TrendCurvesCorrosionRates-H2S

1. Purpose

This procedure provides and explains the curves for predicting corrosion rates of the commonly used steels in an H2S (Hydrogen Sulfide) environment.

2. General

Data used for plotting the curves was accumulated prior to 1970. Most early curves were from data derived from short term laboratory and pilot plant tests which reflected initial high rates. The result is a correlation of many published and private curves, and data points adjusted in the direction dictated by service performance in Inflection Point Engineering processes, i.e. hydrotreating, Unibon, Unionfining, Unicracking, or other units where high temperature H2S corrosion is present. This adjustment was in the general direction of showing lower corrosion rates than one would predict from the available published curves.

Curves published in the 1960’s by the NACE International, T-8 Committee on Refinery Industry Corrosion, show about a 50% reduction in corrosion rates of various alloys from earlier published curves. These curves were a result of a study which determined that pressure in the range studied was an insignificant factor; therefore, volume or mole percent of H2S was used rather than partial pressure. Although our preliminary curves were based on H2S partial pressure versus temperature, most of our applications are at higher pressures where we also feel partial pressure of H2S is less significant than volume percent. Therefore, Inflection Point Engineering decided to use the volume percent criteria.

3. Corrosion Rate Curves

Reference the following curves grouped according to alloy content:

See

Attachment 1 - Trend Curves For Predicting Corrosion Rates of 0-5% Chromium

Alloy Steel

Attachment 2 - Trend Curves For Predicting Corrosion Rates of 9% Chromium

Alloy Steel

Attachment 3 - Trend Curves For Predicting Corrosion Rates of 11-13%

Chromium Stainless Steel

Attachment 4 - Trend Curves For Predicting Corrosion Rates of 18%

Chromium - 8% Nickel Stainless Steel

Determining corrosion rates using TZ-700-01 is an alternative to using the trend curves in Attachment 1-4. Corrosion rate predictions using TZ-700-01 will be the same as those determined using the trend curves.4. Curve Support Information

These curves apply to H2S environments (hydrogen-hydrocarbon diluent) at temperatures from 400 to 1100 F and H2S concentrations from 0.001 to 10.0 volume percent. Note that this environment is different from a wet H2S environment; see Procedure for requirements for wet H2S service. Exact corrosion rates are impossible to predict because of the wide scatter of the data. Many variables contribute to corrosion and effect its behavior, (i.e., type of hydrocarbon diluent, fluctuations to operating conditions, number and severity of regenerations, etc.). However, these curves do predict satisfactory rates that may be utilized for material selection in new units with an acceptable level of confidence.

To further clarify these curves, note a dotted line at 600 F and 0.001 volume percent H2S to 1100 F and 0.04 volume percent H2S. This dotted line represents the "Thermodynamic Cut-Off" under which no corrosion would occur if a pure thermodynamic reaction is obtained. The reaction Fe+H2S +H2 in the areas under this dotted line reverses and corrosion would not occur. Since this thermodynamic reaction is an ideal situation it is shown only for academic purposes. Any variation in operating conditions and possibly corrodents other than H2S make the use of this "Thermodynamic Cut-Off" impractical for actual operations.

Corrosion rates are in mils per year (MPY), 1 mil per year equals 0.001" per year (IPY). For H2S in a naphtha diluent these curves are conservative since the predicted corrosion rate is probably slightly higher than what will be encountered.

Not shown are any differences in corrosion rates in the 0-5% Cr and 9% Cr curves that would reflect the type of hydrocarbon present even though some data shows higher rates in the heavier oils, such as gas oils vs. naphtha when H2S content is the same.

The curves are trend lines to be used for predicting corrosion rates, as a basis for alloy selection regardless of hydrocarbon medium and as guidance on preliminary material selection.

5. Equipment Selection and Corrosion Rates

Most materials are selected based on Inflection Point Engineering practices per the following:

5.1 In hydrotreating, Unibon, Unionfining, Unicracking, or other units where high temperature H2S corrosion is present, the first criteria is that materials meet the H2 resistance required for temperature versus hydrogen partial pressure. Use API (American Petroleum Institute) publication 941 “Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants” to determine the minimum material for the design conditions.

5.2 Once minimum material requirements for H2 are set, decide the importance of keeping the hot section of the unit free of sulfide corrosion scale that may cause plugging in catalyst beds. Frequency of catalyst regenerations is a factor and also the more regenerations the more carryover of scale and possible plugging of catalyst.

5.3 If 5.2 is an important factor as it is for example with Unicracking Units, then select a material with low corrosion rate in the 2-5 MPY range.

5.4 Lower alloys may be applicable where some scale and higher corrosion rates are acceptable, although the alloy chosen must resist the H2 partial pressure.

5.5 When estimating corrosion rates on materials, use the maximum operating temperature rather than design temperature. This will result in some economy of material choice.

The design philosophy for the particular unit and specific piece of equipment impacts the tolerable or acceptable corrosion rate used for material selection. For example, heat exchanger tubes in a Unicracking Unit Feed versus Effluent Exchanger will be relatively thin and not able or practical to be designed with much corrosion allowance. In this case, select a higher alloy material with a predicted corrosion rate of no more than 5 MPY. In the same unit, the shell may be designed with a larger corrosion allowance and thus possibly lower alloy. Piping may also be designed with greater corrosion allowance, thus where scale carryover is not a problem, it may tolerate more corrosion and thus lower alloy. Heater tubes generally require higher alloy because of the higher inside tube wall temperature and its effect on increasing corrosion rates.

Many customers set forth minimum life requirements for the various types of equipment. In such cases, base the requirements on corrosion allowances, acceptable corrosion rates, and the material required.

IPE-TM-700-01 Attachments 1-4.PDF

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