20 号钢和 16Mn 钢天然气管道的失效分析
|Xuexu XU1, Zhiyong LIU1, Jiankuan LI1, Cuiwei DU1, Hui HUANG2, Renyang HE2|
The failure analysis for a natural gas pipeline, composed of pipes of 20 steel and 16Mn steel, was performed by means of examination of macro-morpholopy, metallograph, inclusion analysis as well as scanning electron microscope examination and chemical analysis for the relevant materials. Results showed that the areas with higher Mn-content such as the weld joint and the right-angle elbow, were serious corroded. The failure of the natural gas pipeline is mainly due to the erosion-corrosion beneath the CO2-cotaining thin electrolyte film. Machining defects and the microstructure deterioration caused by welding could also promote the corrosion process, thereby, inducing the serious wall-thinning of the pipeline.
|Key words： 20 steel 16Mn steel natural gas pipeline thin electrolyte layer erosion-corrosion|
With the ever-increasing demand for energy from Sinopec, the safety and reliability issues of oil and gas pipelines are increasingly being considered. Corrosion has long been one of the major risks affecting the safety and service life of pipeline structures . Among them, H2S-CO2 corrosion [2,3] is the main corrosion influencing factor in the transmission pipelines, station yards and long-distance pipelines. The corrosion of CO2 in natural gas pipelines is mostly thin liquid film corrosion. The corrosive medium such as CO2 in the transmission medium is easily dissolved in the water film and corrodes the pipeline. The study found that [4, 5, 6], there are many factors that affect CO2 corrosion, such as temperature, CO2 partial pressure, flow rate, medium composition and so on. In a certain temperature range, the corrosion rate of the pipeline in CO2 aqueous solution increases with the increase of temperature. When the pipeline surface forms a dense corrosion product film, the solubility of the pipeline decreases with the increase of temperature. Studies [7,8,9] have shown that as the CO2 partial pressure increases, the corrosion rate of the pipe increases. The effect of flow rate on CO2 corrosion is related to the material of the pipeline. Each material has a critical flow rate. After reaching the critical flow rate, the corrosion rate increases as the flow rate increases. The corrosion rate of the pipeline will decrease as the pH of the transmission medium increases, increasing the pH will reduce the solubility of FeCO3, favoring the formation of FeCO3 protective film and reducing the corrosion of the pipeline. But so far, there are few reports on the corrosion behavior of oil pipeline CO2 in low pressure pipelines and its influencing factors.
In this paper, taking the internal corrosion failure of CO2 low-pressure natural gas pipelines at a station as an example, using tissue analysis and corrosion characteristic analysis techniques, the differences in the material of the tube body, the state, and the welding of the thin film containing CO2-H2O are analyzed. The influence of fluid accelerated corrosion provides theoretical and practical basis for preventing the occurrence of similar failures.
1 Experimental method
For the failure of natural gas pipelines, according to the requirements of GB/T13298-91 metal microstructure inspection method, the different parts of two natural gas pipeline sections were observed. The sampling position of the sample is shown in Figures 1 and 2. The sample was sanded to 2000# step by step. After mechanical polishing, it was etched with 4% nitric acid alcohol solution. Then the metallurgical phase was performed with an ECLIPSE MA200 metallographic microscope. Observe the organization.
In order to judge whether the pipe meets the requirements for use, the material components and inclusions were analyzed using GENESIS XM EDS and chemical analysis at different failure sites of natural gas pipelines. In order to analyze the causes of the failure of the two natural gas pipelines, samples with different layers of rust inside the pipe segment were cut, and then their corrosion products were removed by the FEI Quanta 250 Scanning Electron Microscope (SEM) after being deoiled with acetone, washed with alcohol, and blown with cold air. The microscopic appearance is observed. In order to determine the main environmental factors causing corrosion and to infer failure mechanisms, Rigaku-type X-ray diffractometer (XRD) was used to analyze the corrosion products at the failure site.
Based on the above analysis results, a comprehensive theoretical analysis of the failure pipeline was conducted to determine the cause of corrosion and its key control conditions.
