CN109816133B - Method for predicting corrosion in pipeline - Google Patents
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Abstract
The invention discloses a method for predicting corrosion in a pipeline, and belongs to the field of pipeline corrosion. The method comprises the following steps: dividing the target pipeline into a plurality of sub-pipelines; acquiring the water accumulation probability and the corrosion probability of the sub-pipeline; multiplying the ponding probability and the corrosion probability to obtain the total corrosion probability of the sub-pipelines; and predicting whether each sub-pipeline of the target pipeline is easy to generate internal corrosion or not according to the total corrosion probability. The influence of medium corrosivity and free water accumulation on pipeline internal corrosion is considered at the same time, whether the sub-pipeline is easy to generate internal corrosion or not can be accurately predicted, and the pipeline can be effectively prevented from leaking; in addition, the target pipeline is divided into the plurality of sub-pipelines, whether the plurality of sub-pipelines are easy to generate internal corrosion or not is sequentially judged, the part which is easy to generate in the target pipeline can be accurately and effectively inquired, and then corresponding management measures are carried out on the part, so that the operation intensity is reduced, and the internal corrosion of the pipeline can be effectively prevented.
Description
Technical Field
The invention relates to the field of pipeline corrosion, in particular to a method for predicting corrosion in a pipeline.
Background
With the entering of each main gas field in China in the middle and later periods of exploitation, the content of corrosive media such as carbon dioxide, hydrogen sulfide and the like and free water in natural gas is gradually increased, so that the degree of internal corrosion of the natural gas gathering and transportation pipeline is increased. Internal corrosion, which is one of the causes of pipeline aging, can cause pipeline leakage, reduce the structural strength of the pipeline, and seriously threaten the safety and integrity of the whole natural gas transportation system. Therefore, it is necessary to provide a method for predicting corrosion inside a pipe, which is to predict whether the pipe is susceptible to internal corrosion, and provide a basis for managing corrosion inside the pipe.
The prior art mainly provides two methods for predicting the internal corrosion of the pipeline, wherein one method mainly considers the corrosivity of a medium and predicts the degree of the internal corrosion of the pipeline through various corrosion rate prediction models; the other method is to determine the accumulation position of free water in the pipeline by a multiphase flow numerical simulation method and infer the position in the pipeline where corrosion is easy to occur.
The inventor finds that the prior art has at least the following problems:
since the internal corrosion of the pipe is mainly electrochemical corrosion, free water and corrosive media must be present in the pipe at the same time to cause the internal corrosion of the pipe. However, in both prediction methods provided by the prior art, free water and corrosive media are not considered at the same time, so that whether the pipeline is easy to generate internal corrosion cannot be accurately predicted.
Disclosure of Invention
In order to solve the above problem, an embodiment of the present invention provides a method for predicting corrosion in a pipeline. The technical scheme is as follows:
a method for predicting corrosion in a pipeline, the method comprising:
dividing the target pipeline into a plurality of sub-pipelines;
acquiring the water accumulation probability and the corrosion probability of the sub-pipeline;
multiplying the ponding probability and the corrosion probability to obtain the total corrosion probability of the sub-pipelines;
and predicting whether each sub-pipeline of the target pipeline is easy to generate internal corrosion or not according to the total corrosion probability.
Specifically, the dividing the acquisition target pipeline into a plurality of sub-pipelines includes:
sequentially determining a plurality of pipe segment dividing points along the axial direction according to the properties of the fluid in the target pipeline;
dividing the target pipeline into a plurality of pipeline sections by taking the pipeline section division point as a boundary point;
dividing the pipe segment into a plurality of sub-pipelines according to the elevation of the pipe segment.
In particular, the length of the subduct is 5m-30 m.
Specifically, the ponding probability of the subduct is obtained by the following method:
acquiring an actual inclination angle, a maximum critical inclination angle and an average critical inclination angle of the sub-pipeline;
calculating the water accumulation probability according to the following calculation formula by using the actual inclination angle, the maximum critical inclination angle and the average critical inclination angle of the sub-pipeline;
the calculation formula of the ponding probability is as follows:
in the formula:
PS-water accumulation probability of the subduct;
α — actual inclination, degree, of the subduct;
βmax-a maximum critical inclination angle, °, of said subduct;
Specifically, the acquiring an actual inclination angle of the sub-pipe includes:
acquiring the length and height difference of the sub-pipelines;
calculating the actual inclination angle of the sub-pipeline according to the length and the height difference of the pipeline and the following calculation formula;
the calculation formula of the actual inclination angle is as follows:
in the formula:
l-length of the subduct, m;
h-the height difference of the subducts, m.
