Failure analysis of gas pipeline in a gas collecting station

1. Introduction

Pipeline is the most economical and safe way to transport oil and gas resources, but it is also extremely vulnerable to the influence of external pressure, corrosion, third-party damage and natural disasters [1-3]. In oil and gas storage and transportation engineering, the chemical properties and metallographic structure of the gas collecting pipeline itself determine that this iron-based alloy is a kind of corrosion-prone alloy [4-5]. According to a large number of data analysis at home and abroad and field investigation and analysis of oil and gas fields, the main failure of gas gathering pipeline is corrosion failure [6-8]. Generally speaking, the failure of the gas gathering pipeline is mainly due to three reasons: 1. The natural gas contains CO₂, which reduces the pH value of the water, which is weakly acidic and forms the corrosion product FeCO₃ [9]. 2. Natural gas contains H₂S and CO₂, which form an electrochemical reaction similar to a galvanic cell and chemical reaction that destroys the metal lattice, and corrodes the gas gathering pipeline [10]. 3. The natural gas contains CO₂ and CL, forming a “sweet gas” environment and corroding the gas gathering pipeline [11].

The external shale gas transmission pipeline in A area is the first shale gas transmission pipeline in China [12], one of the gas collection station gas collection pipeline failure. According to the

information provided, the pipeline is put into operation in May 2019, and the design specification of the pipeline is Φ323.9×8 mm seamless steel pipe, and the steel grade is L360N. The design pressure of the gas gathering pipeline is 8.5 MPa, the design gathering and transportation capacity is 260×104 m³/d, and the length is 6.65 km. The transmission medium is raw material gas (moisture), uncontained sulfur, and the anti-corrosion material is 3PE. There are nine obvious corrosion pits on the inner wall of the failed pipe sample, and the outer surface anticorrosion layer is partially damaged.

In order to clarify the reasons of the failure of the gas gathering pipeline, this paper analyzes the composition and mechanical properties of the failed pipeline samples, determines the composition and distribution of the corrosion products, and combines the failure theory to analyze the failure reasons of the pipeline.

2. Physical and chemical testing and analysis

2.1. Macroscopic morphology analysis

The macro morphology of the failed pipeline is shown in Fig. 1 and Fig. 2. It can be seen from Fig. 2 that there are 9 obvious corrosion pits on the inner wall of the tube sample. After cutting the relatively serious corrosion pits, the minimum remaining wall thickness of all the corrosion pits are measured to be 2.72 mm, 2.66 mm, and 2.36 mm, respectively.

Fig. 1Macroscopic appearance of sampling tube

Fig. 2Macroscopic appearance of the inner surface of the tube sample

The anti-corrosion layer on the outer surface of the pipe sample is partially damaged, and part of the surface is stuck with a “soil layer with small gravel”. “Soil layer with small gravel” is stuck on the surface, as shown in Fig. 3. After clearing the “soil layer with small gravel”, it was found that the anti-corrosion layer on the outer surface of the pipe sample was not completely damaged. After the anti-corrosion layer was wore away, the metal outer surface of the pipe sample did not appear damaged or corroded (The surface rust appears after the anti-corrosion layer is worn away), as shown in Fig. 4. The anti-corrosion layer on the outer surface of the pipe section is damaged, and the local damage is serious and there is a “soil layer with small gravel”, but not completely penetrated the anti-corrosion layer, and there is no corrosion or rust on the outer surface of the pipe section. It is inferred that the main reason for the damage of the anti-corrosion layer on the outer surface of the pipe section may be the mechanical damage during the construction process.

Fig. 3The serious pipe section with “soil layer with small stone slag” is adhered to the surface

Fig. 4The outer surface of the tube sample after the anticorrosion coating is worn off

2.4. Metallographic analysis

In order to improve the judgment of the microstructure condition, sample 1 and sample 2 are taken from the corrosion pits of the pipe section samples for structural analysis, as shown in Fig. 5. According to GB/T13298-1991 “Metal Microstructure Inspection Method”, the microstructures of the two samples are evaluated as ferrite plus pearlite, as shown in Fig. 6 and Fig. 7. According to GB/T 10561-2005 “Determination method of non-metallic inclusions in steel”, the non-metallic inclusions in the two samples are evaluated as D-type inclusions (spherical oxides), and the grade is 1.5; according to GB/T 6394-2002 “Method for the determination of the content of non-metallic inclusions in steel” to evaluate the grain size of the two samples, the measured grain size is 7 grades.

Fig. 5Metallographic analysis of sample sampling location at low power

Fig. 6Sample 1 metallographic photograph

Fig. 7Sample 2 metallographic photograph

2.5. Scanning electron microscope and energy spectrum analysis

In order to understand the reason for the corrosion of the tube sample, sample 1 was intercepted in the non-corrosive area of the tube sample, and the results of scanning electron microscope and energy spectrum analysis were shown in Fig. 8 and Table 5. The results show that the surface of sample 2 is flat without any layered or massive corrosion products. Sample 1 is mainly Fe, C, O and a small amount of Si and Mn. Sample 2 was intercepted at the corrosion pit of the pipe sample, and the results of scanning electron microscopy and energy spectrum analysis were shown in Fig. 9 and Table 5. The results show that there are gray layered and massively distributed corrosion products in the pits on the inner surface of sample 1. The gray corrosion products at the bottom of the pits are mainly Fe, O, C and a small amount of Al, Si, P, S, and Mn. It shows that the corrosion type of the gas gathering pipeline is pitting corrosion. A block sample is taken from the pipe corrosion pit, and the corrosion product is analyzed for phase. The results show that the corrosion products are mainly FeCO₃, Fe₃O₄, FeO, FeO(OH).

