CN112214940B - Method for identifying high-risk section of wet natural gas pipeline internal corrosion - Google Patents
Method for identifying high-risk section of wet natural gas pipeline internal corrosion Download PDFInfo
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- 238000005260 corrosion Methods 0.000 title claims abstract description 68
- 230000007797 corrosion Effects 0.000 title claims abstract description 65
- 239000003345 natural gas Substances 0.000 title claims abstract description 47
- 238000000034 method Methods 0.000 title claims abstract description 13
- 239000007788 liquid Substances 0.000 claims abstract description 32
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- 239000007789 gas Substances 0.000 claims description 22
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- 238000006243 chemical reaction Methods 0.000 claims description 6
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- 229910000037 hydrogen sulfide Inorganic materials 0.000 description 7
- 238000012360 testing method Methods 0.000 description 7
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 description 6
- 238000001514 detection method Methods 0.000 description 6
- 238000009825 accumulation Methods 0.000 description 5
- 238000002474 experimental method Methods 0.000 description 4
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 description 2
- RAHZWNYVWXNFOC-UHFFFAOYSA-N Sulphur dioxide Chemical compound O=S=O RAHZWNYVWXNFOC-UHFFFAOYSA-N 0.000 description 2
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 2
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- 229910052760 oxygen Inorganic materials 0.000 description 2
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Abstract
Provided is a method for identifying a high-risk corrosion section in a wet natural gas pipeline. According to the method, three-dimensional multiphase flow simulation calculation is carried out on a wet natural gas pipeline to obtain flow parameters in the pipeline, a proper corrosion model is selected to predict corrosion rate in the pipeline in combination with the corrosive medium condition contained in natural gas, the reliability of corrosion rate prediction is verified by adopting a corrosion experimental device, the position where the pipeline is most likely to be corroded is determined, the critical inclination angle of accumulated liquid of the wet natural gas pipeline is calculated, the probability of accumulated liquid is predicted in combination with the actual inclination angle of the pipeline, and finally, the high-risk corrosion pipeline section in the wet natural gas pipeline is comprehensively determined according to the predicted corrosion rate and the probability of accumulated liquid.
Description
Technical Field
The invention belongs to the technical field of natural gas pipeline safety risk evaluation, and particularly relates to a method for identifying a high-risk corrosion section in a wet natural gas pipeline, which is mainly used for predicting and identifying the high-risk corrosion section of a natural gas pipeline transmission system.
Background
The construction time of the moisture pipeline of the oil and gas field in China is mostly long and limited by the design capability, the construction level, the material condition and the like at that time, the high-incidence period of accidents is reached after years of operation, and the corrosion is one of the important factors influencing the safety and the integrity of the pipeline.
In petroleum-associated natural gas or pure natural gas, gas produced from a formation contains a certain amount of corrosive gases, i.e., carbon dioxide, hydrogen sulfide, sulfur dioxide, and the like, in addition to methane and the like. These gases are less corrosive when present as pure gases, but once dissolved in water, they greatly increase the corrosivity. Because the gas in the pipeline inevitably carries a certain amount of silt from the stratum, the silt plays a polishing role when moving along with the gas, causes the abrasion of the inner wall of the gas pipeline, damages a protective film on the surface and causes corrosion. In addition, trace oxygen in the pipeline is dissolved in accumulated water and has certain corrosiveness. Various microorganisms, as well as variations in operating temperature, delivery pressure, flow rate, etc., can have some effect on the rate of corrosion of the pipeline. A certain amount of water vapor is still contained in the natural gas pipeline, the water vapor can be converted into water due to the change of the operating environment in the pipeline, the water is deposited at the bottom of the pipeline under the influence of gravity, and the pipeline is corroded due to corrosive dissolution in the water. The liquid surface part of the accumulated water contacting the inner wall of the pipeline creates conditions for the electrochemical corrosion of metal due to the alternation of gas phase and liquid phase environments, thereby causing the pitting corrosion of steel and generating sulfide stress corrosion in a wet sulfur environment.
In 2014, the national safety supervision administration is involved in safety special investigation, and the result shows that 2.5 hidden dangers exist in oil and gas pipelines per 10 kilometers in China on average, and the rectification rate is less than 13%. Compared with developed countries, the accident rate of oil and gas pipelines in China is nearly 10 times higher.