Specifically, the maximum critical inclination angle and the average critical inclination angle of the sub-pipeline are obtained by the following method:
acquiring the average gas flow velocity, the maximum gas flow velocity and the minimum gas pressure of the fluid in the sub-pipeline;
calculating the average critical inclination angle by using the average gas flow speed and the minimum gas pressure;
calculating the maximum critical inclination angle by using the maximum gas flow rate and the minimum gas pressure;
the calculation formula of the average critical inclination angle and the maximum critical inclination angle is as follows:
in the formula:
β -said mean critical inclination or said maximum critical inclination, °;
ρg-gas density in the subduct, kg/m3；
ρl-density of liquid in said subduct in kg/m3；
Vg-gas flow velocity, m/s, inside the subduct;
g-acceleration of gravity, 9.81m/s2；
Di-the inner diameter of the subduct, m;
wherein, the calculation formula of the gas density is as follows:
in the formula:
p-gas pressure in the subduct, MPa;
MW-molecular weight of gas in the subduct, g/mol;
r-universal gas constant, 8.314J/(mol.K);
t-gas temperature inside the subduct, K;
z-gas compression factor within the subduct.
Specifically, the corrosion probability is obtained by a method including:
adopting different types of corrosion rate prediction models to respectively obtain the corrosion probability of each sub-pipeline, and correspondingly obtaining a plurality of sub-corrosion probabilities;
obtaining the corrosion probability according to the following calculation formula by using a plurality of sub-corrosion probabilities;
the calculation formula of the corrosion probability is as follows:
in the formula:
i-serial number of the corrosion efficiency prediction model;
m is the number of the corrosion efficiency prediction models;
Pi-sub-corrosion probabilities corresponding to the corrosion efficiency prediction model with index i;
Wi-a weighting factor corresponding to said corrosion efficiency prediction model with index i.
Specifically, the sub-etching probability is obtained by the following method:
sequentially conveying N groups of fluids with different properties in the target pipeline, and correspondingly acquiring N groups of first information, wherein the first information comprises: the starting point temperature, the end point temperature, the starting point flow rate and the end point flow rate of the fluid, wherein n is an integer greater than or equal to 1000;
according to n groups of first information, obtaining n groups of second information corresponding to each sub-pipeline in a one-to-one correspondence mode by utilizing a multiphase flow numerical simulation method, wherein the second information comprises: the temperature and pressure of the fluid within the subduct;
according to n groups of second information, acquiring n corrosion rates corresponding to each sub-pipeline in a one-to-one correspondence mode by using the corrosion rate prediction model;
acquiring the sub-corrosion probability according to a preset corrosion rate threshold and the n corrosion rates;
the calculation formula of the sub-corrosion probability is as follows:
in the formula:
Pi-the sub-corrosion probability;
a-the number of said corrosion rates greater than or equal to said corrosion rate threshold.
Specifically, if the total probability of corrosion is greater than 0.5, the subduct is prone to internal corrosion.
The technical scheme provided by the embodiment of the invention has the following beneficial effects:
according to the pipeline internal corrosion prediction method provided by the embodiment of the invention, the total corrosion probability of the sub-pipelines is obtained by firstly obtaining the water accumulation probability and the corrosion probability of the sub-pipelines, so that whether each sub-pipeline of the target pipeline is easy to generate internal corrosion is predicted. Therefore, the prediction method provided by the embodiment of the invention considers the influence of medium corrosivity and accumulation of free water on the internal corrosion of the pipeline, can accurately predict whether the sub-pipeline is easy to generate internal corrosion, and can effectively prevent the pipeline from leaking; in addition, the target pipeline is divided into the plurality of sub-pipelines, whether the plurality of sub-pipelines are easy to generate internal corrosion or not is sequentially judged, the part which is easy to generate in the target pipeline can be accurately and effectively inquired, and then corresponding management measures are carried out on the part, so that the operation intensity is reduced, and the internal corrosion of the pipeline can be effectively prevented.
Detailed Description
In order to make the objects, technical solutions and advantages of the present invention more apparent, embodiments of the present invention will be described in further detail below.
The embodiment of the invention provides a method for predicting corrosion in a pipeline, which comprises the following steps:
step 101: the target pipe is divided into a plurality of sub-pipes.
Step 102: and acquiring the water accumulation probability and the corrosion probability of the sub-pipeline.
Step 103: and multiplying the water accumulation probability and the corrosion probability to obtain the total corrosion probability of the sub-pipelines.
Step 104: and predicting whether each sub-pipeline of the target pipeline is easy to generate internal corrosion or not according to the total corrosion probability.
According to the pipeline internal corrosion prediction method provided by the embodiment of the invention, the total corrosion probability of the sub-pipelines is obtained by firstly obtaining the water accumulation probability and the corrosion probability of the sub-pipelines, and then whether each sub-pipeline of the target pipeline is easy to generate internal corrosion is predicted. Therefore, the prediction method provided by the embodiment of the invention considers the influence of medium corrosivity and accumulation of free water on the internal corrosion of the pipeline, can accurately predict whether the sub-pipeline is easy to generate internal corrosion, and can effectively prevent the pipeline from leaking; in addition, the target pipeline is divided into a plurality of sub-pipelines, whether the plurality of sub-pipelines are easy to generate internal corrosion is judged in sequence, the part which is easy to generate in the target pipeline can be accurately and effectively inquired, and corresponding management measures are further carried out on the part, for example, the measures of cleaning the part, adding a corrosion inhibitor, installing a corrosion leakage monitoring system and the like are carried out on the part, so that the operation intensity is reduced, and the internal corrosion of the pipeline can be effectively prevented.