2 experimental results
2.1 Conditions of service conditions
Failure of the natural gas pipeline specifications for the 90 mm × 10 mm, 20 steel and 16Mn 钢管 and 16Mn right angle elbow welded pipe. The working pressure of the pipeline is 20 MPa, the flow rate is 5~15 m/s, the working temperature is the outdoor natural temperature (about 20~30 °C), the transmission medium is natural gas, a small amount of water (dew point below -20 °C) and CO2 (< 1%, volume fraction), The failure pipeline has been put into operation for nearly 10 years. Corrosion failure sites are concentrated in the excavation end of the pipe from the ground to its downstream area of 15-20 m. The area in this section is a temperature change zone.
2.2 Macroscopic Corrosion Morphology Observation
Figures 1 and 2 are the macroscopic topography of the inner surface of different pipe segments, respectively. It can be seen that there are obvious rust layers on the two natural gas pipe sections and the inner walls of right angle elbows. The rust layer in the general area is dense and reddish-brown, while the partially severely corroded areas (as shown in Figure 2) have a light-yellow tan color, indicating that these There is a more active corrosion process in the area. At the same time, as can be seen from Figure 1, the right 16Mn steel pipe section is more corrosive than the left 20 steel pipe section, which can be preliminarily inferred that the corrosion behavior of the two materials in this environment is different. From Figures 2a and b, it can be further seen that severe localized corrosion or uneven overall thinning occurred in the straight pipe, weld seam, and right angle elbow of the 16Mn steel. The maximum corrosion depth at the weld in Figure 2a has exceeded the wall thickness. 4/5. Compared with the straight pipe portion of 20 steel in Figure 1, the 16Mn steel is more severely corroded. It can be considered that the 16Mn steel is more severely corroded than the 20 steel, and the corrosion at the weld seam is more severe than that at the straight pipe.
Fig.1 Macro morphology of the welded sectionbetween 20 steel and 16Mn steel and the sampling locations
Fig.2 Macro morphologies of 16Mn steel and the sampling locations: (a) straight section, (b) right-angle elbow
2.3 Analysis of Alloy Chemical Composition
The chemical components of the failed sections of the two natural gas pipeline sections were analyzed to determine if their composition was satisfactory. The sampling positions are shown in Figures 1 and 2, and the results are shown in Tables 1 and 2. As can be seen from Tables 1 and 2, the basic chemical compositions of the 16Mn steel and the 20-steel pipeline are within the normal composition range and comply with the relevant standards.
Table 1 Chemical compositions of the failed 20 steel (mass fraction / %)
2.4 Metallographic analysis
The metallographic observations of 20-steel and 16-Mn steel and their welds are shown in Figures 3 and 4, respectively. From Fig. 3a, it can be seen that 20 steel has a more homogeneous matrix structure, consisting of fine ferrite equiaxed grains (white) and pearlite (black). The inclusions have smaller grains and lower density; the weld structure can be seen in Figure 3b. The microstructure of the base metal is obviously different, the weld is widmanite, and the grain is obviously coarse and unevenly distributed. The weld heat affected zone is composed of mixed microstructures (acicular ferrite, widmanite, pearlite). Wait). From Fig. 4a, it can be seen that the 16Mn steel has a homogeneous matrix consisting of ferrite (white) and pearlite (black), and the grain is coarser than that of the 20 steel matrix; Figure 4b shows that the microstructure of the 16Mn steel weld is also Wei’s. Body structure, and more than 20 steel weld area organization is thick; from Figure 4c can be seen, 16Mn steel weld heat affected zone organization and 20 steel heat affected zone organization, the same mixed organization, and 16Mn steel heat affected area organization The 20 steel heat affected zone organization is more coarse. It can be seen from Figure 4d that the degree of tissue deterioration of the 16Mn right-angled elbow is even more serious. It is a more coarse widmanite structure, and there is a significant difference from the straight-tube matrix. The above matrix, welds and HAZ microstructures show that the microstructure deterioration and strong scouring of the 16Mn steel weld zone and right-angled elbows may be the cause of serious corrosion in the weld zone and right-angled elbows.
