Failure Analysis of a Gas Well Tubing due
to Corrosion: A Case Study
M. Javidi, M. Saeedikhani & R. Omidi
Journal of Failure Analysis and
Prevention
ISSN 1547-7029
Volume 12
Number 5
J Fail. Anal. and Preven. (2012)
12:550-557
DOI 10.1007/s11668-012-9595-8
1 23
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J Fail. Anal. and Preven. (2012) 12:550–557
DOI 10.1007/s11668-012-9595-8
TECHNICAL ARTICLE—PEER-REVIEWED
Failure Analysis of a Gas Well Tubing due to Corrosion:
A Case Study
M. Javidi • M. Saeedikhani • R. Omidi
Submitted: 2 April 2012 / in revised form: 23 June 2012 / Published online: 20 July 2012
Ó ASM International 2012
Abstract In this study, failure analysis of a gas tubing
string was investigated. Visual inspection of the tubing
string showed that some of the tubings were corroded
locally at pin thread ends, which resulted in abrupt
replacement. In order to determine the cause of failure,
chemical composition, mechanical strength, Charpy
impact, and hardness, and microstructures of the corroded
and non-corroded pins were investigated. The chemical
composition of the tubing material was found to be API
5CT Grade C-75-2. The samples taken from the body of
both the corroded and non-corroded tubings showed the
same impact energy, yield strength, ultimate tensile
strength, and elongation. In addition, the hardness of the
body and thread ends of tubings were the same except for
corroded tubings, which showed locally more hardness at
thread region. Our analyses indicate that cold working the
tube strings, during the make-up process in the field,
caused localized corrosion of the male pins.
Keywords Corrosion failure analysis Hardness Microstructure Steel
M. Javidi (&) M. Saeedikhani
Department of Materials Science and Engineering, School
of Engineering, Shiraz University, 7134851154 Shiraz, Iran
e-mail: mjavidi@yahoo.com; mjavidi@shirazu.ac.ir
M. Saeedikhani
e-mail: Mohsen.saeedikhani@gmail.com
R. Omidi
Technical Inspection Division, Arya-SGS Quality
Assurance, Shiraz, Iran
e-mail: jafar_omidi@yahoo.com
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Introduction
Carbon steels are commonly used material for production
tubing of oil and gas wells, especially in case of exposure
to CO2 corrosion (also named sweet corrosion). API
Specification 5CT standard introduces a variety of carbon
steel tubing materials. However, in recent years, failure of
tubing strings due to thread gluing and corrosion happens
more and more frequently, which results in great economic
loss to oil and gas fields [1, 5]. One of the most frequent
and aggressive environments found in the petroleum
industry is fluid with high concentrations of chlorides and
containing carbon dioxide, which leads to CO2 corrosion
[2]. There are many variables associated with CO2 corrosion, including pH, temperature, pressure, flow regime,
steel composition, inhibitor, brine chemical composition,
the nature of surface films, etc [3, 4]. Sweet corrosion is
one of the major causes of failures in the oil and gas
industry. Corrosion occurs in all stages of production, from
downhole to surface equipment and further to the processing facilities. The presence of CO2 gas and that of
chloride ions are two important factors that lead to CO2
corrosion, resulting in higher corrosion rates [5, 6]. Furthermore, the presence of H2S in conjunction with chloride
ion can result in a severe corrosion rate [7].
Two general solutions can be employed to control CO2
corrosion. One is the use of corrosion resistance alloys,
which is a metallurgical solution [8]. The other is the use of
corrosion inhibitors, which is a chemical solution [5].
Although, corrosion-resistant alloys offer the advantages of
superior corrosion resistance, thinner wall and higher
mechanical strengths, the high initial capital cost demanded by this option makes it restrictive, especially for the
small producers. Chemical treatment by the use of corrosion inhibitors is a usual method for corrosion prevention
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and control, especially for low production or short-life
wells. Fine-tuning of the inhibition program is required to
achieve an adequate protection while continuing to
improve the cost wise performance. The lack of control on
inhibition program can increase the risk of corrosion.
