Sulfide Stress Cracking Susceptibility Research Articles

Microstructural Characterizations and Sulfide Stress Cracking Susceptibility of a High-Strength Oil Country Tubular Goods-Purpose Steel Under Different Quenching Conditions

Microstructural Characterizations and Sulfide Stress Cracking Susceptibility of a High-Strength Oil Country Tubular Goods-Purpose Steel Under Different Quenching Conditions

Effect of Cooling Rate on Sulfide Stress Cracking Resistance of a Q345 Pressure Vessel Steel Subject to Hydrogen Sulfide

As an important equipment for the separation, store, and transport of the oil and natural gas in energy industry, the pressure vessels are subjected to harsh service environments of sulfide stress cracking (SSC). In this work, the effect of the cooling rate on the SSC susceptibility of a Q345 pressure vessel steel is studied. A pronounced distinction in microstructure is presented as the cooling rate is increased from ≈1 to ≈15 °C s−1. At ≈1 °C s−1, the microstructure is consisted of polygonal‐like ferrite and distinct banded pearlite. At ≈5 °C s−1, the microstructure is consisted of polygonal‐like ferrite and faintly banded pseudo‐pearlite. At ≈15 °C s−1, the microstructure is acicular ferrite with a complete elimination of banded structure. The cooling rate decides the level of the banded structure. As the cooling rate increases, the banded structure becomes relatively slight and even disappears. Strength in sort ascending is ≈1, ≈ 5, and ≈15 °C s−1. The SSC failure happens at ≈1 and ≈5 °C s−1, while does not happen at ≈15 °C s−1. The strength is not the only dominant factor responsible for the SSC failure. The SSC is preferentially generated at the banded structure. The elimination of the banded structure is necessary to improve the SSC resistance of the Q345 pressure vessel steel.

Evaluation of post weld heat treatments and susceptibility to sulfide stress corrosion cracking of simulated HAZ in forged supermartensitic stainless steel UNS S41427

Supermartensitic stainless steels (SSMSs) with 12–13%Cr, 5%Ni, 2%Mo and microadditions were developed to casings, tubullars and mandrels used in the oil and gas off-shore production. These materials have great resistance to aqueous medium containing large amounts of CO2 and can withstand high temperatures and large amounts of chloride as well. However, SMSSs have a limited resistance to H2S containing solutions, and may fail due to sulfide stress cracking (SSC). This limit is even lower for forged and welded components that used in mandrels. Recent studies have been developed to find an operational envelope for safe use of SMSSs in sour production systems. The present study shows the results of slow strain rate testing (SSRT) of a forged V-alloyed SMSS submited to thermal simulation in Gleeble machine to produce a coarse grain heat affected zone (HAZ). The microstructure of the HAZ is characterized by fresh martensite, intergranular delta ferrite and fine precipitates which increase the hardness to a level above the maximum limit for sulfide stress corrosion cracking. The effects of two post weld heat treatments (PWHT) on the mechanical properties and susceptibility SSC were evaluated. Single and double tempering treatments provoked the decrease of hardness and the increase of ductility parameters. However, specimens representative of the HAZ, base metal, and HAZ with single and double tempering presented high SSC susceptibility parameters in SSRT in saline solution (200,000 ppm NaCl) with 1.0 psia of H2S partial pressure, and pH 4.5.

Effects of Ce and La on microstructure and sulfide stress cracking susceptibility of API-5CT-C110 casing steel

This study investigated the effects of Ce and La addition on microstructure and sulfide stress cracking (SSC) behavior of API-5CT-C110 casing steel. The role of rare earth (RE) elements on the SSC resistance was assessed via uniaxial tensile testing and double cantilever beam testing (NACE TM0177 A and D methods). The experimental results show that the appropriate addition of RE is beneficial to the improvement of SSC resistance without compromising strength. RE addition is found to refine prior austenite grains and carbides, and modify the coarse inclusions into spherical RE oxysulfides. The electron backscattered diffraction analysis indicates that the steel with RE has lower high angle grain boundary and kernel average misorientation, which could effectively hinder crack propagation and thus reduce the SSC susceptibility. Furthermore, the proportion of deformed grains is reduced significantly due to RE addition, and substructure grains with low storage energy are increased, which is also a vital factor enhancing the SSC resistance.

