Machine Learning for Sulfide Stress Cracking Prediction

Sulfide stress cracking (SSC) and hydrogen embrittlement (HE) prevent the use of high strength carbon steel alloys in the recovery of fossil fuels in H2S containing ‘sour’ environments commonly experienced in deep well fossil fuel recovery efforts. Couplings are a common weak point in casing strings as high magnitude mean tensile stresses are generated by connection interferences created during power make-up of downhole tubular components. When subject to service loads both mean and alternating stresses are increased further providing the high tensile stresses necessary for SSC initiation. Since high strength carbon steel alloys are not typically suited for sour service environments, the current solution is to use or develop much more expensive alloys with increased corrosion-cracking resistance, or limit their use to significantly weaker sour environments, or higher operating temperatures. Failure due to fatigue is another major problem in downhole tubular components. Likelihood of fatigue failure is further exacerbated in corrosive environments (such as H2S and NaCl), commonly encountered in service. The cost for detecting the impending failure before final separation is dramatic at a factor 10X. A cost effective method of mitigating failure from SSC and corrosion fatigue would greatly reduce operational costs and extend component life. Introduction of stable, high magnitude compressive residual stresses into less expensive carbon steel alloys alleviates the tensile stresses, and mitigates SSC, while also improving fatigue performance. Low plasticity burnishing (LPB) is an advanced surface enhancement process providing a means of introducing compressive residual stresses into metallic components for enhanced fatigue, damage tolerance, and SCC performance. The effects of LPB on high cycle fatigue (HCF) and SSC were evaluated on quench and tempered API P110 grade steel. LPB processed specimens had an increase in fatigue life greater than an order of magnitude over untreated specimens. LPB was successful in completely mitigating SSC in all test specimens at tensile stresses up to 90% specified minimum yield strength (SMYS). The initial results indicate that LPB processing of P110 steel provides an economical means of SSC mitigation and fatigue strength improvement in sour environments.

Sulfide stress corrosion cracking (SSCC) in crude oil field environment containing hydrogen sulfide (H2S) has been recognized as a material degradation and damage mechanism. Laboratory data and field experience have demonstrated that extremely low concentration of H2S may be sufficient to lead to SSCC failure of susceptible materials. In some cases, sulfides may act synergistically with chlorides to produce SSCC failures. SSCC mechanism is a form of hydrogen embrittlement that occurs in high strength steels and in localized hard zones in weld of susceptible materials. In the heat-affected zones adjacent to the weld, there are often very narrow hard zones combined with regions of high residual stress that may become embrittled to such an extent by dissolved atomic hydrogen. On the basis of this understanding, SSCC tests were conducted with smooth specimens of the multi-pass welded ASTM A106 Gr B steel pipe used in the oil industries. And SSCC resistance according to the welding processes was evaluated. From the results, the weld by GTAW+FCAW showed the largest resistance against SSCC.

Oil & Gas treatment and petroleum refining involve aggressive environments containing aqueous hydrogen sulfide (H2S). Carbon-manganese steels used in these industrial sectors may be susceptible to various kinds of cracking phenomena namely Hydrogen Induced Cracking (HIC), Sulfide Stress Cracking (SSC) and Stress Oriented Hydrogen Induced Cracking (SOHIC). The HIC risk can be avoided by a strict control of the chemical composition of the steel (sulfur, phosphorus, oxygen) associated to a specially-adapted production route. SSC can be limited by a careful control of the hardness level of both the parent material and the heat affected zone as well as a low impurity level and appropriate PWHT. SOHIC is a critical problem in the Oil & Gas industry since it has been involved in many in-service failures. This phenomenon can be described as a combination of both SSC and HIC. Previous studies have shown that the measures taken to counter HIC and SSC are not sufficient to protect carbon-manganese steels against SOHIC. The SOHIC susceptibility of SA516 Grade 70 carbon-manganese steel was studied according to NACE MR0175/ISO15156-2 standard by means of the four-point-bending and constant load test methods. Both base metal and welded specimens were investigated. The results show that the microstructure also plays an important role and that only quenched and tempered steels with appropriate PWHT can offer SOHIC resistance when combined with an optimized chemical composition and steel fabrication route.

