Cause Analysis of Corrosion of Ground Pipeline in High Flow Condensate Gas Field

A condensate gas field surface pipeline is used to transport underground natural gas to the gas gathering station, and the pipeline material is L245NB steel. After only 5 months of production, it was found by non-destructive testing that the partial wall thickness reduction of a section of the tee before entering the gas gathering station was extremely serious, mainly located at the corners, welds of the tee.
After the gas from the condensate gas field flows out of the wellhead, it is separated into gas-liquid two phases with the decrease of pressure and temperature. The gas phase is natural gas in the condensate gas field, and the liquid phase is condensate. It is estimated that the daily gas production of the condensate gas field is 106m3, and the daily liquid production is 70m3. According to the pipe diameter of 100mm, the fluid velocity in the pipeline is as high as 13m.s-1, which is a high-flow condensate gas field. The working temperature of the pipeline is 40-60 ° C, the volume fraction of CO2 in the transport medium is about 1.02%, and the CL-mass concentration is about 59290 mg·L-1. In order to prevent the occurrence of corrosion and perforation accidents, the causes of corrosion of the tee were analyzed and improvement measures were proposed.

1 Physical and chemical tests and results

1.1 Macroscopic appearance
Figure 1 shows the piping (the entire installation is horizontally placed) and the sampling position. No fluid is passed through the alternate conveying passage during normal production. It can be seen from Fig. 2 and Fig. 3 that the outer wall of the tee is basically non-corrosive, but the inner wall has obvious corrosion, the side of the fluid passing through is obviously obvious, the surface is smooth, and there is no obvious corrosion product, wherein the inner side of the weld and the corner of the exit are corroded and thinned. The most serious, the formation of a number of horseshoe-shaped corrosion pits, the wall thickness is severely uneven, the difference is very large, the wall thickness is between 7.62 ~ 14.32mm, the weld thickness is only 5.44mm. The surface on the side where no fluid passes is covered with a thicker corrosion product, and the wall thickness is relatively small.
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Figure 1 Scheduling position
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Figure 2 The macroscopic appearance of the tees
1.2 Chemical composition
According to GB/T4336-2002, the chemical composition of the tee’s material was analyzed by ARL4460 direct readingspectrometer. The analysis results are shown in Table 1. It can be seen from the analysis results that the chemical composition of the pipe meets the requirements of GB/T9711.2-1999.
1.3 Micromorphology and corrosion products
In the tee material, there are fluid passage side and no fluid passage side sampling (respectively recorded as 1# and 2# samples), and the sampling position is shown in Fig. 4. The surface morphology and composition of the corroded surface were observed by TESCAN-VEGA II scanning electron microscopy (SEM) and the attached energy dispersive spectroscopy (EDS). The corrosion products were analyzed by D8 ADVANCE X-ray diffractometer (XRD). It can be seen from Fig. 5 to Fig. 7 that there is a small amount of corrosion products on the surface of the sample 1#, and the corrosion products on the surface of the sample #2 are thicker. The corrosion products mainly contain three elements of iron, carbon and oxygen, and a small amount of sulfur. Chlorine and other elements. Figure 8 shows that the surface corrosion product of the 2# sample is mainly FECO3 with a small amount of FES0.9.
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       (a) Corrosion pit                                                                      (b) Partial enlargement
Figure 3: The tee macroscopic appearance of fluid passing through the inner wall of the side
Table 1 Chemical composition (mass fraction) of L245NB steel

Grade C Si Mn P S Ti V Nb CE
EN 10208-2 max. max. max. max. max. max. max. max. max.
L245NB 0.162) 0.40 1.10 0.025 0.020 0.42
L290NB 0.172) 0.40 1.20 0.025 0.020 0.04 0.05 0.05 0.42
L360NB 0.202) 0.45 1.60 0.025 0.020 0.04 0.10 0.05 0.45

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Figure 4 Sample sampling position

