7.3 High-Temperature H2/H2S Corrosion (Couper-Gorman)

7.3 High-Temperature H2/H2S Corrosion (Couper-Gorman)

High-Temperature $\text{H}_2/\text{H}_2\text{S}$ Corrosion is an aggressive form of sulfidation that occurs in petroleum refining hydroprocessing units where hydrogen gas ($\text{H}_2$) and hydrogen sulfide ($\text{H}_2\text{S}$) are simultaneously present at elevated temperatures and pressures. Documented under API RP 571 Section 3.35, this mechanism governs materials selection and equipment integrity across hydrodesulfurization (HDS) units, distillate hydrotreaters (DHT), gas oil hydrotreaters, hydrocrackers, and catalytic reformer pretreaters.

While high-temperature sulfidation in $\text{H}_2$-free environments is governed by the modified McConomy curves, the presence of molecular hydrogen fundamentally alters both the reaction thermodynamics and the physical nature of the resulting scale. High-temperature $\text{H}_2/\text{H}_2\text{S}$ corrosion initiates at a lower temperature threshold of 450 °F (232 °C) and produces significantly higher metal loss rates than $\text{H}_2$-free sulfidation at identical temperatures and sulfur concentrations.

                     [ Hydroprocessing Stream: High-Pressure H2 + H2S ]
                                 Operating Temp > 450 °F (232 °C)
                                                |
                                                v
              +-----------------------------------------------------------------+
              | Porous, Friable, Non-Adherent FeS Scale                         |
              | H2 Prevents Passive Oxide & Coke Film Formation                 |
              | Rapid Outward Fe2+ Diffusion & Rapid Scale Spalling             |
              +-----------------------------------------------------------------+
                                                ^
                                                | Rapid Metal Dissolution
              +-----------------------------------------------------------------+
              | Substrate: Carbon Steel & Cr-Mo Steels (1.25Cr to 9Cr)          |
              | ** Little Benefit from Cr until about 7-9% Cr **               |
              | 12Cr better; 300 Series SS (321, 347) Highly Resistant          |
              +-----------------------------------------------------------------+

Chemical Reaction Kinetics and The Transforming Influence of Hydrogen

The fundamental chemical reaction governing $\text{H}_2/\text{H}_2\text{S}$ corrosion is the reversible reaction between iron and hydrogen sulfide:

$\text{Fe} + \text{H}_2\text{S} \longleftrightarrow \text{FeS} + \text{H}_2$

Although the stoichiometric reaction indicates that molecular hydrogen is a product of the corrosion reaction, the presence of high-pressure hydrogen gas in the bulk process environment drives three catastrophic kinetic and metallurgical transformations:

1. Reduction of Organosulfur into Reactive H2S: In $\text{H}_2$-free service, stable thiophenic ring sulfur compounds pass through equipment without reacting. In hydroprocessing units, high-pressure hydrogen catalytically hydrogenates and hydrocracks even the most refractory thiophenes and dibenzothiophenes into gaseous, highly reactive $\text{H}_2\text{S}$. Thus, virtually 100% of the sulfur in the process stream is converted into active corrodent.
2. Suppression of Protective Coke and Oxide Barriers: In $\text{H}_2$-free service, semi-protective coke films and trace oxide scales help moderate sulfidation kinetics. High-pressure hydrogen creates an intensely reducing chemical atmosphere that completely eliminates oxide films and retards coke accumulation on metal surfaces, leaving the base metal continuously exposed.
3. Formation of Highly Defective, Fragile FeS Scale: The iron sulfide scale formed in the presence of $\text{H}_2$ is structurally disorganized, highly porous, and populated by extreme cation vacancy densities. The scale exhibits virtually zero adherence to the steel substrate, flaking and spalling continuously during operation and leaving bare steel in direct contact with $\text{H}_2\text{S}$.

The Couper-Gorman Curves and Key Operating Variables

Corrosion rates in high-temperature $\text{H}_2/\text{H}_2\text{S}$ service are predicted using the Couper-Gorman Curves, published by A.S. Couper and J.W. Gorman in 1971 based on extensive NACE Committee T-8 surveys and verified refinery operating data, and reproduced as modified curves in API RP 571 Section 3.35 and API RP 939-C.

