Experimental study on corrosion of top of X65 steel pipeline with sulfur-containing crude oil

The corrosion behavior of different locations of X65 steel oil pipeline was investigated using a high-temperature corrosion test chamber, which aims to simulate the real corrosive environments of oil pipelines. Then the morphology and composition of the corrosion scales were characterized by Scanning Electron Microscope (SEM), Energy Dispersive Spectrometer (EDS) and X-ray diffraction (XRD). The results demonstrated that with the increasing time, the corrosion rate of X65 steel increased firstly and then slowed down to a lower level for long term. While temperature has obvious influence on the corrosion rate of the X65 steel, which presented the top area of the pipeline, where the steel suffered from uniform corrosion with formation of water drop-like corrosion products adhere to the steel surface. At low temperature, the main component of the corrosion products were iron oxide, in the contrast, at high temperature a protective corrosion product composed mainly of Fe2S could form.

Key words: X65 steel    temperature    top of line corrosion (TLC)    corrosion morphology    corrosion rate

CHENG Yawen1,2, ZHAO Huijun1, ZHOU Lihui3, ZHANG Xuan3, PENG Haoping1, ZHANG Weigang1
1. Jiangsu Key Laboratory of Oil & Gas Storage and Transportation Technology, Changzhou University, Changzhou 213016, China
2. Petroleum Development Center Co., Ltd., SINOPEC Shengli Oil Field, Dongying 257000, China
3. PETRO China Changqing Oilfield Branch Company of Oil & Gas Technology Institute, Xi’an 710000, China