Sulfide stress corrosion cracking (SSCC) in crude oil field environment including hydrogen sulfide ( H 2 S ) has been recognized as a materials failure mechanism. Welding residual stress generation and metallurgical change by fusion welding process increase the cracking driving force and reduce the resistance of brittle fracture as well as environmental fracture. On the base of this understanding, firstly, we analyzed welding residual stresses of welded ASTM A 106 Gr B steel pipe using in the petrochemical plant. And next, SSCC tests were conducted to assess SSCC resistance of the weld with smooth specimens. From the result, influence of temperature on corrosion rate was sensitive in order of HAZ, base metal and weld metal. Therefore, the most sensitive region in the weld is HAZ, and its corrosion rate increases with the temperature of corrosion environment increase. And failure positions of the most cases among failed specimens were at HAZ of the weld. Low limit (σ SSCC ) of A 106 Gr B steel pipe was assessed as 0.6 σ y (7271.6N)

This paper investigates the characteristics of acoustic emission (AE) signals generated from hydrogen induced cracking (HIC) and sulfide stress corrosion cracking (SSCC) for a medium strength steel in hydrogen sulfide (H2S) solution. The experiments performed in this study include the constant load test (CLT) and the constant extension rate test (CERT). From the results of the CLT, the AE count rate caused by SSCC was found to be much higher than that resulted from the HIC; and the increase of the AE count rate was observed to be approximately proportional to the increase of the applied loading. In addition, the AE frequency distribution diagrams obtained from these tests were found to contain potential information for distinguishing the mechanisms of HIC and SSCC. From the results of CERT, the AE signals detected from the specimens tested in the H2S solution were compared with those obtained from the specimens tested in the air. In addition, the AE count rate detected from the tensile specimens ...

Engineering diagrams and sulphide stress corrosion cracking of duplex stainless steels in deep sour well environment

Modern duplex stainless steels have been in use since the early 1970s and cast versions of the wrought alloys were soon in demand for pumps and valves. Since that time a range of cast duplex stainless steels have been developed with a wide range of compositions, but all with approximately 50/50 austenite/ferrite phase balance and deliberate additions of nitrogen. This paper presents some comparative corrosion data on a range of cast duplex stainless steels, mainly in seawater. The differences in performance related to composition and microstructure are discussed. Corrosion data in lower chloride brines are also presented to show the limits of use of some lower alloyed duplex materials. In addition to oxidizing chloride solutions, some data are presented on cast duplex stainless steels in reducing brines containing H2S, where the main corrosion problem is sulfide stress corrosion cracking. Finally, the importance of using a suitable technical specification, over and above ASTM, combined with selecting a suitably skilled foundry in order to obtain satisfactory castings is discussed.

Duplex stainless steels (DSSs) have been widely used as the structural components for chemical industries, oil and gas production and offshore applications due to its outstanding corrosion resistance in chloride-containing environments. However, depletion of chromium and molybdenum is a well-known problem in DSSs, especially in welded assemblies, hot-worked and improperly heat-treated parts heated at temperatures ranging from 500 to 900°C. As the sigma phase forms, it depletes the neighboring regions of Cr and Mo, thereby lowering the Cr and Mo contents of the surface oxides over these regions. Then the DSSs become susceptible to corrosion attack. Laser surface melting (LSM) is a possible route to restore the corrosion resistance of DSSs by melting the surface with a laser beam followed by rapid solidification for homogenizing chemical compositions. Different laser parameters will cause different phase distributions in the DSSs, and hence various corrosion properties may be resulted. In present study, microstructure and corrosion behavior of aged DSS 7MoPlus (UNS S32950) were investigated in 3.5% NaCl solution at 25 °C before and after LSM. By LSM, the corrosion resistance of aged 7MoPlus was found to be significantly enhanced as reflected by the increase in the corrosion and pitting potentials and decrease in corrosion and passive current densities. The improvement in corrosion resistance of the aged 7MoPlus after LSM is mainly attributed to re-dissolution and removal of the σ phase.Duplex stainless steels (DSSs) have been widely used as the structural components for chemical industries, oil and gas production and offshore applications due to its outstanding corrosion resistance in chloride-containing environments. However, depletion of chromium and molybdenum is a well-known problem in DSSs, especially in welded assemblies, hot-worked and improperly heat-treated parts heated at temperatures ranging from 500 to 900°C. As the sigma phase forms, it depletes the neighboring regions of Cr and Mo, thereby lowering the Cr and Mo contents of the surface oxides over these regions. Then the DSSs become susceptible to corrosion attack. Laser surface melting (LSM) is a possible route to restore the corrosion resistance of DSSs by melting the surface with a laser beam followed by rapid solidification for homogenizing chemical compositions. Different laser parameters will cause different phase distributions in the DSSs, and hence various corrosion properties may be resulted. In present study, mic...

