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A gas injection well completed mid-2019, started leaking after only approximately four months in service. The well was initially back flowed for a period of approximately two months before it was put on gas injection service. After another two months on gas injection, a tubing-to-annulus leakage was registered and the well had to be shut in to re-establish all barriers.
After only months in service, a tubing-to-annulus leakage was detected in a subsea gas injection well located on the Norwegian continental shelf. This well had been completed with UNS<xref rid="fn1-c2023-19144" ref-type="fn">(1)</xref> S41426 martensitic stainless steel tubing. Upon retrieval of the tubing string, the source of the leakage proved to be a full tubing wall thickness penetrating crack which had initiated in and was confined to, tubing make-up tong die marks on the outside surface. Further, the initial investigation showed that the temperature/pressure gauge instrument line encapsulation material had been severely degraded, revealing the galvanized steel bumper wire. This instrument line was clamped onto the outside of the tubing.
This paper describes the failure analysis and laboratory corrosion tests performed trying to replicate the field failure. The investigations proved that the tong die marks had severely cold-worked the external surface of the tubing and, thus, locally altered the metallurgy and hardness. Further, as the galvanized steel wire was exposed, an effective galvanic cell between the zinc coating and the martensitic stainless steel tubing was established, allowing hydrogen-assisted cracking of the tubing.
Traditionally, sour severity of high-pressure, high temperature (HPHT) oil and gas production wells were assessed by H2S partial pressure (PH2S): The mole fraction of H2S in the gas (yH2S) multiplied by the total pressure (PT). While PH2S is appropriate for characterizing the sour severity of wellbores operating at low total pressures (e.g., PT < 35 MPa) and/or for highly sour systems (e.g., yH2S > 1 mol%), PH2S usually over-predicts the actual sour severity of HPHT systems, leading to sub-optimal material selection options.
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The goal of the Paris Agreement is to limit global warming to below 2°C, preferably 1.5°C, compared to pre-industrial levels.1 While the world is slowly transitioning to more sustainable energy sources to reach this target, one of the ways to reduce the CO2 in the atmosphere is to capture it and store it in depleted gas fields. According to the IOGP1, the total number of CCS projects in Europe is 65 in 2022.2 The aim of these projects is to store around 60 MtCO₂/yr by 2030.
Martensitic Stainless Steel (SMSS) is widely used for downhole production tubing and liners in the Oil & Gas industry. Optimization of the tubular material chemistry, cleanliness and manufacturing route has delivered useful performance in H2S-containing environments (specifically SSC and stress corrosion cracking [SCC])3 resistance4,5,6. Some tubular accessories and most completion equipment require sizes not readily delivered by tubular product form. In these instances, bar stock material is a pragmatic choice.