1 Introduction
With the continuous improvement of the requirements for clean energy, the exploitation of oil and natural gas in China continues to expand, and the output of oil wells is mostly a multiphase mixture of oil and gas. The acid gas and organic acid in the mixture will cause corrosion of the pipeline, especially It is the occurrence of top corrosion. The earliest discovered top corrosion was the gathering pipeline of the LACQ gas field in France in the late 1960s. Although the pipeline was injected with corrosion inhibitors for a long time, the top of the pipeline still suffered severe corrosion. Chai Chengwen et al. [1] pointed out that the top corrosion mainly occurs in submarine oil pipelines, moisture pipelines or multiphase flow pipelines which lack good insulation and have large temperature difference inside and outside the pipeline. Due to the large temperature difference between the inside and outside of the pipeline, the water vapor in the gas condenses at the top to form a condensate. The condensate often contains some corrosive substances (such as CO2, H2S, organic acids, etc.), and the low flow velocity of the liquid in the pipeline accelerates these. The rate at which the substance dissolves in the condensate causes a more severe top corrosion at the top of the pipe [2-4].
At present, the corrosion problem of X65 pipeline steel, which is widely used in China’s oil and gas pipelines, is becoming increasingly prominent. In this paper, the crude oil corrosion test chamber is used to simulate the flow corrosion environment of the pipeline. The top corrosion behavior of X65 steel in sulfur-containing crude oil is studied. The influence of different corrosion time and temperature on the corrosion product structure and morphology of X65 steel is analyzed. The steel pipe provides a theoretical basis for the top corrosion behavior in a crude oil environment.
2 Experimental methods
The experimental materials were selected from commonly used X65 steels, and their chemical compositions (mass fraction, %) were: C 0.16, Si 0.45, Mn 1.60, P 0.02, S 0.01, V 0.06, Nb 0.05, Ti 0.06, Cu 0.2. The strip sample with a corrosion specimen size of 50 mm × 25 mm × 2 mm was used for the experiment. The surface was ground to 1500# with a YM-2A metallographic sample pre-grinding machine, and polished with a polishing machine, then with water. The ethanol was washed, the acetone was degreased, and the cold air was dried and weighed and marked to calculate the corrosion rate.
The physical properties of medium crude oil used in the experiment are shown in the literature [5]. It can be seen that the sulfur content is between 0.5% and 2.0%, which belongs to sulfur-containing crude oil, and the water content is less than 3.0%. The crude oil has a low moisture content. It was heated in a 30 °C water bath for 2 h before the experiment to improve the fluidity of the crude oil.
The equipment used in the experiment is a self-developed crude oil corrosion test chamber. The pressure of the corrosion chamber is normal pressure, the temperature is controlled by the water bath box, and the internal tank is connected to the circulating oil pump and the throttle valve to control the flow rate of the crude oil. The flow rate is 0.5 m/s; the condensate tank The circulating normal temperature water keeps the temperature of the tank wall at about 20 °C. The higher the water bath temperature is, the larger the temperature difference is formed with the condensate tank wall. The corrosion sample rack is added to the top of the tank to simulate the crude oil on the top of the pipeline. corrosion.
Before the experiment, the corrosion sample was installed in the sample slot of the top, the crude oil was poured into the corrosion chamber, high-purity nitrogen was introduced for 2 h to remove oxygen, and then the tank was sealed, and the temperature was raised to 30 °C for preheating. Four corrosion samples were placed in each experiment to ensure the reliability of the results. After the end of the experiment, the sample was taken out, degreased with acetone, and then part of the sample was immersed in a cleaning solution (20 mL of 0.5% diluted hydrochloric acid and 20 mL of 0.5% benzalkonium bromide mixture) for 5 min to remove the surface of the sample. The corrosion product has no obvious corrosion marks on the surface of the sample, and then rinsed with deionized water. Finally, the acid on the surface of the sample is removed with NaOH solution and rinsed with deionized water, dried by cold air, and weighed with an electronic balance. The average corrosion rate of the corrosion sample was calculated by the weight loss method. Another sample was observed with a JSM-6510 scanning electron microscope (SEM) to observe the surface morphology of the corrosion product, and the chemical composition of the corrosion product was analyzed by an energy spectrometer (EDS JSM-6510), and an APEXIIDUO X-ray diffractometer (XRD) was used. ) Analyze the phase of the corrosion product.
The experiment was divided into two groups. The first group was experimented with different corrosion time. The temperature of the experimental water bath was 80 °C, the temperature of the condensate tank wall was kept at 20 °C, and the experimental time of the samples was 48, 72, 96, 120 and 144 h, respectively. The two groups are experiments with different corrosion temperatures. The experimental time of each sample is 168 h, the experimental starting temperature is 30 °C (the experimental allowable temperature fluctuation is ±3 °C), the temperature gradient is 10 °C, and the experimental temperature is 30~100 °C. Change between.
The experiment used the change of weight before and after corrosion of the test piece to determine the corrosion rate of X65 steel [6], that is, the corrosion rate was measured by the weight loss method, as follows:
20180909014422 56391 - Experimental study on corrosion of top of X65 steel pipeline with sulfur-containing crude oil
Where m0 is the initial mass of the sample, g; m1 is the mass of the sample without corrosion products after the experiment, g; S is the surface area of the sample, m2; t is the corrosion test time, h; V is the corrosion rate represented by the weight loss method , g / (m2h).
The average corrosion rate measured by the weight loss method is converted into the corrosion rate expressed by the average erosion depth per unit time, as follows:
20180909021655 29889 - Experimental study on corrosion of top of X65 steel pipeline with sulfur-containing crude oil
Where V is the corrosion rate expressed by the weight loss method, g/(m2h); ρ is the density of the metal material, g/cm3; B is the corrosion rate expressed by the depth of erosion, mm/a.
3 Results and discussion
3.1 Corrosion rate analysis
3.1.1 Effect of different corrosion time on top corrosion rate Figure 1 shows the change of corrosion rate at the top of X65 steel sample with corrosion time. It was found by experiments that the protective film of the surface of the sample substrate formed after 24 h and slowly thickened within about 72 h. The experiment was sequentially taken out in the order of 48, 72, 96, 120 and 144 h. In the initial stage of the reaction, the corrosion rate increased rapidly. With the extension of time, the corrosion rate of X65 steel decreased. After 120 h, the corrosion rate decreased, which basically tended to a certain value. After analysis, there is no protective film on the surface of the sample at the initial stage of corrosion, and the moisture contains a lot of corrosive substances, which leads to a large corrosion rate. As the corrosion process progresses, the concentration of corrosive substances is reduced, but it is not supplemented. Corrosion is weakened, and a corrosion-resistant film of the protective surface has been formed on the metal surface, and the corrosion rate is lowered and tends to be stable. Since the corrosion rate at this time no longer changes significantly, the subsequent experimental test period is selected as 168 h.
20180909022116 67761 - Experimental study on corrosion of top of X65 steel pipeline with sulfur-containing crude oil

Fig.1 Change curve of TLC rate with corrosion time

3.1.2 Effect of different corrosion temperatures on the top corrosion rate Figure 2 shows the corrosion rate of X65 steel samples at different temperatures (30, 40, 50, 60, 70, 80, 90 and 100 °C) at the top of the tank. It can be seen that the corrosion rate of the sample is lower at low temperature and the growth rate is slower. As the temperature increases, the corrosion rate of the sample increases, especially when the temperature is higher than 50 °C, the corrosion rate increases greatly. This difference is due to the increase of the temperature difference, so that the moisture is accelerated to condense at the top of the pipeline, the infiltration area of the top sample and the condensed water is increased, and the condensed water contains a variety of corrosive substances, and the corrosive substances ionize in the water greatly. Accelerated, the corrosion rate of the sample is thus increased; on the other hand, the higher temperature accelerates the reaction rate of sulphide corrosion, and also promotes the conversion of a part of the inactive sulfur to active sulfur [7]. Within the experimental conditions, the corrosion rate of the sample at the top of the box increases first and then decreases with increasing temperature, reaches a maximum at 90 °C, and then decreases slightly. This trend is mainly due to the higher temperature which makes the protective FeS2 product denser and thus has good protection properties, resulting in a lower corrosion rate [8,9]. It has been found that [10], the top corrosion of H2S in moisture at low temperatures will form a small amount of unprotected Fe9S8 on its inner surface, and only when the temperature is higher than 100 °C will it be more protective. Good Fe1-xS and FeS2.