Batching treatment and continuous injection of corrosion
inhibitors are common methods employed for controlling
corrosion for oil and gas wells, and the latter method shows
better performance [5].
This study will investigate the failure analysis of gas
well tubing strings that failed because of localized corrosion at the thread ends of tubing pins. It was observed that
corrosion occured at the male threads of tubings that were
assembled at the site, while there was no sign of corrosion
on the thread pins assembled in the factory. Similar failures
have been reported by other researchers [9–11].
Experimental
The drilled depth of the investigated well was reportedly
3250 m, consisting of 7-in.-diameter tubing—thread and
coupling type. Protection against internal corrosion of the
tubings was provided by means of corrosion inhibitor,
which was carried out once every three or four months via
batch injection. However, the used chemical treatment
regime was not successful in the prevention of corrosion of
the threads at male pins. The operating condition of the gas
well is reported in Table 1.
The investigated tubings were subjected to the following
experimental procedures. After dismantling the tubing
strings, visual inspection of the sound (noncorroded) and
corroded threads was performed on site. The internal and
external surfaces of the tubings were investigated to detect
any sign of corrosion.
Chemical composition of the material was evaluated by
means of OES technique (optical emission spectrometer,
Foundry Master Quantometer) by taking samples from male,
female, and coupling areas. The mechanical strength of the
material was investigated by Santam Tension Instrument
followed by determination of yield strength, tensile strength,
and elongation of the tubing material from the resulting
stress–strain curve. Charpy impact tests were performed on
longitudinal and transverse samples using Herman Paulsen
facility at 26, 0, and 15°C. Furthermore, hardness (Koopa
UV1) and microhardness (Koopa MH1) tests were conducted on the samples to evaluate changes in the hardness
due to mechanical work during make-up of the tubing
strings. The microhardness test was performed by application of a 25-g load, and the resulting indentations were
viewed at 940 magnification. It is important to note that the
sample preparation and mechanical testing were performed
in accordance with specifications of API 5CT Standard [12].
A microstructural study was conducted by taking samples from the body and the threaded areas of both the sound
and the corroded tubings in accordance with ASTM E 3
[13]. The samples were ground, polished, and etched in
Nital 2%, according to ASTM E 407 [14]. The microstructure of the samples was investigated using a S-360
Cambride Scanning Electron Microscope.
Electrochemical investigations were conducted on
samples taken from body, and from both the threaded ends
from a section of tubing, using a three-electrode glass cell
setup with platinum counter electrode and an Ag/AgCl
electrode as reference electrode. The samples (1 cm2 surface area) were prepared by removing all corrosion
products via grinding up to 600 grit, and were placed in a
glass cell filled with 3 wt.% sodium chloride solution,
de-aerated and saturated with CO2. Purging of CO2 was
continued during the polarization test. The open-circuit
potential (Eocp) was measured immediately after immersion
until it stabilized. Then, potentiodynamic polarization was
conducted over a potential range from 0.3 to ?0.3 V vs.
open-circuit potential at a scan rate of 1 mV/s. The corrosion current density (icorr) was determined graphically by
extrapolating the linear Tafel segments to the corresponding corrosion potentials (vs. Ag/AgCl electrode) followed
by corrosion rate calculation using Faraday relation.
Potentiodynamic scanning (PDS) was conducted using an
electrochemical measurement system including a potentiostat/galvanostat (Autolab, Metrohm model llabIII), a
personal computer, and GPES software (General Purpose
Electrochemical SystemVersion 4.9, 2006).
Finally, the history of weight loss corrosion coupons,
laboratory test results, and records for corrosion inhibitor
batch injection were collected from the data bank of the
owner and were used for further analysis and discussion on
the cause of failure.
