Method and device for determining corrosion rate in natural gas pipeline

Abstract

The invention discloses a method and device for determining the corrosion rate in a natural gas pipeline, and relates to the technical field of natural gas pipelines. Correcting the basic corrosion rate according to the following formula to obtain the corrosion rate in the natural gas pipeline; wherein CR is the corrosion rate in the natural gas pipeline; cRbase is a basic corrosion rate; pCO2 is local pressure of CO2. According to the method, the corrosion rate model is corrected, and the corrosion rate can be calculated by means of the correction model on the premise of no detection data, so that the RBI evaluation result of the natural gas station pipeline is obtained, and a basis is provided for inspection and maintenance.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of natural gas pipeline, in particular to a method and device for determining the internal corrosion rate of natural gas pipeline. BACKGROUND

[0002] According to the process and corrosion condition of the natural gas transmission station device, the possible main damage types of the well station are determined after comprehensive analysis, including: a, internal corrosion thinning: uniform corrosion and local corrosion, internal corrosion thinning refers to the uniform thinning or local thinning of wall thickness caused by corrosion medium in the process, the well station contains CO2, so the natural gas process pipeline and equipment may occur uniform corrosion mainly caused by CO2+H2O corrosion, and local corrosion may occur in the position with water and impurity accumulation; b, external damage: atmospheric corrosion and external corrosion of buried pipeline, the external damage of the well station mainly includes atmospheric corrosion and external corrosion of buried pipeline; atmospheric corrosion refers to the corrosion caused by exposure to the atmosphere, the corrosion rate increases with the increase of temperature and the damage of coating, and the main position prone to occur is mainly concentrated in the pipeline support and flange joint with decreased coating effectiveness. However, since the ground main equipment and process pipeline of the well station have good coating quality, the external coating of the equipment and pipeline of the well station is set to be at an average level, and the degree of atmospheric corrosion is determined by software calculation. Therefore, the uncontrollable factor of the damage type is internal corrosion thinning.

[0003] For the case of internal corrosion thinning, the method for obtaining more accurate corrosion speed is based on detection data, that is, for the same object, the wall thickness value of the same position is recorded over time, and the corrosion rate is calculated by wall thickness and time. However, this method requires long-term data recording, and the requirements for professionals and management are high, so many natural gas stations are difficult to achieve. Therefore, there is an urgent need for a method for determining the corrosion rate of natural gas process pipeline in order to provide an important basis for its detection and maintenance and to ensure the safe and effective operation of the process pipeline in the station. SUMMARY

[0004] The present application aims to provide a method for determining the internal corrosion rate of natural gas pipeline to solve the above technical problems.

[0005] To achieve the above purpose, the present application provides a method for determining the internal corrosion rate of natural gas pipeline, which comprises:

[0006] obtaining the basic corrosion rate in the natural gas pipeline;

[0007] correcting the basic corrosion rate by the following formula to obtain the internal corrosion rate of the natural gas pipeline;

[0008]

[0009] wherein, CR is the internal corrosion rate of the natural gas pipeline; CR baseis the base corrosion rate; P CO2 is the CO2 partial pressure.

[0010] Optionally, the base corrosion rate is calculated according to the following formula:

[0011]

[0012] where CR base is the base corrosion rate; f(T, pH) is the temperature-pH function of the natural gas; S is the natural gas flow shear stress; f CO2 is the CO2 fugacity.

[0013] Optionally, the natural gas flow shear stress is obtained by:

[0014] obtaining the friction factor of the natural gas and the natural gas pipeline, the mass density of the natural gas, and the flow rate of the natural gas;

[0015] obtaining the natural gas flow shear stress according to the following formula based on the friction factor of the natural gas and the natural gas pipeline, the mass density of the natural gas, and the flow rate of the natural gas;

[0016]

[0017] where S is the natural gas flow shear stress; f is the friction factor of the natural gas and the natural gas pipeline; p m is the mass density of the natural gas; v m is the flow rate of the natural gas.

[0018] Optionally, the friction factor of the natural gas and the natural gas pipeline is obtained according to the following formula:

[0019]

[0020] where f is the friction factor of the natural gas and the natural gas pipeline; e is the absolute equivalent roughness of the natural gas pipeline wall; D is the diameter of the natural gas pipeline; is the relative roughness of the natural gas pipeline wall; Re is the natural gas Reynolds number.

