Processes and systems for predicting corrosion

Patent metadata

Field	Value
Publication number	US-9317635-B2
Application number	US-201313929037-A
Country	US
Kind code	B2
Filing date	Jun 27, 2013
Priority date	Jun 29, 2012
Publication date	Apr 19, 2016
Grant date	Apr 19, 2016

Abstract

Systems and methods for evaluating the corrosion risk in operations with equipment for the handling an acid gas-containing solutes, e.g., an amine unit for the removal of acid gases such as H 2 S, CO 2 , etc., are provided. Input parameter values corresponding to geometrical parameters of at least an equipment (or a portion of an equipment) susceptible to corrosion risk, operating parameters, fluid dynamic properties, and properties of the solute are received by the system. Based on the input values, the systems and methods derive a minimum pressure above which acid gas flashing occurs given the localized pressure drop, causing corrosion in the identified location. In one embodiment, the systems and methods provide an assessment correlating acid gas loadings with the corrosion risk.

First claim

The invention claimed is:

1. A method for evaluating corrosion risk in a unit handling an acid gas-containing solute, comprising:
identifying at least a location in the unit for conducting the corrosion risk evaluation;
receiving information about geometrical parameters of the location;
receiving information about operating parameters, fluid dynamic properties, and properties of the solute in the unit;
correlating fluid dynamics of the location in the unit with a shear stress value;
predicting a corrosion rate for different acid gas loadings expressed as concentration of the acid gas in the solute responsive to the correlated shear stress;
evaluating a localized pressure drop in the location due to the geometrical parameters;
correlating a relationship between vapor saturation pressure and temperature data for the different acid gas loadings;
identifying from the correlated vapor saturation pressure and temperature data a minimum pressure above which acid gas flashing from the solute occurs given the localized pressure drop, causing corrosion in the identified location.

2. The method of claim 1 , further comprising:
displaying the predicted corrosion rate as a function of the different acid gas loadings as a visual display.

3. The method of claim 1 , wherein the acid gas is H 2 S, the solute is amine, and the acid gas loadings are expressed as moles of H 2 S per mole of amine.

4. The method of claim 1 , further comprising
correlating the minimum pressure below which acid gas flashing of acid gas occurs with a maximum acid gas loading for the identified location.

5. The method of claim 4 , further comprising:
adjusting the acid gas loading to the unit to keep the acid gas loading below the maximum acid gas loading for the identified location.

6. The method of claim 1 , wherein the relationship between vapor saturation pressure and temperature data for the different acid gas loadings is correlated using a physical property software.

7. The method of claim 1 , wherein the relationship between vapor saturation pressure and temperature data for the different acid gas loadings is correlated using an empirical model.

8. The method of claim 1 , wherein the location is selected from any of a reducer, an elbow, an orifice plate, a negative step, a positive step, a slot, a pressure let down valve, and bottom of an absorber.

9. The method of claim 1 , wherein the location is a tube sheet end of a heat exchanger.

10. The method of claim 1 , wherein predicting a corrosion rate for different acid gas loadings responsive to the correlated shear stress comprises:
calculating corrosion rate for different concentrations of acid gas in the solute as acid gas loadings under static conditions using at least an empirical correlation;
calculating corrosion rate for different concentrations of acid gas in the solute as acid gas loadings under flowing conditions using at least an empirical correlation; and
interpolating the calculated corrosion rate taking into account the correlated shear stress to obtain a corrosion rate for different concentrations of acid gas in the solute as acid gas loadings.

11. The method of claim 1 , wherein predicting a predicted corrosion rate for different acid gas loadings responsive to the correlated shear stress comprises:
providing a database containing corrosion rate data for different concentrations of acid gas in the solute under different static and flowing conditions;
obtaining from the database a predicted corrosion rate for different concentrations of acid gas in the solute as acid gas loadings; and
interpolating the predicted corrosion rate for different concentrations of acid gas in the solute as acid gas loadings taking into account the correlated shear stress.