20180909022223 67944 - Experimental study on corrosion of top of X65 steel pipeline with sulfur-containing crude oil

Fig.2 Change curve of TLC rate with temperature

3.2 Corrosion morphology analysis
The corrosion microscopic topography of the top of the test chamber is shown in Figure 3.
20180909022551 34145 - Experimental study on corrosion of top of X65 steel pipeline with sulfur-containing crude oil

Fig.3 Morphologies of top coupons at 40 ℃ (a), 60 ℃ (b), 70 ℃ (c) and 90 ℃ (d)

At low temperatures, the corrosion rate of the sample is slower and the degree of corrosion is lighter. As can be seen from Figure 3, at 40 °C, the surface of the sample is slightly corroded and the corrosion is relatively uniform. Analysis of the corrosion products by XRD showed (Fig. 4) that the products at this time were mainly Fe3O4 which was not protective and other compounds of Fe. When the temperature is 60 °C, the corrosion area of the sample surface increases. After a period of accumulation, due to gravity, the top corrosion product is falling and the texture is brittle, the corrosion product adhesion is not strong, and there is continuous corrosion at the lower end. The product fell off. When the temperature reaches 70 °C, almost the entire surface of the sample is covered by corrosion products, the corrosion products are still loose, but the adhesion is enhanced, and there is no large-area shedding phenomenon. Two layers of corrosion product film are gradually formed on the surface of the substrate. The layer is looser and porous than the dense outer layer. Table 1 shows the energy spectrum analysis of the corrosion products in the A region at a temperature of 70 °C. It is found that the product contains S. It can be inferred that the temperature increase increases the sulfur activity in the crude oil to a certain extent, and the protective corrosion products such as FeS and FeS2 appear on the surface of X65 steel, and the compactness continues with the increase of temperature. Enhanced. When the temperature is raised to 90 °C, combined with the energy spectrum analysis of Table 1, it can be inferred that a relatively dense protective film is formed on the surface of the substrate, which can protect the matrix of the sample in a relatively simple environment.

20180909022749 12195 - Experimental study on corrosion of top of X65 steel pipeline with sulfur-containing crude oil

Fig.4 Compositions of corrosion scale by XRD analysis

Table 1 Compositions of corrosion scale by EDS analysis (Atomic fraction / %)

Position C O S Cl Fe
A 10.2 45.7 1.7 0.1 42.3
B 8.3 42.8 6.9 0.8 41.2

4 Conclusion
(1) With the increase of experimental time, the corrosion rate of sulfur-containing crude oil on the top of X65 pipeline steel increases first and then decreases, and finally the small amplitude fluctuation tends to be stable in the range of 0.631~0.652 mm/a. Through experiments, the corrosion rate of the sample tends to a certain value after the etching time reaches 144 h.
(2) As the bath temperature increases from 30 °C to 100 °C, the overall trend of the average corrosion rate of X65 steel increases first and then decreases. At a temperature of 90 °C, the corrosion rate reaches a maximum of 0.674 mm/a. There is a decrease.
(3) By comparing the corrosion product components, it can be found that the corrosion product contains a trace amount of Cl, which is mainly caused by the chlorine salt contained in the crude oil. When the corrosion temperature is 40 °C, the main component of the corrosion product is Fe3O4. When the temperature is 60 °C, S appears in the product. When the temperature is 90 °C, there are protective corrosion products such as FeS2 in the corrosion products.
The authors have declared that no competing interests exist.

Source: China Steel Pipeline Manufacturer – Yaang Pipe Industry (www.metallicsteel.com)

(Yaang Pipe Industry is a leading manufacturer and supplier of nickel alloy and stainless steel products, including Super Duplex Stainless Steel Flanges, Stainless Steel Flanges, Stainless Steel Pipe Fittings, Stainless Steel Pipe. Yaang products are widely used in Shipbuilding, Nuclear power, Marine engineering, Petroleum, Chemical, Mining, Sewage treatment, Natural gas and Pressure vessels and other industries.)

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