Table 1 The operating condition of the investigated gas well
Sampling
location
Production rate,
MMSCM/day
Water production,
m3/day
Liquid production,
m3/day
LGR, m3/
MMSCM
WGR, m3/
MMSCM
Cl , ppm
CO2,
ppm
H2S,
ppm
pH
Well head
1.9–2.1
14
128
64
7
130–140
7000
3.5
5.1
MMSCM million standard cubic meter, LGR liquid gas ratio, WGR water gas ratio
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Results and Discussion
Material Identification
Visual Inspection
The chemical composition of the tubing material obtained
from OES quantometer analysis is reported in Table 2. It is
important to note that the chemical compositions for the
male, female, and coupling areas were the same. Also, the
stress–strain curve of the material is shown in Fig. 2, and
the mechanical strength and hardness of the samples are
reported in Tables 3 and 4, respectively. The chemical
composition and mechanical properties of the material
meet the specifications as per API 5CT C-75 Type 2 pipe
steel [12]. Furthermore, increases in the hardness and
tensile strength of the material were found at the corroded
threads.
The results of the hardness test revealed that the hardness of the material at the body of the sound and corroded
tubings are similar to each other, whereas the hardness at
the thread location for the corroded tubings is higher than
Figure 1 shows photographs of the failed tubing. It was
observed that threaded ends of male pin tubings were
corroded locally, while the other side of the coupling were
sound (without any sign of corrosion). It can be seen from
Fig. 1a, b that threaded ends of male pin tubings are corroded locally. The corrosion started internally and
continued through the thickness of the wall, resulting in
failure at the threads. However, Fig. 1c, d shows that the
threads of the other side of the coupling are sound without
any sign of localized corrosion (Point X). In other words,
our investigation showed that most of the threads of male
pins that were assembled in the field were corroded, while
the female pins assembled with couplings at the factory
were not corroded locally (as marked on Fig. 1). It can be
seen from Fig. 1b that severe corrosion occurred at the
threads, while the material adjacent to the thread was not
corroded severely. Thus, it was concluded that the cause of
failure must be related to the field, where the tubing strings
were assembled. In addition, a step is shown in Fig. 1c, d at
the end of the pins, which was done by the manufacturer
(Point Y). This step may cause turbulence in the flow that
can lead to erosion corrosion of the male pins. Thus, the
corrosion that was initiated at the male pins can be accelerated by the flow regime.
Fig. 1 Visual inspection of the
tubings, (a) and (b) corroded
male pins, (c) and (d) corroded
threads of the male pin and
noncorroded thread of the
female pins at the junction box
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Table 2 The chemical composition (wt.%) of the tubing material
obtained from quantometer analysis
Fe
C
Si
Mn
P
S
Cr
Mo
Ni
Base
0.211
0.335
1.27
0.013
0.010
0.106
0.010
0.075
Al
Co
Cu
V
W
Nb
Ti
Pb
0.005[ 0.017 0.083 0.005[ \0.001 0.005[ \0.025 \0.05
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Table 5 Conversion of hardness test data to tensile strength
(approximate tensile strength)
Conversion of hardness to tensile strength
Tensile strength of the
sound tubing, MPa
Location
Near to ID
Fig. 2 The stress–strain curves of the investigated material resulting
from tension test
Tensile strength of the
corroded tubing, MPa
Thread
Body
Thread
Body
786
806
772
937
Center
772
772
772
917
Near to OD
786
806
806
937
ID internal diameter, OD outside diameter
Table 6 The Charpy impact test data for sound and corroded tubings
Table 3 Mechanical strengths of the investigated material obtained
from tension test
Sample
Yield
strength,
MPa
Ultimate tensile
strength, MPa
%
Elongation
1
655
803
24.4
2
630
778
3
615
4
611
Average
627
Sample
Temperature, °C
Sound tubing
Corroded tubing
Transverse
26
6
5.5
Transverse
26
5.5
5.8
Transverse
26
5.5
5.5
25.3
Longitudinal
26
11.4
10.5
729
27.7
Longitudinal
26
11.1
11.5
754
26.1
Longitudinal
26
11.4
12
766
25.8
Longitudinal
0
4.8
4.8
Longitudinal
15
4.8
4.6
Table 4 Hardness test data for body and threads of the sound
and corroded tubings
Hardness (HRC)
Hardness of the
sound tubing
Location
Impact energy, J
Hardness of the
corroded tubing
Body
Thread
Body
Thread
Near to ID
22
23
21
Center
21
21
21
29
Near to OD
22
23
23
30
30
ID internal diameter, OD outside diameter
that of the threads for sound tubings. The approximate
conversion of the hardness test data to tensile strength
according to Volume 8 of ASM handbook [15] shows an
increase in the tensile strength of the material at the corroded threads in comparison with the sound threads as
shown in Table 5. The results obtained from the Charpy
impact tests are shown in Table 6. The samples for Charpy
impact testing were taken from the body of both the sound
and the corroded tubings. The results show that the impact
energies of the samples are similar to each other. The
results obtained from Charpy impact tests and the tensile
tests show that there was no difference in the mechanical
properties of the body of the sound and corroded tubings.
