• What is hydrogen embrittlement, where could it occur in our refinery, and how do we avoid it?



  • Craig Harclerode, OSIsoft, charclerode@osisoft.com

    Hydrogen embrittlement, also referred to as high temperature hydrogen attack (HTHA) or methane reaction, is a widely documented corrosion phenomenon in petroleum refining and petrochemical processes that can be best described by using intent search engines like Google and articles like: AICHE Engage, Preventing HTHA, by Lauren Grim (8/15/2016 post) or articles such as ASTM F519 and ASTM G142. In short, the Nelson Index correlates the impact of hydrogen embrittlement on various high strength material such as in the case of carbon steel alloys at high temperatures and high hydrogen partial pressures.

    An example of using advanced analytics can be found in the 2016 EMEA OSIsoft Users Conference in a presentation by MOL’s Tibor Komróczki (Delivering Business Value from Digital Transformation) which describes how MOL developed HTHA advanced corrosion analytics by using PI Asset Framework (PI AF) to configure a HTHA template that was then rapidly deployed to over 50 nodes across four refineries.

    Many companies like MOL are using advanced analytics and methods to monitor for HTHA with associated operational alerts in addition to gathering intelligence to aid in the determination of preventive measures such as the need to inspect or replace certain nodes with different alloys or change operations.

    An additional reference can be found in Leveraging the PI System in the Processing of Opportunity Crudes by MOL’s Gábor Mucsina in the OSIsoft UC2017. This presentation discusses the use of integrity operating windows (IOW) in areas including HTHA to aid in the safe processing of opportunity crudes.


  • Henk Helle, Petrogenium, henk.helle@petrogenium.com

    Hydrogen embrittlement (HE) is the obstructing effect of dissolved atomic hydrogen on the plastic straining of metals. On elastic straining there is no such effect. Since refinery equipment is nominally designed to be stressed elastically, there is generally another factor at play: stress raisers, such as cracks or sharp notches, which induce local plastic zones.

    This redefines the problem: HE is the cause, but hydrogen stress cracking (HSC), or the propagation of cracks under the influence of dissolved atomic hydrogen, is the consequence.

    HSC can occur in a range of metals such as alloyed or unalloyed ferritic steels and nickel-base alloys. Cracking occurs when atomic hydrogen diffuses through the metal lattice to highly stressed points such as notches, inclusions, weld defects or crack tips, and hinders the capacity of the metal to deform plastically, causing it to crack instead. This effect will be stronger at lower temperatures where the diffusion of hydrogen is low enough to become trapped in a stressed zone. The severity of HE depends first on the concentration of dissolved hydrogen. HSC is a quick process: when the conditions are right, crack growth is a process of hours rather than years, although cracking may stop when conditions change. In higher strength materials, the HSC rate tends to be higher and potentially more catastrophic than in ductile metals.

    So, where in the refinery can HSC occur? It requires three ingredients: dissolved hydrogen, susceptible metal, and plastic strain. Hydrogen dissolves in metal when in contact with hot hydrogen gas, such as in hydroprocessing units, or when aqueous corrosion reactions form cathodic hydrogen in the presence of H2S, HCN, or HF. This form of hydrogen charging may cause HSC known by another name: sulphide stress cracking or SSC. Aqueous H2S solutions are found in numerous locations in a refinery from storage tanks to the sour water stripper, basically all wet and ambient temperature locations. This is pretty much everywhere in the refinery if the shutdown condition is considered as well. HF exposure is generally limited to HF alkylation units.

    The stresses that produce local plasticity can have several causes: weld stresses and other fabrication stresses, thermal stresses, internal pressure, and external forces. Regarding design, installations are elastically strained, but in practice they often are not.

    Susceptible metals are ferritic materials or duplex stainless, or Ni based alloys, and the critical property is hardness. The reason that hardness determines susceptibility is that crack tip blunting in softer metals gives a lower stress intensity, whilst a sharper and more highly stressed crack tip zone in harder metals is prone to brittle cleavage failure. An empirically derived hardness limit for ferritic steel is 22 HRC, below which HSC is less likely (though not impossible). The finer points of HSC encompass an elaborate standard defining hardness limits and other specifications of metallic materials in relation to SSC in refineries.

    Avoiding HSC requires the following main principles:

    • When shutting down, slow-cool hot pressurised hydrogen-containing equipment in accordance with the specifications.
    • Follow the materials specifications as given in NACE Standard MR0103.
    • Fastidiously adhere to MOC procedures.