This paper provides technical insights based on metallurgical principles that directly influence the properties and applications of key stainless steel families used in aggressive corrosion environments—particularly within the oil and gas industry. Special attention is given to duplex and superduplex stainless steels, which stand out for their exceptional combination of high corrosion resistance and superior mechanical strength. These attributes have positioned them as a leading material choice for manufacturing various components in the global oil and gas sector. One of their major advantages lies in the significant weight reduction achieved by allowing thinner wall thicknesses compared to conventional AISI 316L stainless steels. This, combined with their enhanced resistance to corrosion in marine environments, makes duplex and superduplex grades a highly cost-effective solution. Their adoption has expanded across multiple industrial sectors that require reliable performance in corrosive settings, with particular relevance in offshore oil and gas applications. It is important to note, however, that the presence of non-metallic phases in these steels must be carefully controlled. These phases can lead to embrittlement, thereby compromising the corrosion resistance and mechanical reliability of final components. The successful production of duplex and superduplex stainless steels demands a precisely balanced chemical composition during melting, casting, and refining. This is critical to ensure a desirable duplex microstructure while minimizing the formation of harmful non-metallic phases. Field and laboratory evaluations have demonstrated that duplex and superduplex steels consistently outperform conventional stainless grades in aggressive corrosion environments. The ability to reduce wall thickness without sacrificing strength results in lighter components and reduced material consumption. At the same time, superior corrosion resistance ensures longer service life and lower maintenance costs. These factors make duplex and superduplex grades a clear choice for applications where performance, reliability, and cost-efficiency are critical—particularly in the oil and gas industry. This paper reflects the authors’ extensive industrial experience and long-term involvement in the production of duplex and superduplex stainless steels. The observations and improvements described are based on practical insights gained across the entire manufacturing chain—from steelmaking, casting, and refining to rolling, forging, heat treatment, and final machining. By optimizing these processes, the author has contributed to the development of high-performance steels that deliver both high strength and superior corrosion resistance. These materials offer a reliable and sustainable solution for the most demanding environments faced by offshore oil and gas operations

Demand for CRAs (Corrosion Resistant Alloys) clad steel is getting increased for pipeline application of oil and gas industry because of economic advantage over solid CRAs. CRAs clad steel consists of a CRAs layer for corrosion resistance and a carbon steel for mechanical properties. Nickel based Alloy625 is known to be suitable for harsh environmental condition such as high temperature and high pressure H2S (hydrogen sulfide) condition. In this paper, the corrosion resistance of Alloy625/X65 clad steel plate for pipe produced by TMCP (Thermo-Mechanical Control Process) was investigated. TTP (Time - Temperature - Precipitation) and TTS (Time - Temperature - Sensitization) diagram of Alloy625 indicated precipitation nose, e.g. M6C and M23C6 which would cause deterioration of corrosion resistance. TMCP enable Alloy625 to avoid long time exposure to the precipitation nose. In Huey test, the corrosion rate in TMCP was almost the same as that of solution treated Alloy625 and smaller than that in Q-T (Quench and Temper). In ferric chloride pitting test, no pitting was observed in Alloy625 layer of TMCP type clad steel. In addition, the corrosion test simulating service environment using autoclave apparatus was conducted under the condition of 0.39MPa H2S - 0.53MPa CO2 - Cl− solution at 200°C. Alloy625 clad steel produced by TMCP showed neither SSC (Sulfide stress corrosion cracking) nor crevice corrosion. All the mechanical properties of base carbon steel satisfied API 5L grade X65 specification by optimizing TMCP conditions. It is notable that 85% SATT of DWTT was below −10 °C. Thus, Alloy625/X65 clad steel plate for pipe produced by TMCP with both superior corrosion resistance and low temperature toughness has been developed.