The Effects of NaCl on Hydrogen Permeation and Sulfide Stress Cracking Resistance of C110 High-strength Steel

Sulfide stress cracking (SSC) limits the application of high-strength low-alloy carbon steel C110 in the oil and gas industries. Chloride ions (Cl−) play an indispensable role in SSC. This study aims to evaluate the effects of NaCl on hydrogen permeation and SSC susceptibility by electrochemical techniques including hydrogen permeation test and electrochemical impedance spectroscopy (EIS), and the novel notched tensile slow strain rate test on carbon steel C110 under wet-H2S environments. The results show that the higher concentration of Cl− reduces hydrogen absorption and enhances SSC susceptibility. However, it is widely accepted that the reduction in hydrogen absorption results in an increase in SSC resistance. To figure out the role of Cl− in the SSC mechanism, the morphology of the side and the cross-sectional surface were observed. It was found that a higher pit density in a condition with a higher Cl− concentration leads to increased SSC susceptibility as pits act as crack initiation sites. The SSC mechanism transfers from hydrogen embrittlement to pit-induced cracking when the Cl− concentration in the solution increases.

Effect of Surface Hardness and Hydrogen Sulfide Partial Pressure on Sulfide Stress Cracking Behavior in Low Alloy Linepipe Steel

TMCP (thermo-mechanical controlled process) linepipes have long been used in severe sour environments, but recently sulfide stress cracking (SSC) caused by local hard zones has become a concern. In order to clarify the hardness threshold that leads to SSC, four-point bend (4PB) SSC tests as specified in NACE TM0316 were conducted under several H2S partial pressure conditions. At H2S partial pressures of 1 bar and higher, the surface hardness threshold (at 0.25 mm from the surface) observed in 4PB SSC specimens without SSC cracking was approximately correlated to a maximum acceptable hardness level of 250 HV0.1. A stable low surface hardness of 250 or less HV0.1 was achieved by suppressing hard lath bainite (LB) and obtaining a soft granular bainite (GB) microstructure, resulting in a superior SSC-resistant property. It was found that a SSC crack propagated when the surface hardness increased due to an increasing volume fraction of the LB microstructure. Under a 16 bar H2S partial pressure condition, the crack growth rate increased in the sour environment, and hydrogen embrittlement by H2S was promoted. However, in the 4PB SSC test at 16 bar, the stress concentration and the transition to a crack were suppressed because the shape of localized corrosion was semicircular due to low localized corrosivity. This can be the reason why the SSC susceptibility was similar to 1 bar condition, especially in the 4PB SSC test using the samples with lower surface hardness level of 250 or less HV0.1.

The influence of H2S on hydrogen absorption and sulfide stress cracking resistance of high strength low alloy carbon steel C110

The application of high strength low alloy carbon steel C110 in wet-H2S environment is limited by sulfide stress cracking (SSC). The objective of this research is to evaluate the effect of the environmental H2S content on the susceptibility to SSC. Since SSC is hydrogen induced fracture, the study focusses on: (1) evaluating the effect of H2S concentration on hydrogen absorption, (2) assessing SSC susceptibility by a novel slow strain rate tensile testing (n-NTSSRT) method under both sour and non-sour environments, (3) the correlation between absorbed hydrogen concentration and SSC susceptibility. The results show that with increasing H2S concentration, sub-surface hydrogen concentration C0 increases exponentially, while critical stress intensity factor KISSC decreases. The application of n-NTSSRT methodology criteria is determined to be 1 mol% H2S, which corresponding to a C0 value of 6.66 × 10−6 mol/cm3. When H2S concentration is higher than 1 mol%, the KISSC values should be calculated by assuming the fracture is linear elastic fracture. Otherwise, the elastoplastic fracture solution J-integral should be considered.

Effects of CE and La on Microstructure and Sulfide Stress Cracking Susceptibility of Api-5ct-C110 Casing Steel

Effects of CE and La on Microstructure and Sulfide Stress Cracking Susceptibility of Api-5ct-C110 Casing Steel

Influence of H2S on the general corrosion and sulfide stress cracking of pipelines steels for supercritical CO2 transportation

This article presents a literature review and corrosion testing outputs to fill the knowledge gaps about the effect of H2S on corrosion and sulfide stress cracking (SSC) of pipeline steels in supercritical CO2 (s-CO2) environments. In H2O-saturated s-CO2, H2S facilitates the formation of a protective FeS layer with a threshold content less than 50 ppm. Increasing temperature or adding O2 destroys the integrity of FeS layer and remarkably enhances corrosion. The corrosion is likely to be controlled by gas chemical reactions instead of electrochemical reactions. The SSC susceptibility of strained pipeline steels is lower than expected.