The increases in the hardness and tensile strength of the
material at the corroded threads could be due to cold
working during assembly of tubing strings on the site. This
could be the result of uncontrolled tightening of the couplings, which can lead to cold working and increase in
local energy followed by localized corrosion. However, the
coupling and the threads that were assembled in the factory
did not show any sign of corrosion. The effect of torque
and stress on oil tubing thread connections and its relationship to service life has been investigated by Yuan et al.
[11]. They concluded that the tubing thread connection has
partly entered into an elastic–plastic state under the action
of the make-up torque. The coupling expands in diameter
and shortens in the axial direction under the combined
influence of the make-up torque and the clamping force of
the hydraulic tongs. They found that the tubing thread
connection has undergone plastic strain because the axial
and hoop strains on the head of the pin increase rapidly to
8000 le, even to [10,000 le in some positions. It is
important to note that their study was for the case of
controlled assembling operation of the tubing strings and
under the action of optimum torques. Thus, uncontrolled
assembly with high level of applied torques can result in
cold working of the pins followed by localized corrosion in
future service life.
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It can be seen in Table 1 that the well produces high
volume of water with considerable concentration of chloride ions and CO2; thus the cold-worked pins become
susceptible to localized CO2 corrosion.
Plastic deformation of metals is usually assumed to
increase corrosion rates [16]. When an annealed material is
heavily cold worked, something of the order of 8–80
kJ/kg mol of energy may be stored in the material, as a
result of the increased dislocation density [17]. Foroulis
and Uhlig [18] suggest that the increased corrosion rate is
due to the cathodic (hydrogen evolution) reaction, that is
kinetically easier at cold-worked sites. CO2 corrosion was
also referred to as ‘‘acid corrosion’’ because of the formation of weak carbonic acid and release of hydrogen ions
(H?) [19]. As the dominating cathodic reaction for CO2
corrosion is hydrogen evolution, cold working can increase
the rate of CO2 corrosion. On the other hand, visual
inspection showed that inhibitor treatment of the well
prevented the general corrosion of the tubing string through
its body.
Metallography
Figure 3 shows the microstructure of the body for the
sound and corroded tubings at 9100 and 9400
Fig. 3 Photomicrographs of the
microstructure from the body of
the tubings: (a) sound 9400, (b)
corroded 9400, (c) sound
9100, and (d) corroded 9100
magnification
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magnification. Also, Fig. 4 shows the microstructure of the
threads for the sound and corroded tubings at 9100 and
9400 magnification. The microstructures of the sound
threads were found to be similar to the microstructure of
the body of tubings; in contrast, the microstructures of the
corroded threads reveal an oriented microstructure. As
shown in Figs. 3 and 4, the microstructure consists of
pearlite and lath martensite. The presence of lath martensite could be due to the severe quenching of the material
followed by tempering heat treatment during manufacturing process. The microstructures of the sound threads
shown in Fig. 4a, c are similar to the microstructure of the
body of tubings; while the microstructures of the corroded
threads (Fig. 4b, d) reveal an oriented microstructure due
to cold working, caused by assembly of the tubing strings
in the field. In other words, the microstructure oriented
throughout the direction of cold working. The study of the
microstructure validates the results obtained in the hardness test. Furthermore, in order to show the oriented
microstructure of the cold-worked threads more clearly, the
microstructure of the corroded threads was investigated at
9200 magnification, as shown in Fig. 5. Also, SEM
micrographs at higher magnification show the oriented
microstructure of the cold-worked threads, as shown in
Fig. 6b.
