Journal of Failure Analysis and Prevention

, Volume 12, Issue 5, pp 550–557

Failure Analysis of a Gas Well Tubing due to Corrosion: A Case Study

Authors

    • Department of Materials Science and Engineering, School of EngineeringShiraz University
  • M. Saeedikhani
    • Department of Materials Science and Engineering, School of EngineeringShiraz University
  • R. Omidi
    • Technical Inspection DivisionArya-SGS Quality Assurance
Technical Article---Peer-Reviewed

DOI: 10.1007/s11668-012-9595-8

Cite this article as:
Javidi, M., Saeedikhani, M. & Omidi, R. J Fail. Anal. and Preven. (2012) 12: 550. doi:10.1007/s11668-012-9595-8

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 analysisHardnessMicrostructureSteel

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 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 [911].

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.
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

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 ×40 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 μlabIII), 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.

Results and Discussion

Visual Inspection

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.
https://static-content.springer.com/image/art%3A10.1007%2Fs11668-012-9595-8/MediaObjects/11668_2012_9595_Fig1_HTML.jpg
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

Material Identification

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.
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

Nb

Ti

V

W

Pb

0.005>

0.017

0.083

0.005>

<0.001

0.005>

<0.025

<0.05

https://static-content.springer.com/image/art%3A10.1007%2Fs11668-012-9595-8/MediaObjects/11668_2012_9595_Fig2_HTML.gif
Fig. 2

The stress–strain curves of the investigated material resulting from tension test

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

25.3

3

615

729

27.7

4

611

754

26.1

Average

627

766

25.8

Table 4

Hardness test data for body and threads of the sound and corroded tubings

Location

Hardness (HRC)

Hardness of the sound tubing

Hardness of the corroded tubing

Body

Thread

Body

Thread

Near to ID

22

23

21

30

Center

21

21

21

29

Near to OD

22

23

23

30

ID internal diameter, OD outside diameter

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 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.
Table 5

Conversion of hardness test data to tensile strength (approximate tensile strength)

Location

Conversion of hardness to tensile strength

Tensile strength of the sound tubing, MPa

Tensile strength of the corroded tubing, MPa

Thread

Body

Thread

Body

Near to ID

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

Sample

Temperature, °C

Impact energy, J

Sound tubing

Corroded tubing

Transverse

26

6

5.5

Transverse

26

5.5

5.8

Transverse

26

5.5

5.5

Longitudinal

26

11.4

10.5

Longitudinal

26

11.1

11.5

Longitudinal

26

11.4

12

Longitudinal

0

4.8

4.8

Longitudinal

−15

4.8

4.6

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 με, even to >10,000 με 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.

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 ×100 and ×400 magnification. Also, Fig. 4 shows the microstructure of the threads for the sound and corroded tubings at ×100 and ×400 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 ×200 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.
https://static-content.springer.com/image/art%3A10.1007%2Fs11668-012-9595-8/MediaObjects/11668_2012_9595_Fig3_HTML.jpg
Fig. 3

Photomicrographs of the microstructure from the body of the tubings: (a) sound ×400, (b) corroded ×400, (c) sound ×100, and (d) corroded ×100 magnification

https://static-content.springer.com/image/art%3A10.1007%2Fs11668-012-9595-8/MediaObjects/11668_2012_9595_Fig4_HTML.jpg
Fig. 4

Photomicrographs of the microstructure from the thread of the tubings: (a) sound ×400, (b) corroded ×400, (c) sound ×100, and (d) corroded ×100 magnification

https://static-content.springer.com/image/art%3A10.1007%2Fs11668-012-9595-8/MediaObjects/11668_2012_9595_Fig5_HTML.jpg
Fig. 5

The oriented microstructure of the corroded threads, ×200 magnification

https://static-content.springer.com/image/art%3A10.1007%2Fs11668-012-9595-8/MediaObjects/11668_2012_9595_Fig6_HTML.jpg
Fig. 6

SEM photomicrograph of microstructures for the (a) sound and (b) corroded threads

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 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) [1618].

Potentiodynamic Polarization

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 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.
https://static-content.springer.com/image/art%3A10.1007%2Fs11668-012-9595-8/MediaObjects/11668_2012_9595_Fig7_HTML.gif
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

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 × 10−5

0.225

Sound thread

−0.608

2.532 × 10−5

0.294

Corroded thread

−0.56

1.242 × 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

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.

Copyright information

© ASM International 2012