Primary Process Variables Governing Corrosion Rates

1. Temperature: Corrosion initiates at 450 °F (232 °C). Corrosion rates increase exponentially with temperature up to approximately 750 °F to 800 °F (399 °C to 427 °C). Above 800 °F (427 °C), the rate of increase often plateaus or may even decrease slightly due to thermodynamic equilibrium shifts in the reversible reaction $\text{Fe} + \text{H}_2\text{S} \longleftrightarrow \text{FeS} + \text{H}_2$ and changes in sulfide scale morphology.
2. H2S Concentration (Partial Pressure / Mol%): Evaluated across the spectrum from 0.01 mol% to 10.0 mol% $\text{H}_2\text{S}$ in the process vapor phase. Corrosion rate increases with the partial pressure of $\text{H}_2\text{S}$ ($P_{\text{H}_2\text{S}} = y_{\text{H}_2\text{S}} \cdot P_{\text{total}}$).
3. Unit Pressure and Stream Type (Naphtha vs. Gas Oil): The modified Couper-Gorman curves include separate correlations for naphtha and gas oil desulfurizers. API RP 571 notes that, primarily because of higher H2S partial pressure, corrosion rates in higher-pressure units such as gas oil hydrotreaters (desulfurizers) and hydrocrackers are generally higher than in lower-pressure naphtha hydrotreaters.
4. Vapor/Liquid Ratio: RP 571 lists the vapor-liquid ratio among the critical factors, together with temperature, the presence of hydrogen, H2S concentration (partial pressure), and alloy composition.

  Corrosion Rate (mpy) - Naphtha Service at 1.0 mol% H2S
   100 |                                            Carbon Steel (low-Cr steels only slightly lower)
    80 |                                      * * *
    60 |                                * * *
    40 |                          * * *
    20 |                    * * *
     0 +--------------* * *-----------------------[ 300 Series Austenitic SS < 2 mpy ]
     450°F         550°F         650°F         750°F         850°F
                               Temperature (°F)

Chromium Content: Why Low Alloy Steels Help Only a Little

A heavily tested contrast in RP 571 is how differently chromium performs in H2-free sulfidation (Section 3.61) and in H2/H2S service (Section 3.35).

Comparison: Modified McConomy vs. Modified Couper-Gorman

Order of Increasing Resistance (RP 571)

Carbon steel → low alloy steels → 400 series SS → 300 series SS. Chromium-containing nickel alloys behave like stainless steels with similar chromium levels.

• 9Cr-1Mo: the lowest alloy that normally gives a useful improvement over carbon steel.
• 12Cr Steels (Type 405 / 410): Better resistance than 9Cr, but prone to 885 °F (475 °C) embrittlement and limited weldability, so they are used mainly as cladding or internals.
• 300-Series Austenitic Stainless Steels (Type 304L, 316L, 321, 347): Provide outstanding corrosion resistance. With 18% to 20% Cr and 8% to 12% Ni, these alloys form a dense, adherent, microscopic chromium-rich sulfide/spinel barrier layer ($\text{Cr}_2\text{S}_3$ / $\text{FeCr}_2\text{S}_4$). Corrosion rates are typically 10 to 50 times lower than carbon steel, consistently remaining below 1 to 2 mpy under standard hydroprocessing conditions.
• Nickel-Base Alloys (Alloy 825, Alloy 625): Alloy 825 (UNS N08825, ~42% Ni, 22% Cr, 3% Mo) and Alloy 625 (UNS N06625) provide near-total immunity. Note: High-nickel alloys containing >60% Ni with low chromium (such as Alloy 200 or Monel 400) must never be used in high-temperature $\text{H}_2\text{S}$ environments due to the formation of a low-melting nickel sulfide eutectic ($\text{Ni}_3\text{S}_2$ / Ni) that melts catastrophically at 1175 °F (635 °C).

Reactor Construction, Cladding Strategies, and Polythionic Acid SCC

Because hydroprocessing reactors, exchangers, and separator vessels operate under severe combinations of high pressure (500 to 3000 psig), high temperature (500 °F to 850 °F), and high hydrogen partial pressure, equipment cannot be fabricated from solid austenitic stainless steel due to cost, thermal fatigue stress, and ASME section thickness limitations.

1. Dual-Metallurgy Construction Strategy

Refineries utilize a dual-metallurgy engineering design:

• Pressure Boundary Base Metal: Heavy-wall shell plates and forgings are fabricated from low-alloy steels—specifically 2.25Cr-1Mo or 2.25Cr-1Mo-0.25V (ASTM A387 Gr 22 / Gr 22V, ASTM A336 Gr F22 / F22V). These alloys provide high mechanical tensile strength, superior creep resistance, and verified resistance to High-Temperature Hydrogen Attack (HTHA) per the API RP 941 Nelson curves.
• Corrosion Barrier Cladding: The internal process-wetted surfaces are protected with a 3 mm to 5 mm (1/8 in.) internal layer of austenitic stainless steel, applied via roll-bonded clad plate or multi-pass automated submerged arc / electroslag weld overlay (typically an initial Type 309L buffer layer followed by a Type 347 finish layer).

2. The Threat of Sensitization and Polythionic Acid SCC (PASCC)

While 300-series stainless steels solve Couper-Gorman corrosion, they introduce an acute shutdown failure mechanism: Polythionic Acid Stress Corrosion Cracking (PASCC), documented in API RP 571 Section 3.52.