2 Flow field calculation and indoor simulation test

2.1 Flow field calculation
The location and severity of corrosion in the tee is related to the flow and velocity of the fluid in the tube [1]. The FLUENT software was used to calculate and analyze the velocity field at different positions of the tees. Table 2 shows the relevant data for the liquid phase and the gas phase. The volume of the liquid phase in the fluid is very small compared to the gas phase and can be calculated in a single phase. Set the fluid to a steady-state single-phase incompressible flow,
The calculation is performed using the KE turbulence model. Calculation conditions: the inlet speed is 13.5m.s-1, the outlet is natural flow, and the inlet and outlet diameters are both 100mm. The calculation results are shown in Figure 9.
It can be seen from Fig. 9 that along the direction of fluid flow, the outer wall of the straight pipe section connected to the tee corner and the outlet is a high-velocity field zone, and the erosion corrosion of the zone is more serious under the action of high-speed fluid, which is The situation on the spot is also consistent.
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(a) 1# sample                                 (b) 2# sample, low magnification    (c) 2# sample, high magnification
Fig.5 Microscopic morphology of corrosion products on the inner surface of the tee
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Figure 6 1# Sample surface corrosion product EDS spectrum
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Figure 7 2# Sample surface corrosion product EDS spectrum
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Figure 8 XRD spectrum of corrosion products on the surface of 2# sample
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Figure 9 Flow velocity field inside the tee
2.2 Laboratory simulation test
The L245NB steel coupon sample with the same material as the on-site pipeline was used, the size was 40mm×10mm×3mm, and the on-site corrosion environment was simulated. The static simulation test of the high temperature autoclave was carried out in the laboratory. By measuring the corrosion rate, the corrosion of the L245NB steel pipeline under the high flow rate on site was compared and analyzed.
The static corrosion device uses a 34.4mPA high temperature autoclave produced by CORTEsT, USA. The test corrosion medium carbon dioxide pressure was 0.153 mPA, the total pressure was 15 mPA, the CL-mass concentration was 59,490 mg.L-1, the test temperature was 60 ° C, and the test time was 72 h.
Before the test, the high-purity nitrogen gas was deaerated for 10 h, and then three samples were charged and the autoclave was sealed. High-purity carbon dioxide gas was passed through to continue deaeration for 4 h, and then the temperature was raised. After the temperature reached 60 ° C, 0.153 mPA was introduced. The carbon dioxide is finally passed through nitrogen to maintain the total pressure at around 15 mPA. After the test, rinse with distilled water and remove the membrane
Wash the surface of the sample to remove the corrosive medium, then remove the water with anhydrous alcohol and then dry it. After removing the corrosion product film, weigh it with FR2300mK type electronic balance to calculate the mass loss and average corrosion rate of the sample. After the autoclave test, each sample was carefully cleaned with detergent, wire brush and remover to remove corrosion products and deposits on the surface of the sample, then dried, and the sample was placed in a drying dish for 24 h. Above, the above-mentioned electronic balance was weighed, and the corrosion rate of the sample was calculated, and then the average corrosion rate was determined. As a result, the average corrosion rate of the sample without the corrosion inhibitor was 0.5324 mm.A-1, and the surface corrosion was uniform, and no pitting morphology was observed.

