshadri, P.V. ( 1992 ) Drillstring Failure Database: What Do We Learn? API/IADC , Drilling Conference IADC/SPE 23842, New Orleans , February 18 -21.
52 Brennan, F.P. ( 1995 ) Fatigue of Drillstring Connections . Transaction of the ASME , 117 , May.
53 Hatcher, P.R. and Szklarz , K.E. ( 1992 ) Near-Threshold Fatigue Crack Propagation Behavior of a Low Alloy Steel in Pressurized Dilute Brine Solution . NACE Annual Conference and Corrosion Show , 150 .
54 Grondin, G.Y. and Kulak , G.L. ( 1989 ) Fatigue of Drillpipe . CADE/CAODC Spring Drilling Conference, 89 - 47 , April.
55 Baryshnikov, A. ( 1997 ) Downhole Tool Full-Scale Fatigue Test: Experience and Practice Recommendations . ASME,
56 Trishman, L.E. ( 1952 ) Methods for the improvement of Drill Collar Joints Evaluated by Full-size Fatigue Tests. Spring Meeting of the Southwestern District , Division of Production, Shreveport, March.
57 Gaynor, T.M. ( 1996 ) Reduction in Fatigue Failures through Crack Detection by Alternating Current Field Measurement . Drilling Conference IADC/SPE 35033, March .
58 Azar, J.J. ( 1979 ) How O2, CO2 and Chlorides Affect Drillpipe Fatigue . Petroleum Engineer International, March.
59 Jiashen, Z. and Jingmao , Z. ( 1993 ) Increasing the Fatigue Life of 40-Cr Steel in Drilling Muds with Corrosion Inhibitors . NACE Corrosion , 49 , 3, March.
60 Karim Khani , M. ( 1996 ) Corrosion Fatigue in Nitrocarburized Quenched and Tempered Steels . Metallurgical and Materials Transactions , 27A, May.
61 Hendrickson, J.R. and Holland, M.R. ( 1984 ) Drillpipe Failures in Hydrogen Sulfide . Drilling Technology Conference Transactions , 358 , 516, March.
Wilson , G.E. ( 1996 ) A New Drillpipe Design Virtually Eliminates Failures That Result from Slip Damage . Drilling Conference IADC/SPE 35036, New Orleans , March 12 -15.
Wilson , G.E. ( 1998 ) How to Reduce Drillstring Fatigue Failures in a Corrosive Environment . Drilling 98, World Oil , October.
64 API ( 1997 ) Standard Procedure for Field Testing WaterBased Drilling Fluids . API-RP-13B-1 , 2nd ed., September.
65 API ( 1998 ) Standard Procedure for Field Testing Oil-Based Drilling Fluids . API-RP-13B-2 , 3rd ed., February.
66 Tsukano, Y. ( 1988 ) Appropriate Design of Drillpipe Internal Uset Geometry Focusing on Fatigue Property . Drilling Conference IADC/SPE 17206, Dallas, Texas, February 28- March 2 .
Winship , T.E. ( 1995 ) Making Drillpipe Upsets which Increase Fatigue Life . Spring Drilling Conference CADE/CAODC, 95 - 1009 , Calgary, April.
Wilson , G.E. ( 1994 ) What difference Does Internal Taper Length Make on Drillpipe Fatigue Life? Drilling and Completion , SPE 23841 , March .
Wilson , G.E. ( 1993 ) A New Tool-Joint Design Increases the Fatigue Life of Drillpipe Tubes . Drilling Conference SPE/IADC 25772, Amsterdam, February 23-25.
70 Tsukano, Y. ( 1990 ) Improvement of Drill Collar Fatigue Property by Last Engaged Thread Height Reduction of Pin . Drilling Engineering, SPE 18704, December .
72 Knight, M.J. ( 1999 ) Fatigue Life Improvement of Drill Collars Through Control of Bore Eccentricity . Engineering Failure Analysis , 6 , 301 - 319 .