Effects of Environmental Factors on Hydrogen Absorption and Sulfide Stress Cracking Susceptibility of Low Alloy Steel

In this study, the sulfide stress cracking (SSC) susceptibility of high-strength low alloy steels was investigated quantitatively. Double cantilever beam tests were used to evaluate the effects of environmental factors, namely pH, H2S partial pressure, and temperature, on the SSC. The corrosion rates and the absorbed diffusible hydrogen concentration were also determined. The critical stress intensity factor (KISSC), which signifies the SSC susceptibility, was mainly affected by the H2S partial pressure and the temperature. Even though the solution pH apparently affected the corrosion rate, the influence of pH on KISSC was small. Considering these results, the environmental contribution in each elementary process of the SSC phenomenon was discussed. The estimated local hydrogen concentration at the crack tip area, which clearly depends on H2S partial pressure and temperature, showed good correlation to the KISSC obtained in various sour conditions.

Influence of cooling path after rolling on sulfide stress cracking behavior for casing steel

Interrupted accelerated cooling (IAC) in comparison with normal air cooling after rolling is introduced into the production of the API-5CT-C110 casing steel. Sulfide stress cracking (SSC) resistance is improved by IAC processing without compromising strength. Multiple characterizations combined with hydrogen permeation tests are performed to reveal the mechanism of SSC behavior with respect to hydrogen interactions with metallurgical defects (grain boundaries, dislocations and precipitates). The results indicate a low dislocation density and increased amount of irreversible traps are responsible for the superior SSC resistance of the IAC specimen. A model of local hydrogen concentration is proposed to illustrate SSC susceptibility.

Effect of tempering temperature at high temperature zone on sulfide stress cracking behavior for casing steel

Three tempering temperatures at high temperature zone (690 °C, 700 °C and 710 °C) are selected into the quenching-and-tempering processes and performed on the rolled Cr-Mo steel to develop API-5CT-C110 casing steels. Effect of tempering temperature on sulfide stress cracking (SSC) behavior is quantitatively evaluated and further explored by characterizing the microstructure and crystallography. The results show that the strength of steel decreases with tempering temperature, but the SSC susceptibility is reversely varied. EBSD analysis indicates that the steel tempered at lower temperature (690 °C) generates more grains with high Taylor factors, which are difficult to yield, leading to the increasing of dislocation density and more susceptible to SSC.

Influence of PWHT on the sulfide stress cracking susceptibility of 9%Ni low carbon steel

The 9Ni steel low carbon steel is usually applied to pipes, pressure vessels and forged parts working at cryogenic temperatures, due to its high toughness at −196 °C and mechanical strength. Recently, this material was selected to facilities for storage and re-injection of CO2 gas in modern off shore oil and gas platforms. In this new application the steel may be subjected to high pressures in as environment with condensed water, CO2 and traces of H2S. The effect of such a harsh environment on the simulated heat affected zone (HAZ) was investigated by slow strain rate tensile (SSRT) tests. Two post weld heat treatments (PWHT) were reproduced, single tempering (ST) at 575 °C and double tempering (DT) at 670 °C (2 h) and 600 °C (2 h). Specimens without PWHT were more susceptible to sulfide stress cracking (SSC), while the single tempering at 575 °C decreased both the hardness and the SSC susceptibility. Double tempering also increased the resistance to SSC, but was not more effective than the single tempering. As general conclusion, PWHT is strongly recommended to 9Ni low carbon steels subjected to H2S containing environments.

A Study on Sulfide Stress Cracking Susceptibility of GMA Girth Welds in X80 Grade Pipes

The present work evaluates the SSC susceptibility of linepipe steel weld metals produced with various microstructures consisting of different ratios of intragranular (acicular) ferrite and grain boundary ferrite. It is shown that weld metal with high fractions of intragranular ferrite and low grain boundary ferrite passed SSC tests even though their hardness exceeded 250 HV, the widely accepted guideline to prevent SSC fracture initiation. Using a novel combination of hydrogen microprinting combined with SEM and TEM electron microscopy analysis techniques, the intragranular ferrite grain boundaries are shown to provide key hydrogen trapping sites which consist of fine grains and finely dispersed nano-scale carbide precipitates. The presence of a high fraction of trapping sites is suggested to account for the good SSC resistance coupled with high hardness, while increased grain boundary ferrite led to rejection during SSC testing due to inferior fracture toughness associated with coarser grains.