  • Berthold Otzisk, Kurita Europe, berthold.otzisk@kurita-water.com

    Hydrogen embrittlement is an insidious type of failure, often driven by bisulphide ions (HS-) as high pH corrosion. Refinery units with high pH operations are hydrotreaters, amine units, sour water strippers, and FCC light ends. Hydrocrackers, visbreakers, and coker fractionators are occasionally affected, while H-Oil units (LC Finers) or reformers are only infrequently affected.

    Hydrogen embrittlement is a form of corrosion, where high-strength steel becomes brittle and fractures following exposure to hydrogen. Often this form of corrosion is not recognised, which can lead to unexpected and sometimes catastrophic damage. The complete mechanism is not completely understood, because hydrogen embrittlement is not a permanent condition. It starts with hydrogen atoms diffusing through the metal. When these atoms recombine to form hydrogen molecules, they can create extremely high pressure from inside the cavity they are in. When this occurs, the metal ductility is significantly reduced, leading to cracking and brittle failures.

    Hydrogen sulphide ions are known to promote hydrogen embrittlement by allowing more time for the atomic hydrogen to become absorbed. This inhibits the recombination reaction of atomic hydrogen to molecular hydrogen.

    The degree of embrittlement can be influenced by the amount of hydrogen and microstructure of the metal. Ferritic steel is more susceptible to hydrogen embrittlement than high quality steels such as austenitic stainless steels, aluminum, and nickel alloys with different crystal structures. The best method of controlling hydrogen damage is to limit the contact hydrogen has with the metal. Film forming inhibitors reduce the potential for corrosion. They are absorbed to the metal through its polar group. The non-polar tail of the inhibitor is oriented vertical to the metal surface, then the atomic hydrogen reacts with the corrosion inhibitor forming a barrier to the metal surface.


  • Andrew Layton, KBC (A Yokogawa Company), Andrew.Layton@KBC.global

    There are a number of embrittlement corrosion phenomena which are sometimes confused. A brief clarification of three of the most common is given here before talking specifically about hydrogen embrittlement:

    • Temper embrittlement of steels, which is a high temperature long term phenomenon related to higher alloy materials especially when used in thick wall reactor vessels.
    • H2 embrittlement of steels which is a low temperature phenomenon usually related to absorption of H2 generated from cathodic corrosion reactions like Wet H2S corrosion
    • High temperature H2 attack (HTHA) of steels is a relatively high temperature phenomenon impacting more the low alloy materials like CS or C ½ Moly. This is often discussed in recent years because it is related to significant incidents on hydrotreaters or naphtha reformers. This has resulted in the updating of the Nelson curves which identify when HTHA is a concern as a function of temperature, H2 partial pressure, and material type.

    H2 embrittlement of steels is created by absorption of H2 into the steel at low temperatures. It has several forms and there are many mechanisms proposed. Important factors contributing to the phenomena include high hardness, the presence of stress, and water. Typical examples are:

    • Poor welding procedures where moisture may be present
    • Localised dissimilar metals, allowing a corrosion cell to be created in the presence of moisture; this will also generate H2 at the cathode. This can happen in many locations where there are dissimilar materials in the presence of water. One example could be dissimilar bolt/washer/structure materials on jetty or any external supports.
    • Wet H2S corrosion, which is perhaps the most common example of H2 embrittlement, especially if any cyanides and high ammonia levels are present in the presence of H2S and water. Cyanides are a particular problem even at low ppm levels as they can remove the sulphidic protective layer which helps prevent the corrosion cells being set up.

    Typical location examples for H2 embrittlement are:

    • Poor welding and in hardness zones
    • FCC/coker overheads and light ends systems where H2S/cyanides and moisture are present
    • Hydrotreater reactor effluent and stripper systems where H2S/moisture/ammonia is present and sometimes cyanides, which is a particularly bad actor
    • Gas treating systems such as amine systems
    • Alkylation units
    • Sour water systems
    • Some crude and VDU systems dependent on crude type

    Typical mitigations are:

    • Good welding practices
    • Improved steel fabrication standards and selection for equipment going into wet H2S service
    • Dilution of corrosion precursors by water washing with a focus on good mixing design as well as dilution
    • Use of chemical additives such as polysulphides
    • Stress relieving of critical equipment after construction or mechanical/welding work
    • Good inspection programme
    • Good positive materials identification to prevent dissimilar materials issues


  • Chris Claesen, Nalco Water, Chris.Claesen@ecolab.com

    Hydrogen embrittlement is a complex process. A simple way to describe the cause is by the diffusion of atomic hydrogen into metal followed by recombination to molecular hydrogen in voids or impurities in the metal, causing local areas of high pressure inside the metal. It can occur during welding or in a sour wet environment if conditions are such that atomic hydrogen can be generated and diffuse into the metal. The units with wet sour environments that can be most susceptible to embrittlement in a refinery are normally the FCC, thermal cracking units such as cokers and visbreakers, and downstream amine units.