Increased tolerance levels for impurities in CO2 compositions for pipeline transport will give considerable value to CCS projects. Increasing the allowable H2S limits may impose a risk for sulfide stress cracking (SSC) and corrosion. ISO 15156 defines the testing requirements for SSC for oil and gas production, however, CCS applications are not considered in the standard and need to be fully understood in order to provide the right requirements. This work presents preliminary results from an ongoing project with the objective to establish the allowable H2S limit in pipelines transporting CO2 and to establish whether it is possible to represent dense phase SSC behavior by testing in ambient conditions. Autoclave four-point bending test results and simulations are presented and further used to discuss the implications of correlating the dense phase conditions to ambient conditions.

API 6A "Specification for Wellheads and Christmas Tree Equipment" requires compliance with NACE MR0175 for equipment supplied for use in sour (Hydrogen Sulfide-H2S) service. Major changes to the NACE standard in the 2003 revision created the need for substantial changes to the API specification in terms of how both users and manufacturers specify equipment. New environmental restrictions have been imposed by NACE on many commonly used materials. Consequently, new material and temperature classifications have been created within the API document in order to permit compliance with these restrictions. This paper reviews the background to the changes in the NACE standard, their effect on API 6A and some precautions that users of this equipment should consider. Additionally, upcoming changes to NACE MR0175 2003 with the 2004 publication of NACE MR0175/ISO 15156 will be discussed. NACE MR0175 2003 Revision NACE MR0175 prescribes the requirements for production equipment to be used in sour (hydrogen sulfide bearing) hydrocarbon service. Prior to 2003, it only addressed sulfide stress cracking (SCC) as a possible failure mode. Recognizing this, NACE formed the CRA (Corrosion Resistant Alloy) Rewrite Committee to address some of the perceived shortcomings of the earlier revisions. These included:Catastrophic failure mechanisms other than (SSC) were not included in the scope of the document, but other mechanisms such as chloride stress corrosion cracking (SCC) may be the limiting factor in a sour environment.Many environmental parameters important to a material's susceptibility to environmental cracking (SCC or SCC) were not adequately addressed. Depending on the specific alloy, these could include temperature, partial pressure of H2S, chloride concentration, presence of free sulfur, temperature, and other factors.In the last ten years or so, there has been a growing trend to include environmental restrictions that define the safe operating limits for new alloy additions to MR0175. Many of the materials included in earlier editions have a limit on maximum hardness and possibly heat treat condition, but no environmental restrictions. This gave the wrong impression that these materials were safe to use under all environmental conditions.The balloting and approval process to add new alloys was unrealistically long - in some cases years. The resultant work of the CRA Rewrite Committee formed the basis for the changes found in NACE MR0175- 2003: Standard Material Requirements: Metals for Sulfide Stress Cracking and Stress Corrosion Cracking Resistance in Sour Oilfield Environments". Historically there have been few revisions to MR0175 that have impacted the acceptability of previously approved materials. Typically, the revisions have added new alloys, modified test environments, etc. The 2003 revision, however, presents a new approach for selecting materials for use in sour service.

