A thorough characterization of nickel-based UNS N09955 was performed in a simulated sour production wellbore environment for high-pressure, high-temperature (HPHT) subsea applications. The test environment chemistry was 1.14 mol% of carbon dioxide (CO2), 0.4-psia fugacity of hydrogen sulfide (H2S), 240,000 mg/L of chlorides, dissolved oxygen less than 10 ppb, and a pH of 4.2, at 400 °F (204 °C) temperature. Environmentally assisted cracking (EAC) susceptibility was evaluated by fracture toughness (FT) test using compact tension test specimens and rising displacement method. Fatigue crack growth rate (FCGR) and static crack growth rate (SCGR) were studied in the HPHT environment. FT testing indicated a moderate reduction in the initiation FT value of the alloy in HPHT condition compared with the in-air value. FCGR testing was performed at different frequencies and at maximum stress intensity factor (Kmax) (or stress intensity range [ΔK]) values. At a Kmax value of 55 MPa√m, FCGR increased at low frequencies, which may have been associated with the crack front sampling the susceptible orientation. However, at Kmax values of 66, 75, and 85 MPa√m, there was no or little evidence of an increase in FCGR at low frequencies. Additionally, no evidence of a stable SCGR was observed over a range of Kmax values from 55 to 85 MPa√m, supporting the fact that the threshold stress intensity factor (Kth) of Alloy 955 is greater than 85 MPa√m in the tested environment. Finally, scanning electron microscopy (SEM) was used to characterize the fracture surface morphology and crack-growth behavior of Alloy 955. Ductile features for in air FT test and evidence of dislocation slip band cracking and fatigue striations were observed for environmental tests.
Precipitation-hardened nickel-based alloys have been used for decades in the oil and gas industry. Among these alloys, UNS1 N07718 has received the most attention for use in upstream applications such as tubing hangers, production stab plate, multiphase flowmeter bodies, and valve stems because of its performance in sour wellbore fluids (SWFs) and hydrogen-charging environments. It has been reported that the alloy’s performance is excellent for applications up to 350 °F (175 °C) to 400 °F (204 °C) in exposed wellbore environments such as sour production fluids and completion brines and when externally exposed to seawater with cathodic protection (SWCP) at seabed temperatures. However, at higher temperatures, it becomes vulnerable to localized corrosion and stress corrosion cracking, especially in low-pH and higher-chloride-containing environments.1 Studies have shown that other well-known corrosion-resistant alloys (CRA’s), such as Alloy 725 (UNS N07725) and Alloy 625+ (UNS N07716), are susceptible to hydrogen embrittlement in SWCP conditions.2–5 Therefore, these alloys, which have excellent resistance to localized corrosion and stress corrosion cracking in elevated temperature sour production fluids, are associated with higher risk for applications where the material is externally exposed to SWCP. With the development of HPHT fields, exposure to high-temperature wellbore fluids internally and SWCP externally becomes inevitable, and the industry needs to look for alloys that can withstand these complex situations.