At present, no good method exists for predicting the internal corrosion of wet natural gas pipelines at home and abroad, most of the wet natural gas pipelines adopt pipeline direct detection technologies such as magnetic flux leakage detection, ultrasonic detection and the like, the detection cost is high, the detection time is long, partial pipelines do not have direct detection conditions, operators cannot timely master corrosion information in the pipelines, corrosion perforation accidents are caused, serious emergency loss is caused, and the life safety is also damaged.
According to the method, three-dimensional multiphase flow simulation calculation is carried out on the pipeline, a proper corrosion model is selected to predict the corrosion rate in the pipeline by combining the corrosive medium condition contained in natural gas, the reliability of corrosion rate prediction is verified by adopting an experiment, the position where the pipeline is most likely to be corroded is determined, and the liquid accumulation probability is predicted by combining the pipeline inclination angle, so that the high-risk corrosion pipeline section is determined.
Disclosure of Invention
The invention provides a method for identifying a wet natural gas pipeline internal corrosion high-risk section, which is used for identifying the wet natural gas pipeline internal corrosion high-risk section and reducing wet natural gas pipeline leakage accidents caused by internal corrosion.
In order to achieve the purpose, the invention adopts the following technical scheme to realize the purpose:
s1: establishing a three-dimensional model of the pipeline, performing multiphase flow simulation, and calculating flow parameters of the pipeline;
s2: selecting a proper corrosion rate calculation model based on multiphase flow simulation parameters, and calculating the corrosion rate along the pipeline;
s3: evaluating the reliability of the calculated result through an indoor corrosion experimental device;
s4: if the calculation is reliable, the step goes to S5, and if the calculation is not reliable, the step goes back to S1 for recalculation;
s5: and analyzing the probability and the corrosion degree of the accumulated liquid and determining a corrosion high risk point.
In the pipeline three-dimensional multiphase flow calculation, all condensed liquid is accumulated at the bottom of the pipeline; the flow pattern in the pipeline is gas-liquid stratified flow, and the flow in each calculation pipe section is stably developed; and describing the shape of the interface by adopting a curved surface rough gas-liquid interface model.
The three-dimensional multiphase flow calculation comprises the following steps:
201: establishing momentum model under bipolar cylindrical coordinate system
202: establishing heat transfer model under bipolar cylindrical coordinate system
203: establishing a phase change model under a bipolar cylindrical coordinate system
204: coupling 3 models, setting boundary conditions,
205: calculating the flow parameters of pressure, temperature, gas and liquid flow rate, liquid holdup and the like in the outlet pipe,
in the formula: in the formula: l-Lame coefficient;
-axial pressure drop, Pa/m; rho-density of gas or liquid phase, kg/m3(ii) a ω -the velocity of the gas or liquid phase in the axial direction, m/s;
-axial temperature drop, c/m; t-temperature, DEG C; hL-liquid holdup; sLLiquid phase area, m2(ii) a S-pipe Cross-sectional area, m2；R0-pipe radius, m; h isL-liquid phase height, m; riThe radius of curvature of the liquid surface, m and theta are included angles and degrees of the wet wall; theta*Is the included angle of the liquid level.
The corrosion rate prediction is based on the three-dimensional multiphase flow calculation result and is calculated according to the following steps:
301: judging whether natural gas contains CO2And H2S
303: absence of CO in natural gas2Does not contain H2S, calculating according to a Lafayette model:
the flow rate of liquid phase in two-phase flow is less than 0.45m/s, and CR is-1.33VL 3+1.12VL 2+2.53VL+233, if the liquid phase flow rate is greater than 0.45m/s, CR is 1.92VL+6.33，
In the formula, CR is corrosion rate, mm/a; vLThe liquid phase flow rate, m/s.
302: if the natural gas contains CO2Judging whether H still exists in the natural gas2S；
304: if the natural gas contains CO2Also contains H2S, predicting according to an ECE formula:
in the formula: v. ofr-corrosion rate, mm/s; t-temperature of the medium, K; pH valueact-actual pH value, dimensionless; pH valueco2——CO2The pH value of the saturated solvent is zero; f. ofco2——CO2The fugacity coefficient of (A) is zero;
305: if the natural gas contains only CO2Does not contain H2S, and is predicted according to the following De Warr95 formula:
in the formula: vcorr-corrosion rate, mm/a; vr-reaction rate, mm/a; vm-mass transfer rate, mm/a; t-medium temperature, DEG C; pco2——CO2Partial pressure, MPa; pH valueact-the actual pH value; pH valueco2——CO2The pH of the saturated solvent; d-the inside diameter of the pipeline, m; u-liquid phase flow velocity of the medium, m/s;
306: and obtaining the corrosion rate along the pipeline.