73 Armstrong, G.M. ( 1987 ) Failure Prevention by Selection and Analysis of Drillstem Connections . Drilling Conference SPE/IADC 16075, New Orleans , March 15 -18.
74 Kirk, W.L. ( 1972 ) Deep Drilling Practices in Mississippi . Journal of Petroleum Technology , June.
75 Schock, W.H. ( 1986 ) One Piece , Forged, Heavy Wall Drillpipe: Built Stronger for Tougher Drilling . Drilling Conference IADC/SPE 14792, Dallas, February 10-12.
76 Gabolde, G. and Nguyen , J.P. ( 1999 ) in Drilling Data Handbook , Publications de l' Institut français du pétrole , Éditions Technip , 7th ed., Paris, France.
77 Baryshnikov, A. ( 1994 ) Optimization of Rotary-Shouldered Connection Reliability and Failure Analysis . Drilling Conference IADC/SPE 27535 , Dallas, February 15-18.
78 Baryshnikov, A. ( 1995 ) Downhole Tools Fatigue Resistance for Different Materials . Drilling Technology, ASME , PD, 65 .
79 Bailey, E.I. ( 1998 ) Calculating Limits for Torsion and Tensile Loads on Drillpipe. Hart's Petroleum Engineer International , February.
80 Payne, M.L. ( 1995 ) Drillstring Design Options for Extended Reach Drilling Operations . Drilling Technology, ASME , PD, 65 .
81 API ( 1992 ) Recommended Practice for Testing of Thread Compound for Rotary Shouldered Connections . API-RP-7A1 , 1st ed., ANSI/API-RP-7A1-1992 , November.
82 API ( 1983 ) Tentative API Bulletin on Rotary Shouldered Connection Thread Compounds . Bulletin API-7A1 , 1st ed., February 1980 and Supplement 1 , March 1983 .
83 Baryshnikov, A. ( 1995 ) Make-up Torque and Rotary Shouldered Connection Reliability . Drilling Conference SPE/IADC 29352, Amsterdam, February 28-March 2.
84 Baryshnikov, A. ( 1999 ) Eliminating Twist-Offs as a Cause of Drillstring Failure . OCTG Special Report , Word Oil, July .
85 Slack, M.W. ( 1990 ) Technique to Assess Directly Make-up Contact Stress Inside Tubular Connections . Drilling Conference IADC/SPE 19924, Houston, Texas, February 27- March 2 .
86 Tsukano, Y. ( 1990 ) Development of Lightweight Steel Drillpipe with 165-ksi Yield Strength . Drilling Conference IADC/SPE 19960, Houston, Texas, February 27-March 2 .
87 Glagola, M.A. ( 1986 ) Aluminium Drillpipe for Directional Drilling . Drilling Conference IADC/SPE 14789, Dallas, Texas, February 10 -12.
88 Schenato, A. , Borriello , G. and Pozzi , V. ( 1991 ) Ultra Deep Drilling Problems and Solutions, Agip SpA , Milano, Italy.
89 Eaton, L.F. ( 1993 ) Tool-Joint Heat Checking While Predrilling for Auger TLP Project . Drilling Conference SPE/IADC 25776, Amsterdam, February 23-25.
90 Szklarz, K.E. ( 1990 ) Fracture Toughness Criteria for HighStrength Drillpipe . Shell Canada Ltd, Drilling Conference IADC/SPE 19964, Houston, Texas, February 27-March 2 .
91 Guesnon, J. and Pignard , G. ( 1992 ) IFP Field Tests its New Trafor MWD System . Ocean Industry, May, 23 - 28 .
92 Mabile, C. , Fay , J.B. and Desloovere , O. ( 1997 ) Standard Surface Measurements Sampled at High Acquisition Rate Help in Detecting Drill String Vibrations . Offshore Mediterranean Conf. OMC 97 , Ravenna , Italy, March 19 -21, 759 - 769 .