The following describes the steps of the method for predicting corrosion in a pipeline provided by the embodiment of the invention:
step 101 is to divide the target pipe into a plurality of sub-pipes.
The medium pressure and the medium temperature of the target pipeline can affect the degree of internal corrosion of the target pipeline, for example, if the medium pressure is high, the partial pressure of acid gas in the pipeline can be increased, and the internal corrosion of the pipeline can be aggravated; if the medium temperature is high, the chemical reaction between the corrosive medium and the free water is easily promoted, and the corrosion in the pipeline is also aggravated.
It should be noted that the medium refers to natural gas in the target pipeline.
However, the target pipeline is usually provided with a branch line access point (i.e. the target pipeline is communicated with other pipelines), a chemical agent injection point (i.e. chemical agent, such as anticorrosive agent, is injected into the pipeline), and an accessory facility such as a tee joint and a valve chamber (i.e. an operation chamber for controlling the medium temperature, pressure and flow rate of the target pipeline) which can cause the medium pressure and medium temperature of the target pipeline to be convex, and is not favorable for predicting whether each sub-pipeline of the target pipeline is easy to be internally corroded, for this reason, in the embodiment of the present invention, the branch line access point, the chemical agent injection point, the tee joint and the valve chamber which cause the pressure and temperature convex of the target pipeline are used as a dividing point to divide the target pipeline, and then the step 101 can be specifically divided into the following steps:
step 1011: and sequentially determining a plurality of pipe segment division points along the axial direction according to the fluid property in the target pipeline.
The fluid property in the target pipeline refers to whether the temperature, pressure and flow of a medium in the target pipeline are changed or not; while branch inlet and outlet points, chemical reagent injection points, tee joints, valve chambers and other points causing the medium pressure and temperature of the target pipeline to be convex or accessory facilities of the pipeline are all pipe segment division points.
Step 1012: and dividing the target pipeline into a plurality of pipeline sections by taking the pipeline section dividing point as a dividing point.
The number of the pipe sections is related to the number of the branch inlet and outlet points, the chemical reagent injection points, the tee joint and the valve chamber. For example, if the target pipeline is provided with a branch inlet/outlet point and a chemical injection point, the target pipeline has two pipe segment dividing points, and accordingly, the target pipeline is divided into three pipe segments by taking the two pipe segment dividing points as dividing points.
Step 1013: the pipe segment is divided into a plurality of subducts according to the elevation of the pipe segment.
In order to ensure the accuracy of the prediction result, the length of the sub-pipeline is set within the range of 5m to 30m, and if the topography where the target pipeline is located has large fluctuation, the length of the sub-pipeline should not exceed 5 m.
Therefore, the embodiment of the invention considers the influence of medium pressure and temperature on the internal corrosion of the target pipeline, and divides the pipeline into a plurality of pipeline sections by adopting branch inlet and outlet points, chemical reagent injection points, tee joints, valve chambers and other points causing the medium pressure and temperature of the target pipeline to be convex or accessory facilities of the pipeline as pipeline section division points; each pipe section is subdivided according to the elevation of the pipe section, and each pipe section is divided into a plurality of sub-pipelines, so that the accuracy of the prediction result can be improved.
Step 102 is to obtain the water accumulation probability and corrosion probability of the sub-pipeline.
Specifically, the ponding probability of the subduct can be obtained by the following method:
step 2011: and acquiring the actual inclination angle, the maximum critical inclination angle and the average critical inclination angle of the sub-pipelines.
Step 2012: calculating the probability of water accumulation by using the actual inclination angle, the maximum critical inclination angle and the average critical inclination angle of the sub-pipelines according to the following calculation formula;
the calculation formula of the ponding probability is as follows:
in the formula:
PS-water accumulation probability of subduct;
α -actual inclination, degree, of the subduct;
βmax-a maximum critical inclination angle, °, of the subduct;
Specifically, the actual inclination angle of the subduct may be obtained by: acquiring the length and height difference of the sub-pipelines; calculating the actual inclination angle of the sub-pipeline according to the following calculation formula by utilizing the length and the height difference of the sub-pipeline; the calculation formula of the actual inclination angle is as follows:
in the formula:
l-length of subduct, m;
h-height difference of sub-pipelines, m.
The height difference of the subduct means the height difference between the starting point and the ending point of the subduct. When the elevation of the terminal point of the sub-pipeline is smaller than that of the starting point, the actual inclination angle of the sub-pipeline is smaller than 0 degree; and conversely, greater than 0.
Further, when the actual inclination angle of the sub-pipe is larger than the critical inclination angle (which means the minimum inclination angle at which the sub-pipe can retain free water in the sub-pipe under a certain medium pressure and medium flow), the free water can be accumulated in the sub-pipe, and therefore the water accumulation characteristic of the sub-pipe needs to be described.
