Failure Analysis of Corrosion and Fracture of P110 Tubing in a Development Well

In this paper, a fractured and corroded tubing string was analyzed through macroscopic observation, chemical composition analysis, metallographic and mechanical test. The corrosion products were studied by SEM, EDS, and XRD method. The results showed that the corrosion of tubing in this well was caused by CO2 corrosion, the well contains CO2 medium and increasing water cut in the late stage of development were the main reasons of serious corrosion, the scaling on the tubing wall aggravated the corrosion. Finally, some suggestions were proposed for avoiding or slowdown this kind of corrosion failures.


Introduction
With the increasing demand for energy in the production development, oil and gas well shift to the harsh environment, the service environment of tubing and casing are more and more severe, and the corrosion fracture of tubing and casing frequently [1][2][3][4] .Tubing is the lifeline of oil and gas exploitation.Once the corrosion fracture occurs, it will seriously threaten the underground safety of wells, affect the normal production of oilfield, and bring huge economic losses [5][6][7] .Therefore, it is necessary to analyze the causes of corrosion fracture of tubing and put forward targeted preventive measures to reduce the occurrence of similar accidents.
In this paper, the reason of a fractured tubing in a development well in the west of China was studied.The depth of the well was 5700 m, and the specification of tubing was Ф88.9 × 6.45 mm P110EUE.It was found that the pressure dropped sharply during the gas lift operation, and the 471# tubing was found fractured when it was taken out from the well.There was obvious corrosion occurred in the inner wall of the 372#~471# tubing, and accompanied by a certain degree of scaling phenomenon.Among them, the 467#~471# tubing scaling heavily, and the 471# tubing is the most corroded.No obvious outer wall corrosion was found in other tubing except the 471# and 521# tubing.A certain degree of scaling was found on the outer wall of the tubing, and there was no significant change in scaling degree on the outer wall.

Macroscopic observation
The macroscopic morphology of the failed tubing is shown in Figure 1~ Figure 3.The 471# tubing is a fractured tubing.The inner and outer walls of the tubing are pit-like corrosion morphology, and the wall thickness is reduced obviously.The remaining wall thickness is between 1.5 mm to 4 mm.Due to the thin wall thickness, it has been flattened after salvage, and the fracture is also damaged severely, as shown in Figure 1.It can be seen from the fracture at the lower part of 471# that there were more corrosion products on the internal wall of the 471# tubing and the thinning was serious.The wall thickness thinning is serious, resulting in a sharp decline in the tensile strength of the tube, and eventually the tube fracture.The internal and external walls of the 472# tubing are corroded lightly compare to 471# tubing, there was no obvious thickness thinning, and the remaining wall thickness is between 5.5 mm to 6 mm, as shown in Figure 2. The internal and external walls of 521# tubing were attached with heavy oil, the inner and outer walls are pit-like corrosion morphology, and the remaining wall thickness is between 2.5 mm to 4.5 mm, as shown in Figure 3.The inner wall corrosion is relatively serious than that of the outer wall on the other tubing, and a large number of corrosion products and scaling are attached to both the inner and outer walls.
The original wall thickness of the tubing in this well was 6.45 mm and the service time was 7.5 years.Based on this, the average corrosion rate of tubing was calculated and the qualitative categorization of tubing corrosion was determined according to NACE SP0775-2023 [8] standard (Table 1).The results are shown in Table 2. Tubing 471# and 521# experienced severe corrosion, while tubing 472# experienced moderate corrosion.Qualitative categorization High Moderate High In addition to the remaining wall thickness of 471# tubing, which is too thin to be analyzed, the 472# and 521# corroded tubing were tested and analyzed.

Chemical composition analysis
The chemical composition of the P110 tubing is shown in Table 3.The elements content accorded with the API Spec 5CT [9] standard requirement, the chemical composition is qualified, but the content of P, S, Cr and Mo elements in 472# and 521# tubing is different significantly.Compared with 521# tubing, the 472# tubing with higher corrosion resistance elements Cr, Mo and less impurities P and S elements showed less corrosion.

Metallographic structural characterization
The metallographic structural of the tubing is show in Figure 4, the microstructure is tempered sorbite.No oversized nonmetallic inclusions were found, and the grain size of tubing is ASTM 9.0 grade.

Mechanical properties
The results of tensile test showed that the tensile strength of 521# tubing is far below the requirement in API Spec 5CT standard, one of the 472# sample is below the 862MPa, as shown in Table 4. Since the test samples are all corroded samples, the exact cross-sectional area cannot be measured, so the elongation value A cannot be obtained; The wall thickness of the 521# tubing is thinned seriously, and the yield strength and impact test results cannot be measured.Both the internal and external surfaces of the samples were corroded, and the residual wall thickness is not enough to process the standard impact sample.The 2.5×10×55 mm sample is a non-standard sample, and the measured values are for reference only, as shown in Table 4.
The results of hardness value were shown in

SEM observation and EDS analysis
The micro-morphology and energy spectrum analysis specimen were taken from internal and external of the tubing.Electron microscope observation showed that thick corrosion product films were attached to both the inner and outer walls of the sample, and the corrosion films were uneven, especially for external wall, the morphology of which was shown in Figure 5 and Figure 6.The EDS results show that the corrosion products mainly contain of Fe, C, O, S and Cl, Si, Ca, Al elements, as show in Figure 7 and Figure 8.The C, O and Fe elements were the main components of corrosion products, while Cl, Si, Ca and Al elements were the main components of well fluid.It suggested that the corrosion film on the surface is mainly CO2 corrosion product.

XRD analysis
The corrosion products were FeO(OH) and FeCO 3 , shown in Figure 9 and Figure 10.The CaCO 3 shown in Figure 10 was the scale deposit.The corrosion products are mainly iron oxides and carbon dioxide corrosion products.

