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The method for detecting stress corrosion cracking (SCC) of pipelines, comprising the steps of: identifying pipeline locations and pipeline conditions that are amenable to inspection by a magnetic flux inline tool and by a TFI tool; performing two inspections on the pipeline, one inspection performed using the magnetic flux inline (MFL) tool and an other inspection performed using the TFI tool; aligning signal features resulting from the two inspections; identifying TFI signals occurring above a specified threshold; identifying MFL signals for a section of pipeline corresponding to the identified TFI signals; for the identified TFI signals, determining whether the MFL signals are below a second threshold level; designating the sections of the pipeline corresponding to identified TFI signals above the threshold and below the second threshold as a potential corrosion feature; identifying TFI signals that exceed a defined metal loss percentage; measuring a width and length of the signal features, and if the width and length of the signal feature exceed threshold crack width and length values, designating as a potential corrosion feature section of pipeline corresponding to the identified TFI signals.

Titel:	METHOD AND APPARATUS INSPECTING PIPELINES USING MAGNETIC FLUX SENSORS
Autor/in / Beteiligte Person:	Gao, Ming ; Limon, Sergio ; McNealy, Richard Clark ; Sherstan, Ron
Link:	View record in USPTO Patent Applications (Volltext)
Veröffentlichung:	2007
Medientyp:	Patent
Sonstiges:	Nachgewiesen in: USPTO Patent Applications Sprachen: English Document Number: 20070222436 Publication Date: September 27, 2007 Appl. No: 11/277523 Application Filed: March 27, 2006 Assignees: General Electric Company (Schenectady, NY, US) Claim: 1. A method for detecting stress corrosion cracking (SCC) of pipelines, comprising: identifying pipeline locations and pipeline conditions that are amenable to inspection by a magnetic flux tool; performing two inspections on the pipeline, one inspection performed to collect the magnetic flux inline (MFL) data and an other inspection performed using TFI data; aligning signal features resulting from the MFL and TFI data; evaluating a number of features indicated by the MFL and TFI data, the features including potential crack field features and potential corrosion features, and based upon results of the evaluation identifying potential crack fields for physical inspection. Claim: 2. The method of claim 1 wherein identifying potential crack fields for physical inspection includes performing at least one of: excavating and inspecting all locations associated with the features, and excavating and inspecting a selected number of locations associated with the features. Claim: 3. The method of claim 1 wherein the identifying pipeline locations and pipeline conditions includes determining whether a pressure in the pipeline is sufficient to perform the inspections. Claim: 4. The method of claim 1 wherein the potential crack field features are determined by a process comprising: identifying TFI data variations occurring above a specified threshold; identifying MFL data for a section of pipeline corresponding to the identified TFI data; for the identified TFI data, determining whether MFL data variations are below a second threshold level; designating the sections of the pipeline corresponding to identified the TFI data above the threshold and below the second threshold as a potential corrosion feature. Claim: 5. The method of claim 1 wherein the potential corrosion features are determined by a process comprising: identifying TFI signals that exceed a defined metal loss percentage; measuring a width and length of the signal features, and if the width and length of the signal feature exceed threshold crack width and length values, designating as a potential corrosion feature section of pipeline corresponding to the identified TFI signals. Claim: 6. The method of claim 1 wherein the potential crack field features are determined by a process comprising: identifying TFI signals occurring above a specified threshold; identifying MFL signals for a section of pipeline corresponding to the identified TFI signals; for the identified TFI signals, determining whether the MFL signals are below a second threshold level; designating the sections of the pipeline corresponding to identified TFI signals above the threshold and below the second threshold as a potential corrosion feature; identifying TFI signals that exceed a defined metal loss percentage; measuring a width and length of the signal features, and if the width and length of the signal feature exceed threshold crack width and length values, designating as a potential corrosion feature section of pipeline corresponding to the identified TFI signals. Claim: 7. The method of claim 1 wherein the designated sections of the pipeline corresponding to identified TFI signals above the threshold and below the second threshold as