Specifically, the maximum critical inclination angle and the average critical inclination angle of the sub-pipe are obtained by the following method: acquiring the average gas flow velocity, the maximum gas flow velocity and the minimum gas pressure of the fluid in the sub-pipeline; calculating an average critical inclination angle by using the average gas flow speed and the minimum gas pressure; and calculating the maximum critical inclination angle by using the maximum gas flow speed and the minimum gas pressure.
The calculation formula of the average critical inclination angle and the maximum critical inclination angle of the sub-pipeline is as follows:
in the formula:
beta-mean critical inclination or maximum critical inclination, °;
ρggas density in the subduct, kg/m3；
ρlThe density of the liquid in the subduct, kg/m3；
Vg-gas flow velocity in the subduct, m/s;
g-acceleration of gravity, 9.81m/s2；
DiThe inner diameter of the subduct, m.
Wherein, the calculation formula of the gas density is as follows:
in the formula:
p is the gas pressure in the subduct, MPa;
MW-gas molecular weight, g/mol;
r-universal gas constant, 8.314J/(mol.K);
t-gas temperature in the subduct, K;
z-gas compression factor within the subduct;
and acquiring the average gas flow velocity, the maximum gas flow velocity and the minimum gas pressure in the sub-pipelines, and respectively and correspondingly calculating the average critical inclination angle and the maximum critical inclination angle by utilizing the average gas flow velocity, the maximum gas flow velocity and the minimum gas pressure.
It should be noted that the average critical inclination angle corresponds to the average gas flow rate, and the maximum critical inclination angle corresponds to the maximum gas flow rate and the minimum gas pressure. That is, when the gas flow rate is the average gas flow rate in the sub-pipeline, the average critical inclination angle can be calculated according to the above formula; when the gas flow rate is the maximum gas flow rate in the sub-pipe and the gas pressure is the minimum gas pressure in the sub-pipe, the maximum critical inclination angle can be calculated according to the above calculation formula.
It will be understood by those skilled in the art that the density of the liquid in the subduct may be obtained by sampling analysis; the gas flow rate, the gas pressure and the gas temperature in the sub-pipeline can be obtained by reading related measuring instruments; the molecular weight of the gas can be obtained through chemical analysis, and when the methane content of the natural gas in the sub-pipeline is more than 80%, the molecular weight of the gas can be considered to be 16 g/mol; one gas pressure and one gas temperature in the sub-pipeline correspond to one gas compression factor, and the gas compression factor can be obtained through a table look-up method or a mathematical calculation method.
It should be noted that, a pipe segment corresponds to a critical inclination angle, that is, the critical inclination angles of a plurality of sub-pipes under a pipe segment are all the same.
Because the medium flow in the natural gas pipeline is unstable flow, the medium flow velocity at the same point at every moment is changed, and the critical inclination angle is also changed continuously according to the above-mentioned critical inclination angle calculation formula of the sub-pipeline. That is, the critical inclination angle of a certain point on the sub-pipeline fluctuates up and down by taking the average critical inclination angle as the center, and the variation range does not exceed the maximum critical inclination angle at most. And the fluctuation of the critical inclination angle of the subduct causes uncertainty to exist in the judgment of the liquid accumulation possibility of the subduct, and the uncertainty can be defined as the water accumulation probability.
Wherein, the calculation formula of the ponding probability is as follows:
as can be seen from the calculation formula of the water accumulation probability, the difference value between the actual inclination angle and the critical inclination angle of the sub-pipeline can be approximately regarded as obeying the standard normal distribution, and the standard error is
Then, the normalized formula is
Namely, it is
The value of (2) is subject to standard normal distribution, and the ponding probability of the sub-pipeline can be indirectly obtained through a standard normal distribution function, for example, by referring to a standard normal distribution table.
The above is a description of a method for obtaining the probability of water accumulation in the subduct, and the following is a description of how to obtain the probability of corrosion in the subduct.
Specifically, the corrosion probability may be obtained by a method including:
step 2021: and respectively calculating the corrosion probability of each sub-pipeline by adopting different types of corrosion rate prediction models, and correspondingly obtaining a plurality of sub-corrosion probabilities.
According to the types and contents of acidic corrosive media, the gas collecting and transporting pipelines can be divided into three types, which are respectively: h2Pipes with predominantly S corrosion, i.e. CO2Partial pressure and H2The ratio of S partial pressure is less than 20; ② pipes with internal corrosion, i.e. CO, caused by multi-factor synergy2Partial pressure and H2Of partial pressure SThe ratio is between 20 and 500; (iii) CO2Pipes with predominant corrosion, i.e. CO2Partial pressure exceeding H2S partial pressure is more than 500 times.
Wherein, when the target pipeline is H2When the pipeline mainly corroded by S and the pipeline internally corroded by the multi-factor synergistic effect are used, corrosion rate prediction models suitable for the target pipeline are Anderko models, Teevens models, SwRI models and the like; when the target pipeline is CO2When a pipeline mainly corrodes, the corrosion rate prediction models suitable for the target pipeline are DWM, Nesic, NORSOK and the like.