Table 2 Chemical composition of the failed 16Mn steel (mass fraction / %)
Fig.3 Metallurgical structures of the failed 20 steel: (a) matrix, (b) welded zone, (c) heat affect zone
Fig.4 Metallurgical structures of the failed 16Mn steel: (a) matrix, (b) welded zone, (c) heat affect zone, (d) right-angle elbow
2.5 Inclusion Analysis
From the results of the metallography, there is no significant difference in the density and scale of the inclusions of the two steels at different locations. Therefore, according to the positions of the straight pipe sections of 20 steel and 16Mn steel shown in the sampling positions in Figures 1 and 2, the appearance and type of the inclusions were observed. And EDS analysis, the results are shown in Figures 5 and 6, respectively. From these two sets of data, the main inclusions in 20-steel and 16-Mn steels are MnS inclusions. The inclusions have lower density and smaller size, and the inclusions have similar levels and are all type A inclusions (sulfides. Inclusions) in Class 1 inclusions.
Fig.5 SEM image and EDS analysis of the inclusion in the failed 20 steel
Fig.6 SEM image and EDS analysis of the inclusion in the failed 16Mn steel
2.6 Analysis of Corrosion Products
The analysis results of the corrosion products of the two natural gas pipelines are shown in Figures 7 and 8. With reference to Figures 1 and 7, it can be seen that the rust layer on the surface of 20 steel is small and dense and the rust layer shows no signs of shedding. This indicates that 20 Steel can form a protective layer of corrosion products in the service environment and effectively protect the substrate. With reference to Figures 2 and 8, it can be seen that the rust layer on the inner surface of the 16Mn steel tube shows a clear crystalline state with obvious crack cracks, indicating that the corrosion product is easy to fall off, the corrosion product layer is loose, incomplete, not dense, and there are many defects. The electrochemical reaction cannot be effectively prevented by the penetration of aggressive ions into the pipe segment matrix, and the protection of the pipe segment matrix is poor.
Fig.7 Surface morphologies of the failed 20 steel with corrosion product: (a) weld joint, (b) matrix
Fig.8 Surface morphologies of the failed 16Mn steel with corrosion product: (a) weld joint, (b) matrix, (c) right-angle elbow
In order to further analyze the causes of the failure of the two natural gas pipe sections, XRD analysis was performed on the corrosion products of the three different parts of the pipe segment. The results are shown in Figure 9. It can be seen that the corrosion products formed by 20 steel and 16Mn steel pipe sections under long-term corrosion of corrosive media have basically the same composition, and are mainly composed of FeCO3, Fe3O4 and iron oxyhydroxide. This result shows that CO2 is the main depolarizing agent for the electrochemical process of corrosion in the above pipe section. The presence of FeOOH in the corrosion product of the 20 steel surface is more obvious than that of the 16Mn steel, further indicating that the corrosion product layer of the former is more stable and protective, which may be the main reason leading to the obvious difference in the corrosiveness of the two steels. one.
Fig.9 XRD spectra of corrosion products in the failed 20 steel and 16Mn steel in different regions
3 Analysis and discussion
From the point of view of the material of the failed pipe section, the chemical compositions of the 20 steel and 16Mn steel are within the standard range (Tables 1 and 2) and meet the standards of use. EDS analysis of inclusions and XRD analysis of corrosion products can eliminate the effect of inclusion differences on the local failure thinning of the pipeline.
3.1 Effect of microstructure on corrosion failure of natural gas pipelines
Figures 3 and 4 show that the grain size of the 20-pipe segment is smaller than that of the 16Mn steel. When the grain is refined, the number of active atoms on the surface of the 20-steel increases [10,11,12], and the passive film formation ability on the surface of the material increases. , Make the surface easier to form a passivation film, thereby improving the corrosion resistance of the material. At the same time, Parkinson study  showed that the increase of the Mn content in the metal will make the grain coarse, thus reducing the corrosion resistance of the metal. Figure 1 and 2 show that the 16Mn pipe section is more severe than the 20 pipe section. As can be seen from Figs. 1 and 2, obvious groove corrosion occurred in the weld zone of 20-steel and 16-Mn steel. Zhang et al.  showed that the corrosion potential of the weld zone is lower due to the difference of the weld area and the matrix structure. The corrosion potential of the tissue is high, the weld zone is easily formed with the matrix structure, the weld zone is the cathode, and the matrix is the anode. After a long service period, trench corrosion occurs in the weld zone and the weld zone is exposed to corrosive media. In the weld area, SCC fracture failure occurs easily .
