Hydroprocessing

Unit Operation Description

Hydrotreating^{1 2 3}

The main goal for hydrotreating is to remove sulfur and nitrogen compounds from naphtha and gas oil. Historically hydrotreating was designed to treat feed to the catalytic reforming and isomerization which requires desulfurized product to prevent catalyst poisoning. Nowadays, hydrotreating is focusing, apart from its traditional role, on “cleaning” fuels allowing to meet increasing restrictions regarding automotive sulfur emission. Table 1 shows main feed-product options for hydrotreating unit.

Table 1 Feed-product options for Hydrotreating Unit.^{1 2}

Hydrocracking^{1 2 3}

Hydrocracking apart of hydrodesulfurization and hydrodenitrogenation shifting its goal to other reactions like cracking, isomerization, or saturation to obtain lighter, low viscosity, fuel products. Consequently, hydrocracking exhibits the capability to process a significantly wider array of feedstocks, ranging from heavy vacuum gas oils to atmospheric gas oils, yielding products spanning from heavy diesel to naphtha. Enhancing cracking, saturation, or de-alkylation reactions demands somewhat distinct catalysts compared to those used in hydrotreating. Typically, hydrocracking employs catalysts based on zeolites integrated with active metals like Pd, Ni-Mo, or Ni-W. In most hydrocracking units, catalysts for hydrodenitrogenation and hydrodesulfurization, typical in hydrotreating, are positioned on the initial beds, while lower beds are active in both hydrotreating and hydrocracking reactions.

Chemistry

From a chemical perspective, both hydrotreating and hydrocracking share a similar reaction setup. However, in hydrotreating, two particular reactions hold paramount importance from both desirable reaction and corrosion perspectives:

\(\ce{RSR1 + 2H2 -> RH + R1H + H2S}\) (hydrodesulfurization)

\(\ce{R=NR1 + 3H2 -> RH + R1H + NH3}\) (hydrodenitrogenation)

These reactions, alongside hydrogenation, isomerization, and cracking, occur on fixed catalyst beds typically composed of Ni/Mo/Co-alumina/zeolite/aluminosilicates. The selection of active metals and support type is tailored to the specific objectives of the hydroprocessing unit; for example, Ni-Mo catalysts supported on γ-alumina are commonly employed for hydrodesulfurization. In both hydrotreating and hydrocracking, H₂S and ammonia resulting from these reactions act as primary drivers of corrosion. They lead to ammonium bisulfide corrosion and wet-H₂S damage, particularly impacting sections like the Reactor Effluent Air Cooler (REAC); for in-depth details, refer to the dedicated NH4HS corrosion chapter.

Reactors

Reactor construction in both processes typically follows the trickle-bed system (refer to Figure 1). Here, the feed, mixed with hydrogen, is heated and enters the reactor’s top. As it flows through catalyst beds, interstage cold hydrogen injection cools the feed. Heavier feeds induce more exothermic reactions, necessitating additional quenching zones. Naphtha and kerosene hydrotreating may suffice with a single bed without quenching.

Corrosion within the reactor is primarily linked to high-temperature hydrogen attack, for which materials like 1-1/4Cr-1/2Mo or 2-1/4Cr-1Mo are commonly utilized as a mitigation strategy. Materials used in high-temperature hydrogen service must adhere to API RP 941 standards.

The presence of H₂S in the mixture triggers sulfidation within the H₂S/H₂ system, affecting various areas like feed pre-heat (post-H₂ injection), reactor effluent, and recycle hydrogen streams. Material selection and predicting corrosion behavior due to this mechanism can be facilitated using Couper-Gorman curves, accessible in the Tools section.

Prior to hydrogen mixing, the feed might instigate ’traditional’ Sulfidation in the absence of hydrogen. It’s crucial to scrutinize metallurgy and sulfur content, including active sulfur species, especially during crude feedstock upgrades that render them more sour and acidic. Similar considerations apply to the potential impact of Naphthenic Acid Corrosion, especially if vacuum gas oils, known for their propensity to generate such corrosion, are utilized as feed in hydrotreating or hydrocracking.

Another damage mechanism present in hydrotreating, as well as in hydrocracking units, includes chloride-stress corrosion cracking (Cl-SCC) and NH₄Cl Corrosion. Chloride may originate from hydrogen recycled from catalytic reforming, which uses Cl-activation for reforming catalysts. Ammonium chloride might deposit in exchangers downstream of the reactor. The justification for using, for example, 300 series austenitic stainless steel, is the operating temperature. At higher temperatures (e.g., feed/effluent exchangers), NH₄Cl deposition is limited, whereas in exchangers operating at lower temperatures (e.g., in REAC, stabilizer OVHD, or separators), under deposit corrosion, and Cl-SCC may likely occur. Cl-SCC might also manifest in drain branches made of austenitic stainless steels. This is typically observed shortly after shutdowns or turnarounds. If water is trapped in drains, during startup, when the temperature exceeds approximately 60°C (140°F), water will begin to boil off, leaving salt deposits that rapidly exacerbate the Cl-SCC phenomenon. Failures typically occur on welds without stress relieve.

Products cooling and separation

In both hydrocracking and hydrotreating, the reactor’s effluent first enters the separation phase to split the stream into vapor, water, and liquid hydrocarbon fractions. Typically, this process employs two separators, high-pressure, and low-pressure. From the bottom of the cold, low-pressure separator (CLPS), the hydrocarbon fraction is directed to the fractionator for separation into desired side cuts. Sometimes, the fractionator may be preceded by a stabilizer, as shown in Figure 1.

The corrosion processes prevalent in separation mostly originate from NH₄HS Corrosion and wet-H₂S damage. The occurrence of wet-H₂S damage, commonly observed in separators as blistering and hydrogen-induced cracking (HIC), becomes notably more pronounced in instances where there’s a greater likelihood of heightened CN^- concentration. This tendency is often encountered in situations involving the coprocessing of nitrogen-rich bio-feedstock.

Potential Damage Mechanisms

Figure 1 Hydroprocessing (HT/HC) Unit diagram with typical damage mechanisms.^{after API RP 571}

Legend: 1 - Sulfidation; 2 - Wet H₂S Damage (H₂ Blistering/HIC/SOHIC/SSC); 3 - Creep/Stress Rupture; 4 - High Temperature H₂/H₂S Corrosion ; 5 - Polythionic Acid SCC; 6 – Naphthenic Acid Corrosion; 7 – NH₄HS Corrosion; 8 – NH₄Cl Corrosion; 9 – HCl Corrosion; 10 - High Temperature Hydrogen Attack; 16 - Temper Embrittlement; 20 - Erosion / Erosion-Corrosion; 22 - Amine Stress Corrosion Cracking; 23 - Chloride SCC; 25 - Hydrogen Embrittlement; 30 – Short term overheating – Stress rupture; 31 - Brittle Fracture; 32 – Sigma Phase Embrittlement; 35 – Stress Relaxation Cracking; 45 – Amine Corrosion; 46 – Corrosion Under Insulation;

References

This Article has 3 references.

1:Ch.S. Hsu, P.R. Robinson editors - Practical Advances in Petroleum Processing vol 1 - Springer ScienceBusiness Media, Inc., 2006.

2:D.S. J. “STAN” JONES, P.R. PUJAD´O editors - Handbook of Petroleum Processing - Springer, 2006.

3:American Petroleum Institute Recommended Practice – API RP 941, latest edition.