The above models are well known to those skilled in the art, for example, the Anderko model can be found in the graduation paper of royal jade in doctor 'determination and modeling research on solubility of natural gas component in aqueous solution containing alcohol'; the Teevens model and the Nesic model can be found in Sankara Papavinasam, Corroson Control in the Oil and Gas Industry; the DWM model and NORSOK model can be found in CO in oil and gas field of Zhangian in the 2 nd period of China's national institute of Corrosion and protection in 20052Prediction model of corrosion "; the SwRI model can be found in Yan graduation thesis of Yan Yongyan of Shu Shuoshi university at Zhejiang, research on the submarine pipeline oil spill risk evaluation system. The corrosion rate of the target pipe can be obtained by those skilled in the art by referring to the above documents using the above types of models.
It should be noted that, in application, the sub-corrosion probabilities of the sub-pipes may be correspondingly obtained through one or more of the corrosion rate prediction models, and the corrosion probabilities of the sub-pipes are obtained by using a weighted sum manner.
When the corrosion probability of the sub-pipeline is obtained by only adopting one corrosion rate prediction model, wiThe value is 1; w of each model if multiple corrosion rate prediction models are usediAnd each w is in a range of 0 to 1iThe value of (c) can be set according to the content of the corrosive medium and all w are guaranteediThe sum of (a) and (b) is 1.
It should be noted that, when a plurality of corrosion rate prediction models are used to obtain the corrosion probability of the sub-pipeline, if the target pipeline is H2Tubes based on S corrosionThe pipeline with the internal corrosion caused by the synergistic effect of the multiple factors and the pipeline, a plurality of corrosion rate prediction models adopted by the sub-pipeline can be selected from Anderko models, Teevens models, SwRI models and the like; if the target pipeline is CO2The corrosion-dominated pipeline and the plurality of corrosion rate prediction models used by the sub-pipelines may be selected from the DWM, Nesic and NORSOK models.
Step 2022: the corrosion probability is obtained according to the following calculation formula by using the plurality of sub-corrosion probabilities.
Wherein, the calculation formula of the corrosion probability is as follows:
in the formula:
i-serial number of corrosion efficiency prediction model;
m is the number of corrosion efficiency prediction models;
Pisub-corrosion probabilities corresponding to the corrosion efficiency prediction model with sequence number i;
Wi-a weighting factor corresponding to the corrosion efficiency prediction model with index i.
Further, the sub-etching probability is obtained by:
step a: acquiring first information of n groups of fluids of a target pipeline with different properties, wherein the first information comprises a starting point temperature, a starting point flow rate, an end point temperature and an end point flow rate of the target pipeline, and n is an integer greater than or equal to 1000.
The starting point temperature, the starting point flow rate, the end point temperature and the end point flow rate of the target pipeline refer to the temperature and the pressure of the natural gas at the starting point of the target pipeline and the temperature and the pressure of the target end point.
Step b: and acquiring n groups of second information corresponding to each sub-pipeline in a one-to-one correspondence manner by utilizing a multiphase flow numerical simulation method according to the n groups of first information, wherein the second information comprises the temperature and the pressure of the sub-pipeline.
It should be noted that a set of first information corresponds to a set of second information, that is, each set of first information is obtained by a multiphase flow numerical simulation method to obtain a set of second information corresponding to the first information.
Multiphase flow numerical simulation is common in the art, and various types of simulation software, such as OLGA software (the software is commercially available from Schlumberger, usa), pepphase software (the software is commercially available from SimSci, usa), etc., have appeared for implementing the multiphase flow numerical simulation, and by inputting parameters such as starting gas pressure, starting gas temperature, end gas pressure, and end gas temperature of a target pipeline into the software, a method for simulating multiphase fluid movement in the pipeline so as to obtain relevant parameters (such as temperature, pressure, etc.) at a certain position in the pipeline can be obtained.
Step c: and according to the n groups of second information, acquiring n corrosion rates corresponding to each sub-pipeline in a one-to-one correspondence manner by utilizing a corrosion rate prediction model.
It should be noted that, a group of second information corresponds to a corrosion rate, that is, each group of second information obtains a corrosion rate corresponding to the second information through a corrosion rate prediction model.
Step d: and setting a corrosion rate threshold, and acquiring the sub-corrosion probability according to the corrosion rate threshold and the n corrosion rates.
The calculation formula of the sub-corrosion probability is as follows:
in the formula:
Pi-sub-corrosion probability;
a is the number of corrosion rates greater than or equal to the corrosion rate threshold.
Internal corrosion of the subduct can occur when corrosive media and free water are present within the subduct. However, for in-pipe corrosion management, it is more of a concern whether the corrosion rate of the subduct exceeds the control corrosion rate, i.e., whether the subduct is susceptible to in-pipe corrosion. Therefore, the embodiment of the invention adopts a mathematical probability method to judge whether each sub-pipeline of the target pipeline is easy to generate internal corrosion, and specifically comprises the following steps: firstly, acquiring n corrosion rates of a sub-pipeline under different temperatures and pressures; finding out the number of the n corrosion rates which is greater than or equal to the control corrosion rate, and recording the number as a; and then, calculating to obtain the ratio of a to n, wherein the ratio is the sub-corrosion probability of the sub-pipeline.
