Recent reports have highlighted hydrogen embrittlement (HE) of high strength, quench-and-temper (Q&T) coiled tubing (CT) resulting from hydrochloric (HCl) acid usage in sour environments. HCl acid treatments expose CT surfaces to aggressive corrosion, often exacerbated by H2S from formation fluids or as a chemical reaction. Helping the CT industry recognize the morphologies of damage when the tube is retired and re-evaluating the CT grade selection and chemicals are vital for averting costly and dangerous CT failures.
To establish a comprehensive case history preceding the CT failure mode, pertinent field data must be collected and correlated, encompassing job frequency, acid and H2S exposure duration, concentration levels, downhole conditions, and inhibition procedures. Metallurgical analysis, including an exhaustive battery of tests, was conducted on the specimens: visual assessment, dimensional verification, fractography, metallographic analysis, mechanical integrity evaluation (comprising hardness and tensile testing), scanning electron microscopy (SEM), and energy-dispersive X-ray spectroscopy (EDS), along with sodium azide spot testing.
A summary of field failures was evaluated from diverse operational environments and locations. Multiple factors contributed to premature CT retirement, particularly inadequate corrosion inhibition and sulfide scavenger programs. However, environmental conditions, operational stresses, microstructural differences, and susceptibilities of various high-grade materials (Q&T and conventional) were correlated and compared with industry research. Low pH fluids like hydrochloric acid or other acidic substances combined with H2S presence created a susceptibility for the high-grade CT materials consistent with other high strength oil and gas carbon steel materials. Material properties, specifically tensile strength and hardness showed a distinct susceptibility to HE with increasing tensile strength. Steels with tensile strengths below 140-ksi are relatively less vulnerable to HE, but susceptibility significantly escalates beyond this threshold. Typically, low cycle fatigue promoted complete through-wall crack propagation, with some cases demonstrating fatigue originating from the steel centerline, where hydrogen ions from acid tend to migrate and recombine as gas. Other initiation points include the OD/ID surfaces and the longitudinal weld. These initiation points demonstrated consistent hydrogen embrittlement intergranular failure mechanisms.
Recent materials research in the Oil and Gas space related to HE and H2S exposure on materials similar to coiled tubing was evaluated for relevance. Two interesting areas of research are presented: fracture propagation theories with hydrogen presence related to fatigue environments, and the influence of various iron sulfide films resulting from the corrosion reaction of H2S and steel.
Sour immersion testing results on high strength coiled tubing are also presented to demonstrate the effectiveness of commercially available inhibitors compared to no inhibition, with good results on Q&T coiled tubing.
This study emphasizes the vital need to evaluate well conditions and working fluids compatibility (including inhibition) with CT materials to prolong CT operational life. Additionally, this study details the morphology of H2S-induced CT failures in acid stimulations, whether due to HE, Sulfide Stress Cracking (SSC), or Stress Corrosion Cracking (SCC), giving insight to future job planning. Prioritizing prevention planning with robust corrosion management is crucial for prolonging overall service life and minimizing operational disruptions in acidic environments using high strength Q&T CT.