Performing indoor experiment to verify the reliability of the corrosion rate prediction result
And if the corrosion rate prediction result is reliable, determining a corrosion high risk point in the wet natural gas:
calculating the critical inclination angle of the pipeline:
and comparing the inclination angle of the wet natural gas pipeline with the critical inclination angle, wherein the liquid accumulation risk exists when the inclination angle of the wet natural gas pipeline is larger than the critical inclination angle, and determining the area with the highest corrosion rate and the liquid accumulation risk as a wet natural gas corrosion high-risk section by combining the corrosion rate predicted in the third step.
If the corrosion rate prediction result is not reliable, the process returns to S1 to recalculate.
Drawings
FIG. 1 is a schematic flow chart of a method for identifying a section of high risk of corrosion in a wet natural gas pipeline according to the present invention;
FIG. 2 is a schematic view of a rough gas-liquid interface with curved surface in multiphase flow calculation according to the present invention;
FIG. 3 is a flow chart of multiphase flow calculation according to the present invention;
FIG. 4 is a flow chart of corrosion rate calculation according to the present invention;
FIG. 5 illustrates the calculation of a pressure at a section of a pipe according to the present invention;
FIG. 6 illustrates the calculation of a temperature for a section of a pipe according to the present invention;
FIG. 7 shows the results of the present invention in calculating a prediction of corrosion rate.
Detailed Description
For the purpose of better explaining the present invention and to facilitate understanding, the present invention will be described in detail by way of specific embodiments with reference to the accompanying drawings.
In the first step, three-dimensional multiphase flow simulation of the pipeline is carried out, and simulation parameters are shown in a table 1:
TABLE 1 pipeline parameters
Parameters were calculated in the following model:
momentum model under bipolar cylindrical coordinate system
Heat transfer model under bipolar cylindrical coordinate system
Phase change model under bipolar cylindrical coordinate system
And calculating to obtain parameters such as pipeline pressure, temperature, liquid holdup, gas-liquid flow rate and the like.
The gas medium at the inlet of the wet natural gas pipeline contains 0.44% of CO2H2S is not contained, so De Warr95 formula is chosen to predict:
in the formula: vcorr-corrosion rate, mm/a; vr-reaction rate, mm/a; vm-mass transfer rate, mm/a; t-medium temperature, DEG C; pco2——CO2Partial pressure, MPa; pH valueact-the actual pH value; pH valueco2——CO2The pH of the saturated solvent; d-the inside diameter of the pipeline, m; u-liquid phase flow velocity of the medium, m/s.
And calculating to obtain the corrosion rate along the line.
And (3) carrying out an indoor experiment to verify the reliability of the corrosion rate prediction result, wherein the indoor corrosion experiment device comprises the following components:
using 3 high-pressure gas cylinders, N respectively2Gas cylinder 1, H2S gas cylinder 2 and CO2The gas cylinder 3 is respectively provided with a first switch valve 8, a second switch valve 9 and a third switch valve 10, and is combined with the master control valve 4 to carry out air inlet control on the high-temperature high-pressure reaction kettle, test solution is added into the high-temperature high-pressure reaction kettle before the test, and N is introduced into the high-temperature high-pressure reaction kettle2Oxygen removal, CO control based on the composition of the medium in the natural gas pipeline2And H2The test temperature is controlled by the temperature controller 5, the test pressure is controlled by the pressure controller 6, the test piece is hung on the rotating shaft 12, the test piece is enabled to obtain the speed, and if an accident occurs during the test or the test is finished, the vent valve 11 can be opened to release the pressure.
And the predicted data and the experimental data are compared and analyzed, the prediction error of the corrosion rate is less than 20%, and the corrosion rate prediction is reliable.
Calculating the critical inclination angle of the pipeline:
and comparing the inclination angle of the wet natural gas pipeline with the critical inclination angle, wherein the liquid accumulation risk exists when the inclination angle of the wet natural gas pipeline is larger than the critical inclination angle, and determining the area with the highest corrosion rate and the liquid accumulation risk as a wet natural gas corrosion high-risk section by combining the corrosion rate predicted in the third step.
