Wet H2S service – What are the Typical Requirements for Steel Plate?

Pressure Vessel made with Dillinger Steel Plate for Wet H2S service

Pressure Vessel made with Dillinger Dicrest HIC Resistant Steel for Wet H2S service

Many petrochemical refineries have Hydrogen Sulphide (H2S) present in the their process streams. Famous for it’s smell of rotten eggs H2S when mixed with liquid water in a refinery is known as Wet H2S.

In most refineries carbon steel boiler plates are used in this environment but they are subject to degradation depending on the a number of key factors

  • pH – acidity
  • H2S Level
  • Temperature
  • Duration of Exposure
  • Nature of the material.

Normally the key issue is not thickness loss in the plate but rather it is the hydrogen in the H2S that is a major concern. Hydrogen is involved in many corrosion mechanisms but the presence of H2S enables there to be a high atomic hydrogen penetration of the steel.

The consequence of this is that the steel becomes embrittle and the atomic hydrogen can recombine to form hydrogen molecules as inclusions in the steel. High hydrogen pressure can then cause high stresses within the steel plate.

Degradation of Steel in Wet H2S Service

The main types of degradation are:

HIC – Hydrogen Induced Cracking.

Hydrogen Induced Cracking is a form of planar cracking when atomic hydrogen diffuses into the carbon or low alloy steel plate. this then combines back into hydrogen molecules at trap sites in the steel. Hydrogen pressure, assisted by hydrogen embrittlement then can cause cracks to appear without the requirement for any external stresses.

The main risk factors are the cleanliness of the steel and the size and shape of inclusions in the steel. Cracks occur in the X-Y axis of the plate and can be identified by characteristics bulges in the plate surface.

SSC – Sulphide Stress Cracking

Sulphide Stress Cracking a different form of cracking which occurs through a combination of stresses on the plate am the presence of atomic hydrogen. in this case the cracks are perpendicular to the the stresses. One of the key risk factors is the hardness of the plate used. It’s possible to get plate resistant to SSC

SWC – Stepwise Cracking 

This is a variation of of HIC. In this case there are multiple hydrogen induced cracks in the metal at different depths. However there are additional perpendicular cracks that then link these planar cracks to form the characteristic stair pattern. Risk factors are the hydrogen embrittlement and the additional stresses caused by the bulging caused by HIC. Applied stresses can also have a contributory effect.

SOHIC – Stress Oriented Induced Cracking

SOHIC cracks occur in plate already subject to HIC cracking. In this case there is stress in the plate – either applied or residual. The cracks appear perpendicular to the principal stress and tend to link pre-existing HIC cracks in a ladder like array. Plates with SOHIC resistance aren’t produced.

Severity of Wet H2S Service

The severity of the Wet H2S Environment is dependent on the H2S content and the pH of the water in contact with the boiler plates. Normally steam composition is used as the primary determinant of severity, but this needs to be reviewed in light of unusual process operations or brief events that aren’t covered by normal operation procedures.

pHH2S ppm
10 to <50≥50 to ≤2000>2000 to ≤10000>10000
<5LowSevereSevereSevere
≥5 to ≤7.8LowModerateModerateSevere
> 7.8LowModerateSevereSevere

If there is a presence of cyanide groups (CN) with a concentration of more than 20 ppm then many cases will be upgraded to high severity

Steel Plate Specifications for Wet H2S Service

Generally carbon steel plates can be used for sour service at all levels – low, moderate and severe, with a corrosion allowance. This is typically 3 – 6mm depending on plates thickness and other factors. However the plates (and other carbon steel components such a forged parts, flanges and pipes) have to meet demanding specifications and these are usually called HIC resistant steel or HIC resistant plate.

The specifications issued by oil and gas companies for HIC plate are designed to

  • reduce the hardness and limiting the tensile stress in the steel. This is done by limiting the residual elements that can increase the hardness of the steel.
  • reduce HIC susceptibility. This is done by restricting he amount of sulphur and controlling the shape of inclusions
  • Limiting crack propagation. This is done by restricting phosphorous in the steel and segregating element content.

Plates for HIC use are fully killed and normalised. They are also vacuum degassed, deoxidised and produced with a fine grain structure. The process also has to be focused on delivering steel with a very low phosphorous and sulphur content.

Steels for use in Wet H2S environments ate produced by:

  • desulphurisation
  • dephosphorisation
  • deoxidising

Calcium treatment can be used to manage inclusion shape if the steel is not particularly clean. Generally calcium treatment is used where sulphur content in the plate is above 0.002% but it is limited to 3 times the sulphur content.

Normally a yield strength of 415 MPa is the maximum allowed (meaning that HIC plates cannot be quenched and tempered) and hardness has to be lower than 200 HB (which also helps with the risk of SSC).

Wet H2S in Refineries

Whilst many refineries are concerned with the effects of wet H2S few oil fields produce crude with a high h2S content. Instead most H2S in refinery process steams occurs as a by product of other processes within the refiner. These include

Breaking this down a bit:

  • The pure crude feed has little H2S in it. However thermal cracking adds H2S as does hydrodesulphurisation  (HDS) and coking when cuts are fed back into the feed for reprocessing.
  • Distillation overhead is normally moderate sour service whilst some of the waste gases normally flared can fall under the severe classification
  • When light cuts are hydrotreated wet H2s can result and the low temperature areas of hydrotreatment units are often classified as moderate H2S service.
  • HDS units and hydrocracker units generally have high concentrations of H2S and consequently low temperature downstream areas with water present tend to be classified as server service. Amine absorbers and the overhead of downstream  separators is also severe.
  • Cyanides can strongly impact the severity of HIC corrosion in thermal cracking units such visbreakers and cokers; also fluid catalytic converters (FCC) can be severe at the cold light end cut (mainly for LPG).
  • Amine processing units (absorbers and regeneration units are severe service
  • Examples of units that are not concerned with West H2S service are reforming, alkylation, isomerisation and propylene. Generally anything that is downstream of a hydrotreatment unit or amine absorber does not need HIC resistant steel

Oakley Steel sells Dicrest HIC resistant steel from Dillinger Hutte thats meets the requirements of all major oil companies including – Total, Exxon, Shell, Petronas and Pertamina

This article is based on a paper by Richez and Zanoncelli at the Dillinger Pressure Vessel Colloquium in 2009. Any mistakes or misinterpretations are of course my own!

 

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