a potential corrosion feature are listed in a priority list and the list is used to determine which crack fields to be physically evaluated. Claim: 8. The method of claim 1 wherein the physical evaluation comprises excavating the pipeline in an area identified as potential corrosion feature. Claim: 9. The method of claim 1 wherein the two inspections are performed simultaneously. Claim: 10. The method of claim 1 wherein the two inspections are performed sequentially. Claim: 11. A method for detecting stress corrosion cracking (SCC) of pipelines, comprising: identifying pipeline locations and pipeline conditions that are amenable to inspection by a magnetic flux inline tool and by a TFI tool; performing two inspections on the pipeline, one inspection performed using the magnetic flux inline (MFL) tool and an other inspection performed using the TFI tool; aligning signal features resulting from the two inspections; identifying TFI signals occurring above a specified threshold; identifying MFL signals for a section of pipeline corresponding to the identified TFI signals; for the identified TFI signals, determining whether the MFL signals are below a second threshold level; designating the sections of the pipeline corresponding to identified TFI signals above the threshold and below the second threshold as a potential corrosion feature; identifying TFI signals that exceed a defined metal loss percentage; measuring a width and length of the signal features, and if the width and length of the signal feature exceed threshold crack width and length values, designating as a potential corrosion feature section of pipeline corresponding to the identified TFI signals. Claim: 12. The method of claim 11 wherein identifying potential crack fields for physical inspection includes performing at least one of: excavating and inspecting all locations associated with the features, and excavating and inspecting a selected number of locations associated with the features. Claim: 13. The method of claim 11 wherein the identifying pipeline locations and pipeline conditions includes determining whether a pressure in the pipeline is sufficient to perform the inspections. Claim: 14. The method of claim 11 wherein the physical evaluation comprises excavating the pipeline in an area identified as potential corrosion feature. Claim: 15. The method of claim 11 wherein the two inspections are performed simultaneously. Claim: 16. The method of claim 11 wherein the two inspections are performed sequentially. Claim: 17. A computer program product for detecting stress corrosion cracking (SCC) of pipelines, the computer program product including instructions for performing: identifying pipeline locations and pipeline conditions that are amenable to inspection by a magnetic flux inline tool and by a TFI tool; performing two inspections on the pipeline, one inspection performed using the magnetic flux inline tool and an other inspection performed using the TFI tool; aligning signal features resulting from the two inspections; evaluating results of the aligning, comprising: determining a number of features detected by the two inspections, the features including potential crack field features and potential corrosion features; and based upon results of the evaluating, performing at least one of: excavating and inspecting all locations associated with the features; and excavating and inspecting a selected number of locations associated with the features. Claim: 18. The computer program product of claim 17, wherein the identifying pipeline locations and pipeline conditions includes: gathering pipeline information including: past inspection results; pipeline operating conditions; and pipeline specifications; and based upon the evaluating, determining whether a specified inspection tool is capable of returning accurate inspection data relating to the condition of the pipeline. Claim: 19. The computer program product of claim 17, wherein the past inspection results includes: number of defects in the pipeline; size of the defects in the pipeline; extent of the defects in the pipeline; and a critical size determined for each of the defects. Claim: 20. The computer program product of claim 6, wherein the potential crack field features are determined by: identifying TFI signals occurring above a specified threshold; for TFI signals occurring above the specified threshold, identifying any potential crack field patterns; for TFI signals that are identified with a pattern, analyzing magnetic flux inline data that are aligned with TFI signals identified with the pattern; determining a likelihood of presence of stress corrosion cracking for features associated with the pattern where results of the analyzing magnetic flux inline data indicate a lack of signal and where a TFI signal is present. Current U.S. Class: 324/220 Current International Class: 01

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METHOD AND APPARATUS INSPECTING PIPELINES USING MAGNETIC FLUX SENSORS