Corrosion resistance of some downhole tubing materials were studied in a recirculating flow loop simulating conditions that induce flow enhanced corrosion. The selected materials included carbon steels (AISI 1018, API X-52), coiled tubing, O.5% Cr, and 13% Cr (AISI 420) martensitic steel The X-52 steel showed the worst resistance to both general and localized corrosion while 13 Cr demonstrated the best performance. The corrosion resistance of the other three materials varied with the conditions. Hydrocarbons were found to have an effect on varying the corrosion rates. All of these materials can be protected with a continuous treatment of corrosion inhibitors. However, the inhibitors were found less effective on coiled tubing and O.5% Cr steel than carbon steels, regardless of applications simulated (batch or continuous). The decreased efficiency is attributed to the enrichment of Cr in the surface film on which inhibitors are less favorably adsorbed.


Sweet (CO2) corrosion is one of the major problems in oil and gas production. Corrosion occurs in all stages of production, from downhole to surface equipment and further to the processing facilities. Two important factors that lead to sweet corrosion are presence of C02 gas and chloride ion, both prompting higher corrosion rates. 1>Extensive research has been carried out in order to better understand and to more effectively control sweet corrosion. The scope of this paper is also focused on sweet corrosion and, in particular, on downhole tubulars, Corrosion failures of downhole tubing can be costly due to lost avenues from missing production and the high cost of workover. Therefore, control of downhole tubular corrosion has been a major challenge to the oil and gas producers.

There are two popular solutions to sweet corrosion control. One is the metallurgical solution with corrosion resistance alloys (CRA). The other is the chemical solution by the use of corrosion inhibitors. CRA?s offer the advantages of (1) superior corrosion resistance and thus extended service life, (2) thinner wall and thus increased productivity, and (3) higher mechanical strengths and thus allowing better tubing string design. However, the high initial capital cost demanded by this option makes it restrictive, especially for the small producers. Chemical inhibition is another viable option, especially for low production wells or short-life wells. Fine tuning the inhibition program is necessary to achieve adequate protection while continuing to improve the cost performance. The producer runs the risk of corrosion failures if the inhibition program is not implemented properly.

Among all CRA?S, the use of AISI 420 martensitic stainless steel containing 13% chromium (hereafter referred to as 13 Cr) in oilfield has been increasing due to its improved resistance to sweet corrosion and the reduced cost. In addition, 13 Cr is more appealing when considering workover cost and inhibitor cost/risk. In fact, usage of 13 Cr accounts for over 50% of total CRA?s in OCTG (oil country tubular goods). 13 Cr has demonstrated outstanding performance against sweet corrosion in the field. However, 13 Cr is less resistant to localized corrosion at elevated temperatures (> 120- 150°C) and is susceptible to SSC (sulfide stress cracking) even at a low H2S partial pressure (> 0.3-10 kPa).14?15 These temperature and pressure limits have been raised by the recent development of new martensitic steels. This includes the 15%Cr steel G and a group of super 13 Cr. 17-20The latter is a modified 13 Cr prepared by reducing the C content while adding NI and Mo. ]1 Another popular, but more expensive, CRA is duplex stainless steels which are used in more severe environments

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