Sulfide stress cracking (SSC) behavior of three microstructures, i.e., ferritic-pearlitic microstructure, ultrafine ferrite microstructure, and acicular ferrite dominated microstructure, was investigated using the bent-beam test in aqueous hydrogen sulfide (H2S) environments. The critical stress (Sc) values of these three microstructures were determined experimentally to be 1008, 1190, and more than 1260 MPa, respectively. As a result, the acicular ferrite-dominated microstructure possessed the best SSC resistance, the ultrafine ferrite microstructure was in a second position, and the ferritic-pearlitic microstructure was relatively the worst. It was analyzed that hydrogen embrittlement (HE) was the main failure mechanism in SSC cracking for high-strength pipeline steels, and preferential hydrogen accumulation within the plastic zone of the main crack tip accounted for the exhibited embrittlement. It was remarkable that the strength values of pipeline steels were not the only factor to determine their SSC susceptibilities. Microstructure played an important role in the SSC initiation and propagation of pipeline steels. In particular, both the fine dispersed precipitations of carbonitrides and the high-density tangled dislocations in acicular ferrite, which behaved as the hydrogen traps, should be attributed to the optimal SSC resistance of pipeline steels.

Hydrogen sulphide has long been associated with causing weight-loss corrosion, blistering, and sulphide stress cracking in low-alloy steels used in oil and gas production. In recent years, new stainless and nickel alloys have been proposed for use in many oilfield applications where corrosion in production environments is particularly severe. However, these materials, in some cases, may be susceptible to corrosion and cracking in sour environments. In this review the behaviour of low-alloy steels, stainless steels, and nickel alloys in H2S-containing environments is discussed. Emphasis is placed on the various types of corrosion and cracking that can occur, their origin and mechanisms, and methods of control.

Pipelines used in the gathering and transport of natural gas, natural gas 1iquids and other petroleum products may contain significant amounts of hydrogen suffice (H2S) and carbon dioxide (C02). When associated with brine these environments can cause internal corrosion and stepwise cracking of pipe line steels. Such phenomena are of increasing importance in the design and protection of offshore gathering lines as levels of H2S increase in these areas. Stepwise cracking is observed in lower strength (less than or equal to 80 ksi yield strength) line pipe steels which are used in oilfield service. Cracking occurs internally through the accumulation of molecular hydrogen along internal surfaces such as nonmetallic inclusions or low temperature transformation structures. As hydrogen becomes trapped at internal surfaces, b1isters fond, usually along parallel planes, which begin to link up via small cracks. These cracks lower the effective wall thickness of the pipe and may eventually become through wall failures. Research over the years has shown how various metallographic variables can be controlled to increase resistance to stepwise cracking. This study examines the effects of inhibitors on the stepwise cracking characteristics of API line pipe steel. The use of inhibitors was found to be available method of controlling the onset and propagation of stepwise cracking. Introduction Pipelines used in the gathering and transport of natural gas, natural gas 1iquids and other petroleum products may contain significant amounts of hydrogensulfide (H2S) and carbon dioxide (C02). In conjunction with aqueous water, these constituents cause internal corrosion of steel pipelines. Also, pipe line material s exposed to aqueous H2S containing environments may be susceptible to failure by either sulfide stress cracking (SSC) or stepwise (blister) cracking. A study was undertaken to provide an assessment of the state-of-the-art of preventing or minimizing the deleterious effects of these phenomena in the transmission of sour (H2S containing) gas. This investigation was undertaken to provide information regarding:the manufacturing of pipe line materials,operating procedures andfield experience. Background Mechanisms of Pipeline Corrosion Damage When acid gases are present, three distinct forms of corrosion damage in pipeline may occur:Weight-loss CorrosionSulfide Stress Cracking (SSC)Stepwise (Blister) Cracking Weight-Loss Corrosion. Produced oil and gas frequently contain H2S and/or CO2 When dissolved in aqueous systems (water or brine), these gases fond acids of fairly low pH which attack and corrode materials commonly used for transmission lines. This attack may be localized, in the fond of pitting or crevice corrosion, or it may be general attack dependent upon the environmental conditions that exist.