Martensitic stainless steel material, 13Cr (UNS 42000) and Super S13Cr-6Ni-2Mo (UNS S41426), tubing is used in producing oil and gas wells due to their corrosion resistance compared to low alloy steels. However, the industry is often anxious to turn these producing wells around for seawater injection or saltwater disposal in which case the presence of oxygen must be considered which significantly influences the corrosion behavior. The risk for localized corrosion (i.e., pitting and crevice corrosion) in highly concentrated chloride environments is dependent on the dissolved oxygen level, temperature, and chloride content. A laboratory study was performed for 13Cr and S13Cr materials in high chloride water at various dissolved oxygen concentrations at specific temperatures based on OLI modeling. Based on the test results, 13Cr is susceptible to localized corrosion with dissolved oxygen in 10-100 ppb range. No such localized corrosion was observed for S13Cr material.
It has become somewhat common in the oil and gas industry to convert producing wells containing 13Cr stainless steels to water injection wells. This practice has led to numerous tubing failures due to pitting of the 13Cr from oxygen dissolved in the injection water. The water source for these wells is often from produced water and seawater but other waters may also be injected. The principal corrosive agent in water injection is dissolved oxygen (DO) with little or no contribution to corrosion from CO2 and/or H2S. It is often mistakenly believed that DO can be managed to the required < 10 part per billion (ppb) for the entire life of an injection well with no disruptions or excursions, but actual field experience shows the contrary.
There is wide industry experience with 13Cr tubing for water injection service most all of it bad. The inability to maintain the DO content below 10 ppb constantly and consistently has resulted in rapid failure of 13Cr tubing in water injection wells. Most often the failures occur within about 6 months of the start of injection. Although not many case studies of these failures have been formally presented it is known that several fields in the Gulf of Mexico (GoM) had such experience when their 13Cr injection tubing pitted in 6 months. Other reports from offshore West Africa and onshore US have expressed the same time frame for failure of 13Cr. In another case an operator limited the DO content of injection water in North Sea wells to 80 ppb but after the 13Cr string was pulled it was found to be badly pitted.1 Subsequently, it was determined that daily biocide treatments caused the DO content to reach 2000 ppb each day for a short period of time. Scoppio and Nice reported on pitting and crevice corrosion in the 13Cr injection tubing in the Gullfaks Field (North Sea) from seawater injection.2 The failure of 13%Cr was determined to be due mainly to poor deaeration of the injected seawater.