Fig. 8Morphology of uncorroded area of pipe sample

Fig. 9The high-magnification morphology of corrosion pit

Table 5The results of elemental content energy spectrum analysis of sample 1 and sample 2

Sample	Element
	C	O	Al	Si	P	S	Ca	Mn	Fe
Sample 1	7.38	23.90	0.32	0.49	0.82	0.99	/	1.26	64.84
Sample 2	4.00	1.49	/	0.32	/	/	/	1.57	92.62

3. Corrosion mechanism analysis

Based on the above analysis, the corrosion products of the corrosion pits in the gas collector are mainly Fe, O, and C, and also contain a small amount of Al, Si, P, S, and Mn. The corrosion products are mainly FeCO₃, Fe₃O₄, FeO, FeO(OH). Although the corrosion products contain a small amount of S, according to the data, the natural gas in the pipeline uncontained S, which excludes the possibility of the sulfide corrosion. Excluding the possibility of sulfide corrosion, the detected S is likely to come from SO₄^2- in the working environment, which has no direct relationship with the corrosion failure of the pipe sample. Since the natural gas composition does not contain O₂, it is judged that the iron oxides in the corrosion products are produced by secondary atmospheric corrosion and surface corrosion products conversion.

Excluding the possibility of sulfide and O₂ corrosion, combined with the XRD analysis results, it can be judged that the drill pipe corrosion is mainly caused by CO₂ corrosion. The gas collecting pipeline of this gas collecting station conveys wet gas. The CO₂ in the gas gathering pipeline is dissolved in water, which reduces the pH value of the water and becomes weakly acidic, forming the corrosion product FeCO₃. CO₂ itself does not It does not corrode the pipeline, but it is extremely corrosive to metal materials after being dissolved in water, and the corrosion of low-carbon alloy steel by CO₂ is mainly pitting corrosion [13-15].

CO₂ corrosion is also called Sweet Corrosion in the oil and gas industry [16-18]. Its essence is that CO₂ dissolves in water to generate H₂CO₃, and metal electrochemical corrosion occurs in H₂CO₃ solution. Regarding the anodic reaction in the CO₂ corrosion process, there is currently no consensus [19-21]. It is generally believed that in a solution containing CO₂, the anode reaction is:

Total anode reaction: $\text{Fe→F}{\text{e}}^{\text{2+}}\text{+2e}$.

At the same time, during the CO₂ corrosion process, the corrosion rate of steel is controlled by the cathodic reaction, which is as follows: $\text{2}{\text{H}}_{\text{2}}\text{C}{\text{O}}_{\text{3}}\text{+2e→2HC}{\text{O}}_{\text{3}}^{-}\text{+}{\text{H}}_{\text{2}}$.

Both H⁺ and H₂CO₃ can be reduced on the electrode. For the reduction of H⁺, it can be expressed as: $\text{2}{\text{H}}_{\text{3}}{\text{O}}^{\text{+}}\text{+2e→}{\text{H}}_{\text{2}}\text{+2}{\text{H}}_{\text{2}}\text{O}$.

The cathode process is the reduction of H₂O and HCO₃^-, namely:

Among them, HCO₃^- has a great influence on the cathode reaction, and the cathode reduction reaction is controlled by the diffusion of HCO₃^-. At the beginning of corrosion, Fe(HCO₃)₂ with strong bonding force has already formed on the metal surface, and the film can change: $\text{Fe(HC}{\text{O}}_{\text{3}}{\text{)}}_{\text{2}}\text{+Fe→2FeC}{\text{O}}_{\text{3}}\text{+}{\text{H}}_{\text{2}}$, The formed FeCO₃ film has poor bonding force with the metal matrix. Since the volume of FeCO₃ is smaller than that of Fe(HCO₃)₂, the volume shrinks during the conversion process, forming a poorly protective FeCO₃ film with micropores, which leads to the corrosion of the gas gathering pipeline [22-25].

4. Conclusions

1) The chemical composition, metallographic structure, Rockwell hardness and impact performance of the gas gathering pipeline meet the requirements of relevant standards, and the yield strength in the tensile performance is lower than GB/228.1-2010 “Metallic Material Tensile Test Part 1: Room Temperature” The standard value of the test method should be judged to be caused by CO₂ corrosion.

2) The gas collecting pipeline of this gas collecting station is mainly corroded by CO₂. The FeCO₃ film formed by the gas gathering pipeline has a poor bonding force with the metal matrix, because the volume of FeCO₃ is larger than that of Fe(HCO₃)₂. The volume is small, and the volume shrinks during the conversion process, forming the poorly protective FeCO₃ with micropores. FeCO₃ can have a “DC battery effect” with iron, leading to electrolytic corrosion.

3) Through the experimental analysis of the gas collecting pipeline of the gas collecting station, corresponding tests can be made to analyze the corrosion causes of other gas gathering pipelines.

5. Suggested improvement measures

1) In order to prevent the CO₂ corrosive environment from damaging the gas gathering pipeline, corrosion-resistant alloys are used as pipeline materials. According to related literature, nickel-based alloys and 22Cr have the best corrosion resistance, but they are not economical. 13Cr (Martensite) can be used. It can fully meet its corrosion resistance requirements.

2) Corrosion inhibitors can be injected into natural gas to alleviate metal corrosion, but corrosion inhibitors are not widely used. They may be effective in one area but not in another area. It is necessary to simulate the actual situation of the oil field before use. Various corrosion inhibitors are evaluated and screened under working conditions.