Wherein, the corrosion control efficiency can be set according to the actual situation of the target pipeline, and generally does not exceed 0.1mm/a (namely millimeter/year).
And step 103, multiplying the ponding probability and the corrosion probability to obtain the total corrosion probability of the sub-pipelines.
And 104, predicting whether each sub-pipeline of the target pipeline is easy to generate internal corrosion or not according to the total corrosion probability.
Specifically, if the total probability of corrosion is greater than 0.5, the subduct is prone to internal corrosion. Thus, leakage of the target pipeline can be effectively prevented.
Examples
Based on the method provided by the embodiment of the present invention, the embodiment takes a certain pipeline as an example, and describes how to predict the internal corrosion.
The target pipeline transport medium is sulfur-containing wet gas, the total length is 0.83km, and a branch air inlet point is arranged along the line. Because the sulfur content of the target pipeline is larger (H)2The S partial pressure reaches 0.07MPa), and no corrosion inhibitor is added. The method for predicting the internal corrosion of the target pipeline specifically comprises the following steps:
(1) pipeline division
The target pipeline is provided with a branch air inlet point and is taken as a pipeline segment dividing point, and the target pipeline is divided into 2 pipeline segments; thereafter, each pipe segment is divided into a plurality of sub-pipe segments.
Further, due to certain fluctuation of the terrain where the target pipeline is located, after comprehensive consideration, the length of the sub-pipeline is not more than 20m, the target pipeline is divided into 46 sub-pipelines according to mapping data of the target pipeline, and branch air inlet points are dividing points numbered as 10 and 11 sub-pipelines in the table 1.
(2) Obtaining ponding probability of subducting
First, the actual inclination angle of each sub-pipe is obtained according to the above formula for calculating the actual inclination angle of the sub-pipe, and the actual inclination angle of each sub-pipe of the target pipe is shown in table 1, where the inclination angle in table 1 refers to the actual inclination angle in units of °.
TABLE 1
Taking the sub-pipe with the number 16 as an example, the actual inclination angle is obtained by the following process:
the length l of the sub-pipeline is 0.2993m, and the height difference h is 0.2527m, then the calculation formula is used
Obtain the actual inclination angle
The actual inclination angles of other sub-pipelines can be obtained by the method.
Secondly, respectively calculating the maximum critical inclination angle and the average critical inclination angle of the sub-pipeline according to the formula for calculating the critical inclination angle of the sub-pipeline.
The target pipeline is divided into two right pipeline sections because the target pipeline is provided with a branch air inlet point, and a large critical inclination angle and an average critical inclination angle corresponding to each pipeline section need to be correspondingly obtained.
The pipe section calculation parameters before the branch air inlet point are as follows: the gas pressure P in the smallest subduct is 2.5MPa, and the gas flow velocity V in the largest subductgIs 2.9m/s, the inner diameter D of the subducti0.094m, liquid density in the subduct ρlIs 1g/cm3The acceleration g of gravity is 9.81m/s2The gas temperature T in the subduct is 298K, the molecular weight MW of the gas is 16g/mol, and the constant R is 8.314 Pa.m3V (mol. K), gas compression factor Z is taken0.83. Substituting the formula for calculating the critical inclination angle of the sub-pipeline, the gas density rho in the sub-pipelinegMaximum critical inclination angle beta of sub-pipelinemaxComprises the following steps:
namely the maximum critical inclination angle of the sub-pipeline with the number less than or equal to 10 is 6.2 degrees; likewise, the average critical inclination angle of the subducts numbered less than or equal to 10 is calculated to be 0.8 ° with an average gas flow rate in the duct of 1.2 m/s.
The pipe section calculation parameters after the branch air inlet point are as follows: the gas pressure P in the smallest subduct is 2.3MPa, and the gas flow velocity V in the largest subductg3.8m/s, inner diameter D of the subducti0.094m, liquid density in the subduct ρlIs 1g/cm3The acceleration g of gravity is 9.81m/s2The gas temperature T in the subduct is 298K, the molecular weight MW of the gas is 16g/mol, and the constant R is 8.314 Pa.m3V (mol. K), the gas compression factor Z is 0.83. Substituting the formula for calculating the critical inclination angle of the sub-pipeline, wherein the maximum critical inclination angle of the sub-pipeline with the serial number equal to or greater than 11 is 10.2 degrees; likewise, the average critical inclination angle of the subducts numbered 11 or more, calculated as the average gas flow velocity in the duct of 1.9m/s, is 2.2 °.
Next, the difference between the actual inclination angle and the average critical inclination angle of the sub-pipe is calculated, as shown in table 2, wherein the inclination angle difference in table 2 refers to the difference between the actual inclination angle and the average critical inclination angle, and is expressed in degrees.