Test Conditions for Pipeline Materials Selection with High Pressure Sour Gas

Acid gases, such as CO2, H2S, and/or sulfur in oil industry’s production fluids, can be responsible for both general and localized corrosion, acting with different mechanisms, which depend on chemical and physical properties of the produced fluids. Materials selection for handling such fluids is performed by combining experience with suggestions from standards and regulations. A good deal of knowledge is available to predict corrosion rates for CO2-containing hydrocarbons, but the effect of high H2S pressure is less understood, mainly due to the difficulty of performing laboratory tests in such challenging conditions. For instance, the so-called NACE solution to assess SSC (Sulfide Stress Cracking) susceptibility of steels is a water-based solution simulating production fluids in equilibrium with one bar bubbling H2S gas. This solution does not represent environments where high gas pressure is present. Moreover, it does not take into account the corrosive properties of sulfur and its compounds that may deposit in such conditions. Besides, properties of high pressure gases are intermediate between those of a gas and those of a liquid: high pressure gases have superior wetting properties and better penetration in small pores, with respect to liquids. These features could enhance and accelerate damage, and nowadays such conditions are likely to be present in many production fields. This paper is aimed to point out a few challenges in dealing with high pressure gases and to suggest that, for materials selection in sour service, a better correspondence of test conditions with the actual field conditions shall be pursued.

A systematical analysis with respect to multiple hydrogen traps influencing sulfide stress cracking behavior of API-5CT-C110 casing steel

The irreversible hydrogen traps including Cr-rich M7C3, Mo2C and MC carbides are characterized by scanning transmission electron microscope (STEM) after the quenching-and-tempering process performed on the API-5CT-C110 casing steel. Combined with our previously published work [Mater. Sci. Eng. A 688 (2017) 378–387], a systematic analysis with respect to the hydrogen interactions with reversible traps (grain boundaries and dislocations) and precipitates influencing sulfide stress cracking (SSC) behavior is presented. Grain boundaries provide channels for hydrogen diffusion. Dislocations trap hydrogen and act as hydrogen “transporters” during moving. Precipitates are introducing traps to retain hydrogen and restrict dislocation movement, then improve resistance to SSC. However, the mobile dislocations can transport the trapped hydrogen from precipitates into potential crack sites in the presence of external stress, leading to the initiation of SSC cracks. Therefore, SSC susceptibility significantly depends on the density of dislocations. The steel with lower dislocation density exhibits superior SSC behavior mainly attributed to its finite hydrogen “transporters”.

Effect of Buffer System on the Sulfide Stress Cracking Susceptibility of Low-Alloy Steel

The effects of a buffer system in test solution and CO2 partial pressure on sulfide stress cracking (SSC) susceptibility of low-alloy steel were investigated under pH 4.0 at 0.03 MPa H2S partial pressure. A double cantilever beam test was used to quantitatively evaluate SSC susceptibility. The corrosion rates and absorbed diffusible hydrogen concentration were also evaluated. Acetic acid/sodium acetate (acetate buffered solution) and carbonic acid/bicarbonate (bicarbonate buffered solution) buffered solutions were used as buffer systems in this study. From the results, in atmospheric pressure tests, KISSC values in bicarbonate buffered solutions were equivalent to or lower than those in acetate buffered solutions. In high CO2 partial pressure conditions, KISSC values in bicarbonate buffered solutions were much higher than those in acetate buffered solutions. At a high CO2 partial pressure and H2S partial pressure (pCO2/pH2S) ratio condition, hydrogen entry is considered to be greatly prevented by corrosion products probably containing amorphous iron carbonate. Presence of the corrosion product with high protectiveness produced in the high pCO2/pH2S ratio condition suggests the possibility that conventional test conditions using acetate buffered solutions are conservative or are equivalent test conditions for actual field conditions.