• Sensitization Mechanism: When standard austenitic stainless steels (such as Type 304 or Type 316) are heated within the sensitization range of 750 °F to 1500 °F (399 °C to 816 °C)—which occurs during reactor post-weld heat treatment (PWHT at ~1250 °F) or during high-temperature operation—carbon atoms diffuse rapidly to austenite grain boundaries, precipitating chromium carbides: $23\text{Cr} + 6\text{C} \longrightarrow \text{Cr}_{23}\text{C}_6$ This precipitates chromium from the adjacent metallic matrix, depleting localized grain boundary chromium content to well below the 12% passivity limit.
• Shutdown PASCC Attack: During turnaround shutdowns, ambient oxygen and liquid water enter the opened vessel, reacting with internal iron sulfide scale to form polythionic acids ($\text{H}_2\text{S}_x\text{O}_6$): $\text{FeS} + \text{O}_2 + \text{H}_2\text{O} \longrightarrow \text{H}_2\text{S}_x\text{O}_6$ In the presence of residual weld or fabrication stresses, polythionic acid attacks the sensitized, chromium-depleted grain boundaries, causing rapid, catastrophic intergranular cracking that can propagate through an entire vessel wall or piping spool within hours.

3. Prevention Guidelines (NACE SP0170)

To eliminate PASCC risk in hydroprocessing units:

1. Specify Stabilized Stainless Steel Grades: Specify Type 347 (stabilized with niobium/columbium: $\text{Nb} \ge 10 \times \text{C}$) or Type 321 (stabilized with titanium: $\text{Ti} \ge 5 \times \text{C}$). Niobium and titanium form stable carbo-nitrides at elevated temperatures, tying up carbon and preventing chromium carbide precipitation.
2. Specify Thermal Stabilization Heat Treatment: Type 321 and 347 base materials and weldments are thermally stabilized by heating to 1600 °F to 1650 °F (871 °C to 899 °C) for 4 hours, ensuring complete carbon precipitation as TiC or NbC.
3. Implement NACE SP0170 Shutdown Procedures: Prior to opening hydroprocessing equipment to air, internal surfaces must be neutralized with an alkaline wash solution (typically 1.0 to 2.0 wt% sodium carbonate / soda ash), or purged continuously with dry nitrogen maintaining a dew point below -40 °F (-40 °C) to prevent liquid moisture condensation.

Affected Process Units, Damage Morphology, and Inspection Strategies

1. High-Risk Refinery Units and Circuits

• Hydrodesulfurization (HDS) & Hydrotreating Units (NHT, DHT, VGO HT): Feed furnace radiant tubes, reactor transfer lines, reactor inlet diffusers, catalyst support grids, reactor effluent piping, and effluent heat exchangers upstream of the reactor effluent air cooler (REAC) water wash injection point.

• Hydrocracking Units: 1st and 2nd stage hydrocracker charge heaters, interstage reactor piping, reactor effluent exchangers, and hot high-pressure separator (HHPS) vessels.

• Catalytic Reforming Units: Naphtha pretreater charge heaters, reactors, and recycle gas piping containing $\text{H}_2$ and $\text{H}_2\text{S}$.

• Downstream of Hydrogen Injection: RP 571 notes noticeable increases in corrosion rate downstream of the hydrogen injection point, where the mechanism changes from H2-free sulfidation to H2/H2S corrosion.

2. Macroscopic Appearance and Scale Fouling Hazards

• Appearance: Uniform loss of thickness from the process side under an iron sulfide scale. RP 571 notes that the scale is about five times the volume of the metal lost and may be multilayered, and that a tightly adherent, shiny gray scale can be mistaken for unaffected metal.
• Downstream Catalyst Bed Fouling ("Scale Blinding"): In fired heaters fabricated from under-alloyed carbon steel or Cr-Mo steel, heavy iron sulfide scale continuously exfoliates into the process fluid. This scale debris is carried directly into downstream hydroprocessing reactors, settling across the top of the catalyst bed. Known as scale blinding, this debris chokes flow channels, generating severe reactor bed differential pressure ($\Delta P$) spikes that force premature unit shutdowns.

3. Non-Destructive Examination (NDE) and Materials Verification

• 100% Positive Material Identification (PMI): Because carbon steel and low-chromium steels have far less resistance than the specified stainless steel, accidental installation of a low-alloy spool piece in an austenitic stainless steel circuit results in catastrophic rapid failure. Specifications mandate 100% PMI testing (via XRF or spark-OES) on all field welds, shop fabrications, flanges, fittings, and thermowells.
• Profile Radiography (PRT): Deployed on piping circuits, thermowells, and small-bore fittings to verify remaining wall thickness and detect internal scale shedding without insulation removal.
• Automated Ultrasonic Thickness Scanning (AUT): High-density ultrasonic grid mapping on furnace tubes, transfer line elbows, and separator shells to establish true corrosion rates.
• Internal Dye Penetrant Inspection (PT): Applied to stainless steel cladding, weld overlays, and internal attachment welds during turnarounds to detect intergranular polythionic acid stress corrosion cracking.