PSI - Issue 80

G. Mubarak et al. / Procedia Structural Integrity 80 (2026) 157–168 Author name / Structural Integrity Procedia 00 (2019) 000 – 000

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1. Introduction Carbon steels, widely used in oil and gas production tubing under API 5CT standards, are increasingly vulnerable to corrosion-related failures [1] . CO₂ corrosion, or sweet corrosion, is a dominant degradation mechanism in such environments [2] , influenced by factors like temperature, CO₂ partial pressure, chloride content, pH, and steel properties [3] . Under certain conditions, protective iron carbonate (FeCO₃) films can form, but their instability can lead to localized corrosion due to galvanic effects [3] – [8]. The presence of chloride ions [9] and H₂S [10] – [12] further intensifies corrosion risks, especially in sour and deepwater environments [13]. Effective mitigation using corrosion inhibitors has shown promise in improving steel performance [14], [15]. While experimental investigations remain common [16] – [21], few studies incorporate predictive modeling [22], [23]. This work presents a combined experimental and modeling-based failure analysis of downhole tubing, aiming to support corrosion prediction and enhance integrity management. 2. Methodology 2.1 Experimental testing Visual inspection was conducted on both internal and external surfaces of a failed API 5CT J55 carbon steel tubing from an operational well, including longitudinally sectioned samples and fracture faces. The tubing, retrieved from a well with a True Vertical Depth (TVD) of 2885 m (1055 mKB), had a 60.3 mm outer diameter (OD), 50.7 mm inner diameter (ID), and 4.83 mm wall thickness (WT). It was exposed to natural gas, condensate, and produced water. Figure 1 shows the failed samples as received in three pieces: a long sample, a short sample, and a plastic container holding corrosion products/scale removed from near the failure. Chemical spot tests were performed prior to surface cleaning. Post-sandblasting, fracture surfaces were examined using a Carl Zeiss ™ STEMI 2000-C stereo microscope. Corrosion products from both surfaces and scale samples were analyzed via X-ray Diffraction (XRD) and Energy Dispersive X-ray Spectroscopy (EDS). The bulk chemical composition was determined using optical emission spectroscopy per ASTM E415-17 [24], and hardness measurements were taken near and away from the fracture zone.

Figure 1: Overview of all pieces of failed downhole tubing, including scale sample in plastic container.

2.2 Corrosion modelling Corrosion modeling was conducted on the tubing section between the wellhead and the first open-hole packer, using operational data provided by the well operator, including depth profiles, production volumes, and fluid compositions. To streamline analysis, the simulation period was divided into two intervals: the first and last 30 days of production, providing representative operating ranges without evaluating each time step individually. Due to model limitations, certain adjustments were made: sub- zero temperatures were replaced with 0 °C, conservative values were applied for H₂S concentrations, and elemental sulfur was set to zero due to insufficient sampling data. Total soluble solids (TSS) were estimated from entered concentrations, and dissolved oxygen was excluded based on anaerobic conditions expected at downhole depths. The modeling was performed using the iFILMS ® software by CorrMagnet Consulting Inc., with pitting corrosion rate (PCR) as the primary output.