[0021] Optionally, the natural gas Reynolds number is obtained according to the following formula:

[0022]

[0023] where Re is the natural gas Reynolds number; D is the diameter of the natural gas pipeline; p m is the mass density of the natural gas; u m is the viscosity of the natural gas; m is the mass flow rate of the natural gas; A is the cross-sectional area of the natural gas pipeline.

[0024] Optionally, the CO2 fugacity is obtained by:

[0025] obtaining the local pressure of CO2 and the temperature of natural gas;

[0026] obtaining the CO2 fugacity based on the local pressure of CO2 and the temperature of natural gas by the following formula:

[0027]

[0028] wherein, f CO2 is the CO2 fugacity; P CO2 is the local pressure of CO2; and T is the temperature of natural gas.

[0029] Optionally, the local pressure of CO2 is obtained according to the following formula:

[0030] P CO2 =b×P′

[0031] wherein, P CO2 is the local pressure of CO2; b is the volume fraction of CO2 in natural gas; and P' is the operating pressure of natural gas.

[0032] The application further provides a device for determining the corrosion rate in a natural gas pipeline, and the device comprises:

[0033] an obtaining unit for obtaining a basic corrosion rate in a natural gas pipeline;

[0034] a correction unit for correcting the basic corrosion rate by the following formula to obtain a corrosion rate in a natural gas pipeline:

[0035]

[0036] wherein, CR is the corrosion rate in a natural gas pipeline; CR base is the basic corrosion rate; and P CO2 is the local pressure of CO2.

[0037] The application further provides an electronic device, comprising: a processor coupled with a memory;

[0038] the processor is configured to read and execute a computer program stored in the memory to implement the method according to any one of the preceding embodiments.

[0039] The application further provides a computer readable storage medium, wherein a program or instruction is stored in the computer readable storage medium, and the program or instruction is executed by a processor to implement the method according to any one of the preceding embodiments.

[0040] Technical effects and advantages of the application:

[0041] The application provides a method for determining a corrosion rate in a natural gas pipeline, the method comprising: obtaining a basic corrosion rate in the natural gas pipeline; and correcting the basic corrosion rate by the following formula to obtain a corrosion rate in the natural gas pipeline: Wherein, CR is the corrosion rate in the natural gas pipeline; CR base is the basic corrosion rate; P CO2 is a local CO2 pressure.

[0042] The application can calculate the corrosion rate by the corrected model without detection data, thereby obtaining an RBI (Risk-Based Inspection) evaluation result of the natural gas station pipeline, and providing a basis for inspection and maintenance.

[0043] Other features and advantages of the application will be set forth in the following description, and in part will become apparent to those skilled in the art from the description, or can be learned by practice of the application. The objects and other advantages of the application will be realized and attained by the structure particularly pointed out in the written description and claims. BRIEF DESCRIPTION OF DRAWINGS

[0044] Figure 1 A flow chart of the method for determining the corrosion rate in the natural gas pipeline. DETAILED DESCRIPTION

[0045] The technical solutions in the embodiments of the application will be described clearly and completely below with reference to the drawings in the embodiments of the application. Obviously, the described embodiments are only some of the embodiments of the application, but not all the embodiments of the application. Based on the embodiments in the application, all other embodiments obtained by those skilled in the art without creative work fall within the scope of protection of the application.

[0046] It should be noted that the structures, proportions, sizes, etc. shown in the drawings attached to the specification are only used to understand and read the content disclosed in the specification by those skilled in the art, and do not define the limiting conditions for implementing the application, and therefore do not have technical significance. Any modification of the structure, change of the proportional relationship or adjustment of the size, without affecting the effects and purposes that can be achieved by the application, should still fall within the scope of the technical content disclosed by the application. Meanwhile, the terms such as "upper", "lower", "left", "right", "middle" and "one" in the specification are only for the convenience of clear description, and are not used to limit the scope of implementation of the application. The change or adjustment of the relative relationship, without substantially changing the technical content, is also regarded as the scope of implementation of the application.

[0047] To solve the problems in the prior art, the application discloses a method for determining the internal corrosion rate of a natural gas pipeline, as shown in the accompanying drawings. Figure 1

[0048] 1. Obtain the basic corrosion rate of the natural gas pipeline.

[0049] Specifically, the method comprises the following steps: 1.1 determining the shear stress of the natural gas flow

[0050] The shear stress S is calculated by modeling the influence of the fluid flow shear stress on the basic corrosion rate, and the unit of the shear stress S is Pa.

