流场作用下的酸性天然气管道内腐蚀理论研究
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摘要
随着石油天然气事业的快速发展,石油天然气开采量的日益增加使得输运管道的里程也在不断扩大。H2S与CO2作为油气伴生气存在于油气之中,并通达油气的开采进入到输运系统中,这不仅对油气工业造成了巨大的经济损失,同时也对环境造成了很大的污染。而随着油气勘探工作越来越向地层深处发展,作为伴生气体的H2S与CO2含量也在不断上升,加之管道输运过程中高温、高压、流速和流态变化的相互作用,管道在流场作用下的腐蚀问题也愈加突出。因此,研究流场作用下管道内腐蚀预测问题,对于实现指导在役管道系统的检测工作量,保障管道系统的安全运行,具有重大的现实意义。
本文以我国的大庆徐深6-3气站与川气东送A线为研究对象,在De waard腐蚀模型与Euler多相流模型的基础上,分别建立CO2腐蚀模型与CO2/H2S腐蚀模型对其三维管道进行仿真模拟。得出的结论如下：
当CO2单独存在时,管段的高程变化对其腐蚀程度有直接的影响；管线的腐蚀率在以CO2分压与温度为自变量的坐标系中呈大致先增加再降低的抛物线形式；气相的微小分压变化(0.025MPa-0.197MPa)并不能引起管线近壁处湍动能与流速的增加,但会使管道内C02相分布呈线性增加。而在流场因素中单独考虑湍动能与流速影响时,可以明显表现出对腐蚀速率产生促进的倾向。弯头影响位置表现在流向变化位置的下游迎流侧壁面与弯头内径壁面；T形管影响位置表现在内部结构X形状合流方向的斜向内壁与迎流侧内径的位置；CO2相的分布情况与现场管道的腐蚀位置吻合良好；而含水率的变化(0.0668%-0.267%)将引起管道内持液率分布呈线性增加,在流场诱导下与CO2共同作用引起管道内腐蚀的直接增高。
CO2/H2S共同存在时,当CO2分压保持0.2108MPa不变时,管线的腐蚀率在以H2S分压与温度为自变量的坐标系中呈大致先增加再降低的抛物线形式。但对流场进行分析时可以发现,对于管径较大的气体输运管道(Φ=406.4mm),由于流道较宽广通畅,在管线流道小范围变化处(50与15°)流场参数变化范围较小,管道出现均匀腐蚀的概率较之出现极值腐蚀的概率大；管线中H2S分压与C02分压的增高,使管道内壁的相分布呈线性增长,且其分布多以略高或略低于均值的椭圆片状形式出现,在其15°俯角开始与结束处的0点方向,由于流道突变的作用,使得相分布略高于均值。
根据模拟所得的流场参数与管壁腐蚀率的关系,在冲蚀模型与De waard模型的基础上提出流场作用下的酸性天然气管道内腐蚀模型。该模型在不引入流场影响下时与De waard腐蚀模型相似,当介入流场参数的影响时,可对流场参数进行相应影响因子的修正以适应当前的工况。在与工况数据对比时,流场作用下的CO2预测模型最大腐蚀速率、平均腐蚀速率与大庆徐深6气站实测值的回归系数分别为0.84与1.12；而流场作用下的CO2/H2S腐蚀预测模型平均腐蚀速率与川东线A线实测值回归系数为1.07。该模型计算出的管线重点腐蚀位置与腐蚀率情况,在与现场工况的壁厚检测对照下吻合情况良好,验证了该改进腐蚀模型的正确性。
图43幅,表5个,参考文献52篇。
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.
本文以我国的大庆徐深6-3气站与川气东送A线为研究对象,在De waard腐蚀模型与Euler多相流模型的基础上,分别建立CO2腐蚀模型与CO2/H2S腐蚀模型对其三维管道进行仿真模拟。得出的结论如下：
当CO2单独存在时,管段的高程变化对其腐蚀程度有直接的影响；管线的腐蚀率在以CO2分压与温度为自变量的坐标系中呈大致先增加再降低的抛物线形式；气相的微小分压变化(0.025MPa-0.197MPa)并不能引起管线近壁处湍动能与流速的增加,但会使管道内C02相分布呈线性增加。而在流场因素中单独考虑湍动能与流速影响时,可以明显表现出对腐蚀速率产生促进的倾向。弯头影响位置表现在流向变化位置的下游迎流侧壁面与弯头内径壁面；T形管影响位置表现在内部结构X形状合流方向的斜向内壁与迎流侧内径的位置；CO2相的分布情况与现场管道的腐蚀位置吻合良好；而含水率的变化(0.0668%-0.267%)将引起管道内持液率分布呈线性增加,在流场诱导下与CO2共同作用引起管道内腐蚀的直接增高。
CO2/H2S共同存在时,当CO2分压保持0.2108MPa不变时,管线的腐蚀率在以H2S分压与温度为自变量的坐标系中呈大致先增加再降低的抛物线形式。但对流场进行分析时可以发现,对于管径较大的气体输运管道(Φ=406.4mm),由于流道较宽广通畅,在管线流道小范围变化处(50与15°)流场参数变化范围较小,管道出现均匀腐蚀的概率较之出现极值腐蚀的概率大；管线中H2S分压与C02分压的增高,使管道内壁的相分布呈线性增长,且其分布多以略高或略低于均值的椭圆片状形式出现,在其15°俯角开始与结束处的0点方向,由于流道突变的作用,使得相分布略高于均值。
根据模拟所得的流场参数与管壁腐蚀率的关系,在冲蚀模型与De waard模型的基础上提出流场作用下的酸性天然气管道内腐蚀模型。该模型在不引入流场影响下时与De waard腐蚀模型相似,当介入流场参数的影响时,可对流场参数进行相应影响因子的修正以适应当前的工况。在与工况数据对比时,流场作用下的CO2预测模型最大腐蚀速率、平均腐蚀速率与大庆徐深6气站实测值的回归系数分别为0.84与1.12；而流场作用下的CO2/H2S腐蚀预测模型平均腐蚀速率与川东线A线实测值回归系数为1.07。该模型计算出的管线重点腐蚀位置与腐蚀率情况,在与现场工况的壁厚检测对照下吻合情况良好,验证了该改进腐蚀模型的正确性。
图43幅,表5个,参考文献52篇。
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.
引文
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