12. The method of claim 1 , wherein the corrosion risk evaluation is conducted for a plurality of locations in the unit to identify a maximum gas loading rate for each of the plurality locations.

13. The method of claim 12 , where the location having a lowest maximum gas loading rate is identified for corrosion risk monitoring.

14. The method of claim 1 , further comprising carrying out the corrosion risk evaluation for the at least a location under at least one of: varying solute types; varying acid gas concentrations in the solute; varying concentrations of the solute; varying temperatures; and combinations thereof.

15. The method of claim 1 , wherein receiving information about operating parameters, fluid dynamic properties, and properties of the solute in the unit comprises
obtaining at least one of operating parameters, fluid dynamic properties, and properties of the solute in the unit from an on-line sensor; and
obtaining at least one of operating parameters, fluid dynamic properties, and properties of the solute in the unit from data entry by an operator.

16. The method of claim 1 , for evaluating corrosion risk in any of an amine unit, a Reactor Effluent Air Cooler (REAC), a steam generation unit, and an alkylation unit.

17. A method for evaluating corrosion risk in an amine unit for removing H 2 S acid gas, comprising:
identifying a plurality of locations in the amine unit to identify a maximum acid gas loading for each location;
receiving information about geometrical parameters of each location;
receiving information about operating parameters, fluid dynamic properties, and properties of amine in the amine unit;
correlating fluid dynamics of each location in the amine unit with a shear stress value;
predicting a corrosion rate for each location at different concentrations of H 2 S in amine as acid gas loadings expressed as concentration of H 2 S in amine responsive to the correlated shear stress for each location;
evaluating localized pressure drop in each location due to the geometrical parameters;
correlating a relationship between vapor saturation pressure and temperature data for the different acid gas loadings; and
identifying from the correlated vapor saturation pressure and temperature data a maximum acid gas loading for each of the identified locations, given the localized pressure drop in each location, above which maximum loading rate flashing of H 2 S occurs.

18. The method of claim 17 , further comprising:
identifying a location having the lowest maximum acid gas loading; and
monitoring the location having the lowest maximum acid gas loading for corrosion risk.

19. The method of claim 18 , further comprising:
adjusting the acid gas loading to the amine unit to below the lowest identified maximum acid gas loading.

20. The method of claim 17 , wherein the relationship between vapor saturation pressure and temperature data for different acid gas loadings is correlated using a physical property software.

21. The method of claim 17 , wherein the location is selected from any of a reducer, an elbow, an orifice plate, a negative step, a positive step, a slot, a pressure let down valve, and bottom of an absorber.

22. The method of claim 17 , wherein the location is a tube sheet end of a heat exchanger.

23. The method of claim 17 , wherein the relationship between vapor saturation pressure and temperature data for different acid gas loadings is correlated using a physical property software.

24. The method of claim 17 , wherein the relationship between vapor saturation pressure and temperature data for different acid gas loadings is correlated using an empirical model.

25. The method of

Assignees

• O'Connor Andrew Thomas
• El Giheny Kyrolos Paul
• Parten Sara Christine
• Crowder Benjamin Roy
• Cooke David Lawrence
• Stepanov Eugene Vladimirovich
• Suzuki Teppei
• Welch Bart Quentin
• Chevron Usa Inc

Inventors

• O'Connor Andrew Thomas
• El Giheny Kyrolos Paul
• Parten Sara Christine
• Crowder Benjamin Roy
• Cooke David Lawrence
• Stepanov Eugene Vladimirovich
• Suzuki Teppei
• Welch Bart Quentin

Classifications

• B01D2257/504

  Carbon dioxide · CPC title

• G06F2111/10

  Numerical modelling · CPC title

• B01D53/1412 Primary

  Controlling the absorption process · CPC title

• B01D53/1456

  Removing acid components · CPC title

• G01N17/02

  Electrochemical measuring systems for weathering, corrosion or corrosion-protection measurement · CPC title