3.2 Effect of thin liquid film on corrosion failure of natural gas pipelines
There are corrosive media such as CO2 in the pipeline transmission medium. Since CO2 dissolves in the water film due to the working conditions of the pipe section in the temperature change zone, it will exist in the pipe section in the form of carbonic acid, which will promote the electrochemical action of the metal. It has a strong corrosive effect on natural gas pipelines. The basic principle of the reaction is:
When the concentrations of Fe2+ and CO32- reach their solubility limits, the two are combined to form a solid iron carbonate oxide film. The chemical reaction equation is as follows:
In the pipe section, Fe2+ formed by anodic dissolution is combined with OH- provided by the cathode oxygen-absorption reaction to form unstable Fe(OH)2. Over time, Fe(OH)2 will be continuously oxidized to more stable FeO(OH). ) or Fe3O4 attached to the inner surface of the pipe.
The presence of a thin liquid film hinders the diffusion of iron atoms into the outer layer and thus effectively suppresses the occurrence of anode reactions (1), thereby slowing the corrosion of the pipeline. At the same time, due to the slow transmission of the medium, FeCO3 can form a corrosion product layer on the surface of the pipe section, which plays a certain role in the protection of the pipe section matrix. However, compared with the FeOOH product layer, FeCO3 can easily fall off under the action of natural gas fluid scour, resulting in 16Mn steel. The corrosion rate is higher. At the same time, relative humidity has a certain influence on the corrosion of CO2 thin liquid film. With the decrease of relative humidity, the thickness of thin liquid film decreases, the solution resistance increases, the mass transfer process is inhibited, and the corrosion rate decreases. The failure of the pipe section is concentrated in the easy to form a thin liquid film at the site, proving that the electrochemical corrosion process of the thin liquid film has an important impact on pipeline failure .
3.3 Effect of flow rate on corrosion failure of natural gas pipelines
Studies have shown that , when the pipeline medium is at a low flow rate, the shear stress is too small to destroy the entire corrosion product layer, so the local corrosion will occur in the loose, weak areas of the corrosion product layer. When the flow rate of the pipeline medium is high (≥14m/s), the corrosion product layer is difficult to deposit on the surface of the pipeline, so the pipeline is prone to total corrosion. Since this failure case only occurred in the temperature-changing zone, it was inferred that the rapid failure of the 16Mn steel pipeline was caused by the synergistic action of the flow rate and the thin liquid film containing CO2. As can be seen from Figure 8, the corrosion product layer on the surface of 16Mn steel is porous and easy to fall off, and it is difficult to form a complete and dense corrosion product film on the surface of the pipeline under the action of the medium scouring. This facilitates the penetration of corrosive ions and leads to different states. More severe local corrosion occurred in the 16Mn steel.
(1) The components of 20-steel and 16-Mn steel pipelines are qualified, and the influence of inclusions on the pipeline corrosion failure is small. Welds are coarsely organized and loosely eroded, making them more susceptible to failure than straight pipe parts. Welds and right-angled elbows are deteriorating due to the machining process, and are more prone to corrosion failure than straight pipe locations.
(2) The corrosion of 16Mn base pipe is more serious than that of 20 steel base pipe. It can be considered that it is related to the factors such as the coarseness of the structure caused by manganese content and the acceleration of the media flow velocity to accelerate the detachment of the corrosion product layer.
(3) The natural gas pipeline promotes localized corrosion failure under the interaction of the CO2 thin liquid film environment and the media flow velocity.
The authors have declared that no competing interests exist.
资料来源： 中国 Natural Gas Pipeline 制造商 – Yaang Pipe Industry (www.metallicsteel.com)
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Corrosion Science and Protetion Technology, 2018, 30(2): 195-201. http://www.cspt.org.cn/CN/10.11903/1002.6495.2017.115