TABLE 2
Then, the standard of the sub-pipe numbered less than or equal to 10Error of the measurement
Standard error of sub-pipes numbered equal to or greater than 11
The standard normal distribution function is taken from the normalized value, and the water accumulation probability value of the sub-pipeline is calculated and obtained as shown in table 3:
TABLE 3
Taking the sub-pipeline with the number of 16 as an example, the process of acquiring the water accumulation probability is as follows:
because the number of the sub-pipeline is more than 11, the actual inclination angle of the sub-pipeline is 57.6 degrees, the maximum critical inclination angle is 10.2 degrees, the average critical inclination angle is 2.2 degrees, and the standard error is 8 degrees, and the actual inclination angle is calculated by substituting the standard formula into the standard formula:
namely, the value of the standard normal distribution function Φ (19.59) is the water accumulation probability of the sub-pipeline, wherein the water accumulation probability of the sub-pipeline is 1.00 by searching the standard normal distribution table.
The water accumulation probability of other sub-pipelines can be obtained according to the calculation process.
(3) Obtaining corrosion probability of sub-pipeline
Since the transport medium of the target pipeline is sulfurous moisture, and H2S partial pressure reaches 0.07MPa, and CO2Partial pressure and H2S partial pressure ratio is less than 20 and belongs to H2S corrosion is the main pipeline. And the corrosion rate was set to be controlled to 0.1 mm/a.
It is empirically believed that the SwRI model is used to predict the corrosion rate of the subduct. Wherein the SwRI model is:
in the formula:
k is a correction coefficient, determined empirically;
CI-the corrosion inhibitor, when no corrosion inhibitor is added, is taken as 1;
O2-indicating O in subduct2In ppm;
pH-the pH of the liquid in the subduct;
Wherein, O2The concentration and the pH value of the (D) can be obtained by sampling and analyzing;
refers to the pressure and CO of natural gas transported by a sub-pipeline2The product of the mole fractions;
refers to the pressure and H of natural gas transported by a sub-pipeline2The product of the mole fractions of S.
Firstly, performing 1000 times of simulation analysis on each sub-pipeline through multiphase flow simulation software to obtain the second pipeline information of each 1000 sub-pipeline groups.
Since the SwRI model does not consider the temperature factor, the pressure value in each second pipe information of the sub-pipe is substituted into the SwRI model, and 1000 corrosion rates of the pipe sections of each sub-pipe are calculated. It should be noted that temperature and pressure parameters may be used when other corrosion rate prediction models are used.
Secondly, counting the quantity a of the corrosion rate in each sub-pipeline which is more than or equal to the control corrosion rate of 0.1 mm/a; and calculates the ratio of a/1000.
Because only one prediction model of the corrosion rate is adopted, and the weighting factor wi is 1, the corrosion probability P of the sub-pipeline corresponding to the target pipeline is P1。
The calculation results of the corrosion probability for each subduct are then shown in table 4:
TABLE 4
Taking the sub-pipeline with the number of 16 as an example, the obtaining process of the corrosion probability is as follows:
the correction coefficient value in the known SwRI model is 3, the corrosion prevention factor value is 1, and CO is2Mole fraction of 0.247%, H2The mole fraction of S is 2.38%, O2Has a concentration of 100ppm and a pH of 4.21.
The sub-pipeline is firstly subjected to multiphase flow simulation analysis for 1000 times, and 1000 pressure values of the sub-pipeline are correspondingly obtained. Wherein the pressure of the sub-pipeline obtained in a certain time is 2.8187 MPa. The predicted corrosion rate was calculated to be 0.0894mm/a by substituting the above known conditions into the SwRI model.
And (3) respectively substituting 1000 times of results obtained by multiphase flow simulation analysis into calculation, and counting 574 predicted corrosion rates which are more than or equal to the control corrosion rate of 0.1 mm/a. The probability of corrosion for the subduct numbered 16 is 574/1000-0.574.
The corrosion probability of other sub-pipelines can be obtained according to the calculation process.
(3) Obtaining total probability of corrosion of subduct
The total corrosion probability can be obtained by the product of the ponding probability and the corrosion probability of each sub-pipeline of the pipeline, wherein the total corrosion probability of each sub-pipeline is shown in the table 5:
TABLE 5
Sequencing the total corrosion probability values of all pipe sections of the whole pipeline to obtain the first 10 pipe sections of the relatively corrosion sensitive sections of the pipeline, wherein the first 10 pipe sections are shown in the table 6:
TABLE 6
| Sorting | Pipeline numbering | Total probability of corrosion |
| 1 | 17 | 0.57 |
| 2 | 19 | 0.56 |
| 3 | 16 | 0.55 |
| 4 | 18 | 0.55 |
| 5 | 29 | 0.54 |
| 6 | 31 | 0.53 |
| 7 | 30 | 0.53 |
| 8 | 42 | 0.52 |
| 9 | 35 | 0.51 |
| 10 | 37 | 0.45 |
The sub-pipelines with higher total probability of corrosion are important to manage.
All the above optional technical solutions may be combined arbitrarily to form the optional embodiments of the present disclosure, and are not described herein again.