    Hydrogen embrittlement can be avoided by using steels that are less susceptible and the use of proper welding procedures for equipment in sour service. Monitoring the composition of sour water can help determine the risk for hydrogen embrittlement for a certain part of a unit while in operation. If conditions are such that there is an increased risk, actions can be taken to reduce the risk. These can include reduction of corrosives by water wash or scavengers or the use of a corrosion inhibitor. Failure of equipment by stress corrosion cracking due to hydrogen charging can be a very drastic event with severe consequences and all possible means should be used to prevent this. Nalco Water can help manage the risk for hydrogen embrittlement with analytical capabilities, monitoring, and the use of patented Pathfinder corrosion inhibitors.


  • Collin Cross, SUEZ – WTS, collin.cross@suez.com

    Hydrogen embrittlement (HE) is a type of damage suffered in various high strength steels. It is caused by penetration of monoatomic hydrogen into the metal which then recombines to form molecular hydrogen leading to internal pressures that weaken the intergranular structure. Various forms of specific damage occur from HE, but generally all are versions of cracking. The differences in types of cracking are due to the specific impact on ductility, types of environments, and types of stresses leading to the damage. The alloys most affected by this mechanism are certain carbon alloy steels, certain stainless steels, and some high strength nickel alloys.

    Units affected by HE in refineries are units that contain environments with high concentrations of hot hydrogen, the proper chemical conditions, the right type of steel, and are subjected to various types of mechanical stress. There are also several special reasons HE can occur as a result of welding practices, cleaning practices, metal manufacturing processes, and so on. While these are important mechanisms that can cause HE, for the discussion here we will focus on unit types that provide the correct hydrogen rich chemical environments and oftentimes are the most at risk. 

    For HE to occur, generally three factors are necessary: high concentrations of hot (<300°F, 150°C) gaseous hydrogen, alkaline conditions, and poisoning agents that slow the recombination of monoatomic hydrogen into molecular hydrogen. Examples of common poisoning agents are cyanide, arsenic and sulphides. The type of corrosion that favours the conditions above is called wet H2S corrosion and most frequently occurs in cracking units such as FCC and hydroprocessing units, cokers, amine units, sour water service units, and HF alkylation units.

    To avoid HE, there are many strategies that should be employed. Routine inspection and monitoring help the detection and mitigation of HE. Proper alloy usage is also an important factor. Post weld heat treating (PWHT) of components, proper welding practices, and proper start-up/shutdown procedures of at-risk units are all important. Protective linings can also be used in the proper circumstances to prevent hydrogen reactions from occurring as favourably. Finally, chemical mitigation can also be used to control HE to a large extent.

    Chemical treatment generally falls into two categories, which are scavenging and passivating. Traditionally, the use of a scavenger was called for and many equipment OEMs still call for this method of mitigation. The most common scavengers used are ammonium or sodium polysulphides. These chemicals are often called ‘cyanide scavengers’ because they work to destroy the poisoning agent and thereby lower the concentration of monoatomic hydrogen to prevent its penetration. While polysulphide scavengers work well and are still in use today, they have several negative side effects that have caused their use to decline in recent decades considering the development of newer and less problematical chemical methods. The problematical side effects of polysulphides include downstream equipment fouling, toxicity, pumpability, and handleability.

    Newer chemical mitigation methods surround the use of specialised high pH passivating inhibitors, or filmers, somewhat like those commonly used in other fractionator overhead corrosion services. While filmers do not directly eliminate the cyanide (or other poisoning agents) as do polysulphides, they do effectively help to prevent monoatomic hydrogen penetration and subsequent HE. HE is prevented in this case because the passivating film fosters rapid recombination from monoatomic hydrogen back to molecular hydrogen outside the metal, thus preventing the penetration necessary for embrittlement to occur. Many refineries today prefer the use of filmers to polysulphides due to their lack of negative side effects, favorable economics, and strong ability to prevent HE.


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