[0051]

[0052] In the formula, f represents the friction coefficient of the natural gas and the natural gas pipeline, v m represents the flow rate of the natural gas, and the unit of v m is m / s. 3 represents the mass density of the natural gas, and the unit of p

[0053] The calculation formula of the friction coefficient f of the natural gas and the natural gas pipeline is as follows:

[0054]

[0055] In the formula, f represents the friction coefficient of the natural gas and the natural gas pipeline, e represents the absolute equivalent roughness of the natural gas pipeline, the unit of e is mm, and e represents the statistical average of the protrusion height of the inner wall of the pipeline, D represents the diameter of the natural gas pipeline, and e represents the relative roughness of the natural gas pipeline. represents the Reynolds number of the natural gas. When the friction coefficient f is in a turbulent flow state, the Reynolds number Re of the mixture is greater than 2300.

[0056] The calculation formula of the Reynolds number Re is as follows:

[0057]

[0058] In the formula, D represents the diameter of the natural gas pipeline, the unit of D is meter, p m represents the viscosity of the mixture, the unit of p m is Pa s (0.001 cP = Pa s), p represents the mass density of the natural gas, m represents the mass flow rate of the natural gas, and A represents the cross-sectional area of the natural gas pipeline.

[0059] 1.2 determining the CO2 fugacity f CO2

[0060] The fugacity is in the unit of pressure, and the fugacity is used to replace the pressure or the local pressure in the calculation of the real replacement mixture balance. When the fugacity is used to replace the pressure, the equation of the ideal gas is used to model the real gas. ​

[0061]

[0062] where f CO2 is the CO2 fugacity; P CO2 is the CO2 partial pressure; and T is the temperature.

[0063] It is also noted that the CO2 partial pressure is obtained by the following equation:

[0064] P CO2 = b x P'

[0065] where P CO2 is the CO2 partial pressure; b is the volume fraction of CO2 in the natural gas (the volume fraction of CO2 in the natural gas can be found in the gas quality analysis report of the natural gas); and P' is the operating pressure of the natural gas.

[0066] 1.3 The natural gas temperature-pH function f(T, pH) is determined using a table lookup method, as shown in Table 1:

[0067] Table 1. pH and temperature value table

[0068]

[0069] The pH of the natural gas is determined by the following equation:

[0070] For condensing water: For Fe ++ saturated water:

[0071] For water with salinity higher than seawater (salinity = 46 g / l):

[0072]

[0073] where T is the temperature in °F and Pco2 is the CO2 partial pressure in psi.

[0074] 1.4 The following equation for the base corrosion rate in a natural gas pipeline is obtained from the parameters of 1.1-1.3

[0075]

[0076] where CR base is the base corrosion rate; f(T, pH) is the temperature-pH function of the natural gas; S is the natural gas flow shear stress; and f CO2 is the CO2 fugacity.

[0077] 2. The base corrosion rate is modified by the following equation to obtain the corrosion rate in a natural gas pipeline.

[0078]

[0079] CR = CR base + (P - P base) / P base base CR base is a base corrosion rate; CO2 P is a CO2 local pressure.

[0080] The application provides a method for determining a corrosion rate in a natural gas pipeline, the method comprising: obtaining a base corrosion rate in the natural gas pipeline; correcting the base corrosion rate by the following formula to obtain a corrosion rate in the natural gas pipeline: CR = CR base + (P - P base) / P base base CR base is a base corrosion rate; CO2 P is a CO2 local pressure. The application can calculate the corrosion rate by the corrected corrosion rate model without detection data, thereby obtaining an RBI evaluation result of the natural gas pipeline, and providing a basis for inspection and maintenance.

[0081] The application further provides a device for determining a corrosion rate in a natural gas pipeline, the device comprising:

[0082] An obtaining unit, configured to obtain a base corrosion rate in the natural gas pipeline;

[0083] A correcting unit, configured to correct the base corrosion rate by the following formula to obtain a corrosion rate in the natural gas pipeline:

[0084]

[0085] CR = CR base + (P - P base) / P base base CR base is a base corrosion rate; CO2 P is a CO2 local pressure.

[0086] Since the content protected by the device is similar to the content protected by the method, no more details are given here, and the detailed description is given in the description part of the method.

