Stress corrosion cracking behavior of super 13Cr tubing in phosphate packer fluid of high pressure high temperature gas well

This paper describes a stress corrosion cracking (SCC) failure case of super 13Cr tubing serviced for six years in a high-pressure, high-temperature (HPHT) gas well. The failure causes and processes were studied by various characterizations and SCC simulation testing. The failure mode of super 13Cr tubing is brittle transgranular fracture, and the dominating role in SCC failure is the synergistic action of KH2PO4 phosphate packer fluid and CO2, leading to corrosion damaged zone, which is a selective corrosion along the martensitic multiscale boundaries. Under tensile stress, cracks developed at the corroded martensitic multiscale boundaries and propagated due to the low structural strength of the corrosion-damaged zone. Due to its compatibility with 13Cr tubing, formate is recommended as an alternate packer fluid for high-pressure, high-temperature (HPHT) gas wells.

Automated summary

This paper describes a case of stress corrosion cracking (SCC) failure in super 13Cr tubing used for six years in a high-pressure, high-temperature (HPHT) gas well. The study analyzed the failure causes and processes through various characterizations and SCC simulation testing. The failure mode of the tubing was identified as brittle transgranular fracture, with the synergistic action of KH2PO4 phosphate packer fluid and CO2 playing a dominant role in SCC failure. The corrosion damaged zone, which selectively corroded along the martensitic multiscale boundaries, was found to be the main reason for crack development and propagation. The use of formate as an alternate packer fluid for HPHT gas wells, due to its compatibility with 13Cr tubing, is recommended.