Discussions
According to the field data, the average water content of the crude oil in the well is greater than 30%wt., the average salt content is greater than 10000 mg/L, and it contains a certain amount of sulfur and wax formation, and the associated gas in the well contains 2%vol.CO2 and trace H2S, which belongs to the gas reservoir with low sulfur content and medium CO2 content, and the pipe string was worked in a harsh corrosion environment.The formation water contained HCO3 -, Ca 2+ , Mg 2+ , and Cl -plasmas accelerated tubing corrosion, as shown in Table 6.In oil and gas production systems, CO2 is not corrosive without water, but it is corrosive when dissolved in water [7] .In the late stage of the well, the moisture content is as high as 48%, and CO2 is very soluble in water, then the carbonic acid is obtained after it is dissolved in water, and hydrogen ions are released.Hydrogen ions are strong depolarizing agents, which are easy to seize electron reduction, promote the dissolution of anode iron and lead to corrosion.The reaction formula is as follows [10,11] : Step Step 2: Carbonic hydrolysis H2CO3----- + H + ------Fe 2+ + H2O (6) Total reaction Fe ----Fe 2+ + 2e - (7) Cathode process H + + e -------H pH<4 (8) H2CO3 + e -------H + HCO3 - 4<pH<6 (9) H2O + e --------H + OH - pH>6 (10) Then 2H ------H2 (11) Result CO2 + H2O + Fe -----FeCO3 + H2 (12) In the process of corrosion reaction, the following reactions may also exist: Fe 2+ +2H2O→FeO (OH) +3H + +e (13) This is consistent with the results of EDS and XRD analysis of corroded tubing.The corrosion products are mainly FeCO3 and FeO(OH) which are CO2 corrosion products, indicated that CO2 corrosion mainly occurs in tubing.FeO(OH) in corrosion products can also be considered as a hydrated oxide of Fe 2+ in the presence of oxygen, with the following formula: 4Fe 2+ +6H2O+O2→4FeO (OH) +8H + (14) In the process of CO2 corrosion, temperature is one of the most important factors, and the influence of temperature on the corrosion rate and corrosion form is largely reflected by the influence on the corrosion product film [12,13] .
The results [14] show that at about 60℃, a small amount of soft and undense FeCO3 is formed on the surface of carbon steel, and the corrosion rate is determined by the rate of CO2 hydrolysis to carbonic acid and the diffusion of carbonic acid to the metal surface.In this case, the corrosion is uniform corrosion.At about 100℃, the corrosion products are thick but very loose, and the corrosion rate is determined by the mass transfer process of the corrosive medium through the product film.At this time, the corrosion rate is the largest, forming a deep pit or ring corrosion.Under the temperature condition of about 150℃, the formation of dense and strong adhesion FeCO3, the corrosion process is basically prevented, and the corrosion rate is low.It is because of the strong influence of temperature on corrosion that local corrosion often occurs selectively at a certain depth in oil and gas wells.
For this failure well, the corrosion degree of tubing gradually increased from 372# ~ 471# when the temperature of the corroded pipe section was in the range of 110 ~ 120℃, but below the 521# tubing, the corrosion degree of tubing decreased, indicated that the corrosion degree tended to stabilize as the temperature exceeded 125℃.
In addition, from the macroscopic morphology of the corroded tubing and the XRD results of the corrosion products, there is obvious scaling phenomenon in the tubing, and the deposit of scale on the tubing will accelerate the corrosion of Corrosion products such as FeS, FeCO3, FeO and other iron compounds and CaCO3, MgCO3, CaSO4, BaSO4 and silicon dirt oil deposited on the surface of the tubing to form scaling. Scale is mostly formed in the lower part of the wellbore and near material defects or joints.Due to the high salinity in the produced liquid and the strong penetrating active anion Cl -, the corrosion film generated on the metal surface is destroyed, and it is difficult to form a dense scale layer or corrosion product protection layer.Microscopic corrosion galvanic cells are formed in local locations, forming pitting pits and rapidly developing in depth.The local corrosion rate is much higher than the average corrosion rate, which accelerates the corrosion.The severity of scaling in the well should be closely related to the quality of its produced water.According to the formation water analysis data of the oilfield, the concentration of Ca 2+ and Mg 2+ ions in the formation water is not very high, but the water cut of the well has increased significantly since 2008, and the water quality in the later stage of development may have changed.Therefore, the formation water quality of the well should be further analyzed.
According to the above macroscopic morphology analysis and corrosion product analysis of corroded tubing, combined with the service conditions of tubing and the mechanism of CO2 corrosion, it can be seen that tubing corrosion meets the characteristics of CO2 corrosion, the main cause of corrosion is CO2 corrosion, and the high water content in the late stage of development is the key reason for corrosion.The reason why the corrosion of the inner wall is more serious than that of the outer wall may be due to the fact that the outer wall of the tubing is in a static protective fluid environmental, and the inner wall is constantly in contact with the produced fluid containing corrosive media.

Conclusions and suggestions
(1) The corrosion of tubing in this well belongs to CO2 corrosion； (2) The oil well contains CO2 corrosive medium and the increasing water cut in the late stage of development are the main reasons of serious corrosion, and the corrosion is aggravated by scaling on the surface of the tubing.
It is suggested that targeted corrosion inhibitors and scale removal agents should be added continuously in the late stage of oil well development to reduce the influence of corrosion medium on pipe string corrosion and scale formation.

Table 1 .
Qualitative categorization of carbon steel corrosion rates

Table 2 .
Qualitative categorization of tubing

Table 4 .
Results of tensile test and charpy impact test

Table 5 .
Results of hardness

Table 6 .
The composition of formation water