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Fig. 4 Photomicrographs of the
microstructure from the thread
of the tubings: (a) sound 9400,
(b) corroded 9400, (c) sound
9100, and (d) corroded 9100
magnification
microhardness value of the corroded threads is higher than
that of the sound threads. These results also confirm the
presence of cold working, which leads to changes in
microstructure, hardness, and mechanical strength of the
threads, and corrosion susceptibility (localized corrosion)
[16–18].
Potentiodynamic Polarization
Fig. 5 The oriented microstructure of the corroded threads, 9200
magnification
However, for further validation, microhardness tests
were performed on the microstructures of the sound and the
corroded threads. Averaging on four microhardness measurements resulted in 128.5 HV for the sound threads and
217 HV for the corroded threads. The data show that
Figure 7 shows the polarization curves obtained at pH 4
and 25°C for the samples taken from the body and threaded
ends of a tubing (with 1 cm2 surface area) in CO2-saturated
3 wt.% NaCl solution. From the obtained polarization
curves, corrosion potential (Ecorr) and corrosion current
density (icorr) were deduced. The resulting electrochemical
data are presented in Table 7. The results indicate that the
corrosion rates of the threaded parts, which were assembled
in the field during fabrication process (here, named corroded thread), are higher than the corrosion rates of the
body of the tubing and threads that were assembled to
the coupling in the factory (here named sound thread). The
higher corrosion rate of the corroded threads in comparison
with body, in the same electrolyte used to simulate CO2
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corrosion, is caused by the cold-worked material having a
higher corrosion susceptibility. This behavior may result
from cold working of threads during assembling process,
consistent with the microstructural study and mechanical
evaluations.
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Table 7 Electrochemical data resulted from polarization curves
obtained at pH 4 and 25°C for the samples taken from the body and
thread ends of a tubing (with 1 cm2 surface area) in CO2-saturated
3 wt.% NaCl solution
Sample
ECorr,
V
iCorr,
A/cm2
Corrosion rate,
mm/year
Body
0.56
1.937 9 10
5
0.225
Sound thread
0.608
2.532 9 10
5
0.294
Corroded thread
0.56
1.242 9 10
4
1.44
History of Corrosion Control
Control of internal corrosion for tubing strings of the
investigated gas well was performed by the use of corrosion
inhibitors via batch injection. The history showed that the
periodic intervals for inspection were every three or four
months. On the other hand, the history of well head corrosion
coupons showed severe corrosion rate according to NACE
RP0775 Standard (higher than 10 mills per year) [20]. Also,
the iron content [21] of the water sample taken from well
head facilities was in the range of 50–100 ppm. These data
indicate active internal corrosion of the tubing strings which
resulted in the failure of the cold-worked male pins.
Conclusions
Fig. 6 SEM photomicrograph of microstructures for the (a) sound
and (b) corroded threads
Fig. 7 Polarization curves
obtained at pH 4 and 25°C for
the samples taken from the body
and thread ends of a tubing
(with 1 cm2 surface area) in
CO2-saturated 3 wt.% NaCl
solution
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It was concluded that cold working of male pins during
assembly of the tubing strings resulted in an oriented
microstructure of the threads, followed by susceptibility to
localized corrosion, which led to CO2 corrosion. Thus, the
make-up and break-out torques can affect the field distribution of the stress of the tubing thread connection during
the make-up and break-out processes. It is important to
improve the performance and service life of the threaded
connection by designing tubings using hydraulic tongs that
can effectively control the make-up torque and velocity.
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