Claims (3)
1. A method for identifying a section with high risk of corrosion in a wet natural gas pipeline is characterized by comprising the following steps:
s1: establishing a momentum, heat transfer and phase change three-dimensional model under the bipolar column coordinates of the pipeline, carrying out multiphase flow simulation, and calculating the flow parameters of the pipeline;
201: establishing momentum model under bipolar cylindrical coordinate system
202: establishing heat transfer model under bipolar cylindrical coordinate system
203: establishing a phase change model under a bipolar cylindrical coordinate system
204: coupling 3 models, setting boundary conditions
205: calculating the pressure, temperature, gas and liquid flow rate and liquid holdup flow parameters in the outlet pipe,
in the formula: l-Lame coefficient;
-axial pressure drop, Pa/m; rho-density of gas or liquid phase, kg/m3(ii) a ω -the velocity of the gas or liquid phase in the axial direction, m/s;
-axial temperature drop, c/m; t-temperature of the medium, ° C; hL-liquid holdup; sLLiquid phase area, m2(ii) a S-pipe Cross-sectional area, m2；R0-pipe radius, m; h isL-liquid phase height, m; riThe radius of curvature of the liquid surface, m and theta are included angles and degrees of the wet wall; theta*Is the included angle of the liquid level;
s2: selecting a proper corrosion rate calculation model based on multiphase flow simulation parameters, and calculating the corrosion rate along the pipeline;
301: judging whether natural gas contains CO2And H2S；
302: absence of CO in natural gas2Does not contain H2S, calculating according to a Lafayette model:
the flow velocity of the liquid phase in the two-phase flow is less than 0.45m/s,
if the liquid phase flow rate is more than 0.45m/s, the CR is 1.92VL+6.33, where CR is the corrosion rate, mm/a; vLThe liquid phase flow rate, m/s;
303: if the natural gas contains CO2Judging whether H still exists in the natural gas2S；
304: if the natural gas contains CO2Also contains H2S, predicting according to an ECE formula:
in the formula: t-temperature of the medium, ° C; pH valueact-actual pH value, dimensionless;
——CO2the pH value of the saturated solvent is zero;
——CO2the fugacity coefficient of (A) is zero;
305: if the natural gas contains only CO2Does not contain H2S, predicted according to the following De Warr95 formula:
in the formula: vr-reaction rate, mm/a; v. ofm-mass transfer rate, mm/a;
——CO2partial pressure, MPa; d-the inside diameter of the pipeline, m; u-liquid phase flow velocity of the medium, m/s;
306: obtaining the corrosion rate along the pipeline;
s3: evaluating the reliability of the calculated result through an indoor corrosion experimental device;
s4: if the calculation is reliable, the step goes to S5, and if the calculation is not reliable, the step goes back to S1 for recalculation;
s5: and analyzing the probability and the corrosion degree of the accumulated liquid and determining a corrosion high risk point.
2. The method for identifying a section with high risk of corrosion in a wet natural gas pipeline according to claim 1, wherein in the calculating of the pipeline flow parameters:
firstly, accumulating all condensed liquid at the bottom of the pipeline; secondly, the flow pattern in the pipeline is gas-liquid stratified flow, and the flow in each calculation pipe section is stably developed; thirdly, the shape of the interface is described by adopting a curved surface rough gas-liquid interface model.
3. The method for identifying a section with high risk of corrosion in a wet natural gas pipeline according to claim 1, wherein the determination of the high risk point comprises:
and comparing the inclination angle of the wet natural gas pipeline with the critical inclination angle, determining that the liquid loading risk exists when the inclination angle of the wet natural gas pipeline is larger than the critical inclination angle, and determining that the area with the highest corrosion rate and the liquid loading risk is a wet natural gas corrosion high-risk section by combining the corrosion rate predicted by S2.
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| CN113051762B (en) * | 2021-03-30 | 2022-04-26 | 中国石油大学(华东) | Geothermal full-process corrosion rate correction method |
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| CN114062236B (en) * | 2021-11-12 | 2022-08-09 | 西南石油大学 | Local corrosion rate prediction model containing six factors of carbon dioxide and hydrogen sulfide |
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