[0087] The application further provides an electronic device. The electronic device comprises at least one processor, at least one communication interface, at least one memory and at least one communication bus; optionally, the communication interface can be an interface of a communication module, such as an interface of a GSM module; the processor can be a processor CPU, or an application specific integrated circuit ASIC, or one or more integrated circuits configured to implement embodiments of the application. The memory can comprise a high-speed RAM memory, and can further comprise a non-volatile memory, such as at least one disk memory. The memory stores a program, and the processor invokes the program stored in the memory to execute the method provided in the above embodiments.

[0088] Corresponding to the method described above, the application further provides a computer storage medium. The computer storage medium stores a computer program, and the computer program is run by a processor to execute the method provided in the above embodiments.

[0089] Finally, it should be noted that: the above only for the preferred embodiments of the application, and not for limiting the application, although the application has been described in detail with reference to the foregoing embodiments, for those skilled in the art, it still can be modified to the technical scheme recorded in the foregoing embodiments, or equivalent replacement of some technical features, within the spirit and principles of the application, any modification, equivalent replacement, improvement, etc., should be included in the protection scope of the application.

Claims

1. A method of determining the rate of internal corrosion of a natural gas pipeline, characterized by, The method comprises: obtaining a base corrosion rate in a natural gas pipeline; correcting the base corrosion rate by the following formula to obtain a corrosion rate in the natural gas pipeline; where CR is the corrosion rate in the natural gas pipeline; CR base is the base corrosion rate; P CO2 is the local pressure of CO2.

2. The method of claim 1, wherein, the formula of the base corrosion rate is as follows: where CR base is the base corrosion rate; f(T, pH) is the temperature-pH function of the natural gas; S is the natural gas flow shear stress; f CO2 is the CO2 fugacity.

3. The method of claim 2, wherein, obtaining the natural gas flow shear stress, comprising: obtaining a friction coefficient of the natural gas and the natural gas pipeline, a mass density of the natural gas and a flow rate of the natural gas; obtaining the natural gas flow shear stress by the following formula based on the friction coefficient of the natural gas and the natural gas pipeline, the mass density of the natural gas and the flow rate of the natural gas; where S is the natural gas flow shear stress; f is the friction coefficient between the natural gas and the natural gas pipeline; p m is the natural gas mass density; v m is the natural gas flow rate.

4. The method of claim 3, wherein, obtaining the friction coefficient of the natural gas and the natural gas pipeline according to the following formula: wherein f is the friction coefficient of the natural gas with the natural gas pipeline; e is the absolute equivalent roughness of the natural gas pipeline pipe wall; D is the diameter of the natural gas pipeline; is the relative roughness of the natural gas pipeline pipe wall; Re is the natural gas Reynolds number.

5. The method of claim 4, wherein, obtaining the natural gas Reynolds number according to the following formula: where Re is the natural gas Reynolds number; D is the diameter of the natural gas pipeline; p m is the mass density of the natural gas; u m is the viscosity of the natural gas; m is the mass flow rate of the natural gas; and A is the cross-sectional area of the natural gas pipeline.

6. The method of claim 2, wherein, obtaining the CO2 fugacity, comprising: obtaining a local pressure of CO2 and a temperature of the natural gas; obtaining the CO2 fugacity by the following formula based on the local pressure of CO2 and the temperature of the natural gas; where f CO2 is the CO2 fugacity; P CO2 is the CO2 partial pressure; T is the temperature of the natural gas.

7. The method of claim 6, wherein, obtaining the local pressure of CO2 according to the following formula: PcO2=b×P' where P CO2 is the local pressure of CO2; b is the volume fraction of CO2 in the natural gas; P' is the operating pressure of the natural gas.

8. An apparatus for determining the rate of internal corrosion of a natural gas pipeline, comprising: The device comprises: an obtaining unit, configured to obtain a base corrosion rate in a natural gas pipeline; a correcting unit, configured to correct the base corrosion rate by the following formula to obtain a corrosion rate in the natural gas pipeline; where CR is the corrosion rate in the natural gas pipeline; CRbas e is the base corrosion rate; P CO2 is the local pressure of CO2.

9. An electronic device comprising: a processor coupled with the memory; the processor is configured to read and execute a computer program stored in the memory to implement the method of any one of claims 1-7. 10.A computer readable storage medium, wherein a program or instruction is stored, and the program or instruction is executed by a processor to implement the method of any one of claims 1-7.

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