The above description is only for the purpose of illustrating the preferred embodiments of the present invention and is not to be construed as limiting the invention, and any modifications, equivalents, improvements and the like that fall within the spirit and principle of the present invention are intended to be included therein.
Claims (4)
1. A method for predicting corrosion in a pipeline, the method comprising:
sequentially determining a plurality of pipe section division points along the axial direction according to the properties of fluid in a target pipeline, wherein the division points comprise branch inlet and outlet points, chemical reagent injection points and auxiliary facilities for causing pressure and temperature mutation of the target pipeline;
dividing the target pipeline into a plurality of pipeline sections by taking the pipeline section division point as a boundary point;
dividing each pipe section into a plurality of sub-pipelines according to the elevation of the pipe section, wherein the length of each sub-pipeline is 5m-30 m;
acquiring the water accumulation probability and the corrosion probability of the sub-pipeline;
the ponding probability of the subduct is obtained by the following method:
acquiring an actual inclination angle, a maximum critical inclination angle and an average critical inclination angle of the sub-pipeline;
calculating the water accumulation probability according to the following calculation formula by using the actual inclination angle, the maximum critical inclination angle and the average critical inclination angle of the sub-pipelines;
the calculation formula of the ponding probability is as follows:
in the formula:
PS-water accumulation probability of the subduct;
α — actual inclination of the subduct in °;
βmax——the maximum critical inclination angle of the subduct, in degrees;
the corrosion probability is obtained by the following method:
respectively calculating the corrosion probability of each sub-pipeline by adopting different types of corrosion rate prediction models, and correspondingly obtaining the sub-corrosion probabilities of a plurality of sub-pipelines by using weight summation, wherein the sub-corrosion probabilities are obtained by the following method:
sequentially conveying n groups of fluids with different properties in the target pipeline, and correspondingly acquiring n groups of first information, wherein the first information comprises: the starting point temperature, the end point temperature, the starting point flow rate and the end point flow rate of the fluid, wherein n is an integer greater than or equal to 1000;
according to n groups of first information, obtaining n groups of second information corresponding to each sub-pipeline in a one-to-one correspondence mode by utilizing a multiphase flow numerical simulation method, wherein the second information comprises: the temperature and pressure of the fluid within the subduct;
according to n groups of second information, acquiring n corrosion rates corresponding to each sub-pipeline in a one-to-one correspondence mode by using the corrosion rate prediction model;
acquiring the sub-corrosion probability according to a preset corrosion rate threshold and the n corrosion rates;
the calculation formula of the sub-corrosion probability is as follows:
in the formula:
Pi-the sub-corrosion probability;
a-the number of said corrosion rates that is greater than or equal to said corrosion rate threshold;
obtaining the corrosion probability according to the following calculation formula by using a plurality of sub-corrosion probabilities;
the calculation formula of the corrosion probability is as follows:
in the formula:
i-serial number of the corrosion efficiency prediction model;
m is the number of the corrosion efficiency prediction models;
Pi-sub-corrosion probabilities corresponding to the corrosion efficiency prediction model with index i;
Wi-a weighting factor corresponding to said corrosion efficiency prediction model with index i;
multiplying the ponding probability and the corrosion probability to obtain the total corrosion probability of the sub-pipelines;
and predicting whether each sub-pipeline of the target pipeline is easy to generate internal corrosion or not according to the total corrosion probability.
2. The method of claim 1, wherein said obtaining an actual inclination of said subducting comprises:
acquiring the length and height difference of the sub-pipelines;
calculating the actual inclination angle of the sub-pipeline according to the length and the height difference of the sub-pipeline and the following calculation formula;
the calculation formula of the actual inclination angle is as follows:
in the formula:
l-the length of the subduct in m;
h-the height difference of the subducts, in m.
3. The method according to claim 2, wherein the maximum critical inclination angle and the average critical inclination angle of the subduct are obtained by:
acquiring the average gas flow velocity, the maximum gas flow velocity and the minimum gas pressure of the fluid in the sub-pipeline;
calculating the average critical inclination angle by using the average gas flow speed and the minimum gas pressure;
calculating the maximum critical inclination angle by using the maximum gas flow rate and the minimum gas pressure;
the calculation formula of the average critical inclination angle and the maximum critical inclination angle is as follows:
in the formula:
β — the mean critical inclination or the maximum critical inclination in °;
ρg-the gas density in the subduct in kg/m3；
ρl-the density of the liquid in the subduct in kg/m3；
Vg-the gas flow velocity in the subduct in m/s;
g-gravitational acceleration, is 9.81m/s2；
Di-the internal diameter of the subduct in m;
wherein, the calculation formula of the gas density is as follows:
in the formula:
p' -the gas pressure in the subduct, in MPa;
MW-molecular weight of gas in the subduct in g/mol;
r is a universal gas constant, and 8.314J/(mol.K) is taken;
t-gas temperature in the subduct in units of K;
z-gas compression factor within the subduct.
4. The method of claim 1, wherein the subducting is susceptible to internal corrosion if the total probability of corrosion is greater than 0.5.
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