3 Comprehensive analysis of the causes of pipeline corrosion reduction

From the on-site inspection and analysis of the tees, after the pipeline was put into production for only 5 months, the original 10mm wall thickness has been corroded to about 5mm, and the corrosion rate is as high as 12mm.A-1, which is much higher than the laboratory test results.
From the analysis of corrosion products on the inner wall of the tube, it can be seen that there is carbon dioxide corrosion on the inner wall [2]. It is estimated that the flow velocity of the fluid in the pit inlet pipeline is as high as 13 m.s-1 or more. At this high flow rate, the corrosion inhibitor does not work at all [3]. Combined with the analysis of the macroscopic morphology, micromorphology, corrosion products and flow field calculation of the inner wall corrosion of the pipe, it can be judged that the severe corrosion of the tee and the uneven thickness of the wall are mainly caused by the high-speed gas and the pipeline during use. The erosion of the liquid (erosion) is accompanied by the interaction of corrosive media (carbon dioxide, CL-, water, etc.).
Erosion is the result of the combination of mechanical damage and electrochemical corrosion of high-speed fluids [4]. The metal surface of the eddy current corrosion is a horseshoe-shaped groove, which is generally cut into the metal surface layer according to the flow direction of the fluid. After the corrosion, the surface is smooth and no corrosion product accumulates, so that the metal is further lost and deepened after corrosion. The eddy current not only accelerates the cathodic depolarization, but also adds a shear stress on the surface of the fluid, which shears off the already formed corrosion product film and causes it to be carried away by the fluid. If the fluid contains solid particles or droplets or bubbles, it will increase the shear stress moment and make the metal surface erosion more serious. The medium transported by the well ground pipeline is condensate gas. After coming out of the well, due to changes in temperature, pressure and other factors, the condensate will precipitate droplets, thereby accelerating the corrosion of the pipe wall.
In the pipeline that transports fluid, most of the pipelines are transported in a turbulent state (rather than a laminar flow state) [5], where each point in the medium does not keep the straight line flowing in the direction of the pipe, but As the pipe flows forward, it will also move up and down along the pipe section. The velocity and direction of each particle in the medium will change continuously at a large frequency, and eddy current will be generated in the pipe wall, but the motion formed by all the particles is relatively stable. State, therefore, when the fluid moves only in the horizontal or vertical direction in the conveying pipe, the pressure and kinetic energy of the fluid in the pipe wall are relatively stable, and the erosion of the pipe wall is uniformly thinned. However, when the fluid is suddenly changed direction (such as elbows, tees) or the fluid is blocked by the inner wall obstacles (such as the inner ring weld is too high), the eddy current effect on the pipe behind these positions is intensified, and the erosion It will intensify.
Since the weld bead is difficult to avoid the presence of welding slag, weld bead, etc., the wall near it will exacerbate corrosion in two ways. On the one hand, the weld seam and its vicinity become active areas, which are anodes with respect to the pipe body, causing corrosion; on the other hand, there may be strong turbulence in the weld and its vicinity.
Where high flow rates and welded joints occur, the rate of localized corrosion will be faster due to cracking of the scale.

4 Conclusions and recommendations

  • (1) The severe corrosion of the pipe section is mainly caused by the combination of carbon dioxide corrosion and erosion, and the corrosion product is mainly FeCO3.
  • (2) There are many unreasonable structures and welds in the original pipeline, such as variable diameter and direction change, which causes the fluid to be too large in local flow rate and the corrosion inhibitor does not work. Therefore, the structural design needs to be optimized.
  • (3) The flow rate of the fluid in the pipeline is too high. It is recommended to increase the pipe diameter or control the output to reduce the corrosion of the pipe to the pipe wall.

References:

[1] Chen Sunyi. Research and protection of fluid erosion on pipe fittings[J].Petrochemical Corrosion and Protection,2003,20(5):59 62.
[2] Zhang Xueyuan, Yan Chao, Lei Liangcai. Carbon dioxide corrosion and control [m]. Beijing: Chemical Industry Press, 2000:20 21.
[3] 000 3738 (2011) 05 0086 04
[4] Ma Ying, Ren Jun, Li Yuandong, et al. Progress in erosion wear research [J]. Journal of Lanzhou University of Technology, 2005, 31(1): 21 25.
[5] Li Helin, Li Pingquan, Feng Yaorong. Failure analysis and preventive measures of oil drill string [m]. Beijing: Petroleum Industry Press, 1999: 503 512.

Summary
cause analysis of corrosion of ground pipeline in high flow condensate gas field - Cause Analysis of Corrosion of Ground Pipeline in High Flow Condensate Gas Field
Article Name
Cause Analysis of Corrosion of Ground Pipeline in High Flow Condensate Gas Field
Description
It was found by non-destructive testing that the partial wall thickness reduction of a section of the tee before entering the gas gathering station was extremely serious, mainly located at the corners, welds of the tee.
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