Effect of Testing Temperature on Sulfide Stress Cracking of Low Alloy Steel

In this study, effects of environmental temperature on susceptibility to sulfide stress cracking (SSC)—a type of hydrogen embrittlement (HE) occurring in sour environments—of low alloy steels were investigated from the perspective of hydrogen entry, absorption, and accumulation. SSC susceptibility was evaluated using a double cantilever beam (DCB) test and a four-point bend (4PB) test in sour environments at several testing temperatures. 4PB test specimens included notched and un-notched specimens to investigate influences of stress concentration and local stress. In the case of evaluation methods using specimens with high-stress concentration area, a decrease in testing temperature from room temperature to 4°C significantly increased SSC susceptibility. Hydrogen entry and absorption behaviors were also evaluated at several testing temperatures using a hydrogen permeation test. The hydrogen concentration at the plastic deformed area increased remarkably with decreasing testing temperature. It is considered that the influence of testing temperature is due to hydrogen concentration at the stress concentration area with plastic deformation. In a low temperature condition, the degree of hydrogen accumulation at the crack tip areas of a DCB specimen or crack initiation site of a 4PB specimen could be higher than that in a higher temperature condition. When steels are applied to low temperature conditions with H2S, a prior material evaluation reproducing both environmental temperature and actual stress condition is needed.

Influence of Weld Preparation Procedure and Heat Tinting on Sulfide Stress Corrosion Cracking of Duplex Stainless Steel

Corrosion resistant alloys, such as duplex stainless steel (DSS), are increasingly the material of choice for oilfield applications as a result of the trend toward more extreme temperature, higher pressure, and elevated levels of hydrogen sulfide. However, the susceptibility of such materials to localized corrosion and sulfide stress cracking (SSC) is a major consideration, particularly in the vicinity of welds. Here we investigate the effect of surface preparation and oxygen content in the backing gas during welding on the pitting and SSC susceptibility of 22Cr DSS. Four-point bend testing of welded specimens under conditions close to the pass/fail boundary revealed a greater tendency for pitting as a function of oxygen content in the backing gas. Pitting was concentrated in the heat-tinted region, whereas cracking was mainly observed in the adjacent coarse ground parent material, with surface defects from the grinding process acting as primary crack initiation sites. The results demonstrate that control...

Identification and Prediction of Wells Susceptible to Sulfide Stress Cracking

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 160489, ’Identification of SSC (Sulfide-Stress-Cracking) -Susceptible Wells and Risk Prediction,’ by Tapan Chakrabarty and Richard J. Smith, Imperial Oil Resources, prepared for the 2012 SPE Heavy Oil Conference Canada, Calgary, 12-14 June. The paper has not been peer reviewed. Hydrogen sulfide (H2S) generated by aquathermolysis—a high-temperature reaction of condensed steam (water) with sulfur-bearing bitumen in the reservoir rock—may increase the risk of sulfide stress cracking (SSC) in cyclic-steam-stimulation (CSS) wells. Identifying the SSC-susceptible wells is important in terms of reducing SSC risk by allocating resources to and implementing proactive intervention measures at the SSC-susceptible wells. A comprehensive research program, with a dedicated instrumented CSS well as the centerpiece, has been undertaken with the objectives of characterizing H2S evolution in the wellbore and developing a tool for identifying the SSC-susceptible wells. Introduction Imperial Oil is using CSS commercially to recover bitumen from the Clearwater formation at the Cold Lake field in Alberta, Canada. In this process, the reservoir is stimulated by injecting high-pressure/high-temperature steam to reduce the bitumen viscosity and produce the thinned bitumen through the same well in a cyclical manner. In a given well, steam injection is through the casing, liquid (bitumen and condensed steam) production is through the tubing, and gas production is mainly through the casing annulus. It is the casing that is susceptible to SSC, as shown in a small casing section retrieved from a Cold Lake CSS well (Fig. 1). SSC in a CSS well is induced by H2S that is generated by the reaction, termed aquathermolysis, between condensed steam and sulfur-bearing bitumen. SSC increases with an increase in H2S partial pressure (pH2S) and with a decrease in well temperature. The inverse temperature effect is attributed to the diffusion of hydrogen atoms—a product of the reaction between H2S and iron—through the casing metal matrix. At a lower temperature, the hydro-gen diffusion is slower and the hydrogen accumulation inside the casing wall is higher, leading to a higher stress build-up and an increased SSC susceptibility. To reduce the risk of SSC in CSS wells at Cold Lake, Imperial Oil has implemented an extensive casing-integrity-assurance program that includes Measuring the H2S during production in all the wells as they cool down to lower than 70°C Shutting in an SSC-susceptible well Purging the casing annulus of a shut-in well with nitrogen to lower the H2S level in the wellbore