Theoretical Study On Internal Corrosion Of Acidic Natural Gas Pipeline Induced By Flow Field

With the rapid development of oil and natural gas utilities, the increasing exploit of oil and natural gas makes the mileage of transport pipeline expanding. CO2and H2S, as the associated gas in the oil and natural gas, join the transport system through the exploitation. It has not only resulted in enormous economic losses to the oil and natural gas industry, but also caused a lot of pollution to the environment. With the exploration work of oil and natural gas develop to the deep geological formations increasingly, the rising contents of the associated gas CO2and H2S, coupled with the interaction among high temperature, high pressure, flow rate and flow pattern in the pipeline transportation, the pipeline corrosion problems under the induce of flow field have become even more outstanding. Therefore, study on the internal corrosion prediction of pipeline induce by flow field have a great practical significance on guiding the detection and ensuring the safe operation of in-service piping systems.Taking the'Xushen6-3'gas gathering station in Daqing Oil Field and'A line'in Sichuan Natural Gas East Transportation as the objects, and based on the De waard corrosion model and Euler multiphase flow model, the CO2corrosion model and the CO2/H2S model were established respectively, their three-dimensional pipes were simulated. The conclusions reached in this article are as follows:When CO2exist alone, change of pipe elevation has a direct impact on the corrosion; pipeline's corrosion rate has a parabolic form which increases first and then reduces in the coordinate system where independent variables are CO2partial pressure and temperature. Slight change of CO2partial pressure (0.025MPa-0.197MPa) does not cause the increase of turbulent kinetic energy and velocity near the pipeline wall, but can make the CO2phase distribution increase linearly. But when considered alone turbulent kinetic energy and velocity in elements of the flow field, it can clearly show a tendency which promotes the corrosion rate. The location of elbow induced by the flow field occurs at the facing stream side with tendency to the fluid field downstream, while the location of tee induced by the flow field occurs at the diagonal site along the direction of the confluence in the tee's internal X-shaped structure. The CO2phase distribution is in good agreement with the site corrosion position, while the change in moisture content (0.0668%-0.267%) causes the liquid holdup distribution increasing linearly. Combined with the moisture content and CO2phase distribution, it increases the internal corrosion of pipeline directly under the influence of flow field,when CO2and H2S co-exist, pipeline's corrosion rate has a parabolic form which increases first and then reduces in the coordinate system where independent variables are H2S partial pressure and temperature, on the condition that the CO2partial pressure maintains0.2108MPa. But when analyzing the flow field, it can found that for the broad and smooth flow channel of the large-diameter gas transport pipeline(Φ=406.4mm), the flow parameters have a little change at the small-scale changes in the pipeline (5°and15°) and the occurrence probability of uniform corrosion is larger than that of the extreme corrosion. The increase of H2S and CO2partial pressure causes the phase distribution increasing linearly at the internal-wall of pipeline. Moreover, the phase distribution often appears in the form of elliptical sheet around the average value. The phase distribution is slightly higher than the average value at0o'clock direction of the angle of15°depression's beginning and end due to the mutation of the flow channel.According to the relationship of the simulated flow field parameters and the pipe wall's corrosion rates, a corrosion model under the interaction of flow field has been put forward on the basis of the erosion model and the De waard corrosion model. It's similar to the De waard corrosion model when not taking consider of the flow field factors'impact. While parameters of the flow field can be modified to adapt the current conditions when taking consider of the flow field factors'impact. Compared with the measured values of'Xushen6'gas gathering station, the regression coefficients of the maximum and the average corrosion rate predicted by the CO2corrosion prediction model under the interaction of flow field are0.84and1.12respectively. While compared with the measured values of'A line'in Sichuan Natural Gas East Transportation, the regression coefficients of the average corrosion rate predicted by the CO2/H2S corrosion prediction model under the interaction of flow field is1.07. The corrosion location and rate calculated by the modified model are consistent with the wall thickness detection of site conditions, which verified that the improved CO2corrosion model is valid.