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The manufacturing and field experience of high strength low alloy (HSLA) steel plates produced by Thermo-Mechanical Controlled Process (TMCP) are well defined in industry standards and literature. The TMCP method consists of a well-prescribed rolling pass schedule followed by accelerated cooling that leads to a fine-grain microstructure with the desired mechanical properties of the produced plates.Quite recently, this TMCP process resulted in detrimental local variations with hidden hardness variations on pipe ID, so-called Local hard Zones (LHZ).
Technical challenges and process improvements moved older generation Thermo-Mechanically Controlled Processing (TMCP) pipes from coarse microstructures and presence of non-metallic inclusions and/or mid-thickness segregation, to finer, homogenized microstructures and improved properties. Despite such an improvement, local hard zones (LHZ) have recently been experienced in the Oil & Gas industry on large diameter line pipes manufactured from TMCP plates, resulting in an in-service failure due to sulfide stress cracking (SSC).After thorough investigations, it was confirmed the root cause of the failure was ascribed to microstructure heterogeneities while manufacturing the TMCP plates. Sub-surface lower bainite was identified as crack initiation areas, leading to the failures.This paper deals with the results of a research program initiated to evaluate the SSC resistance of the actual microstructure associated to these hard zones. The first step was to analyze an industrial pipe section that experienced SSC in service. The microstructure observed was successfully reproduced in laboratory on specimen blanks using Gleeble thermo-mechanical cycles. Then, specimens were tested in different conditions of the Region 3 of the pH-PH2S severity diagram of NACE MR0175 / ISO 15156 to evaluate their cracking susceptibility. As a result, the maximum hardness limit of 22 HRC (248 HV) historically specified in standards shall not be considered as a safe limit if local hard zones are present at the surface of the material. Thus, the threshold should be decreased to 210 HV for safe use in Region 3 sour environments.
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.