Corrosion issues in hydrocracking

Corrosion at the top of the hydrogen sulfide removal tower is severe; attention should be paid to the core of the tower top cooler. The reaction part is of course more important.

Erosion and elbow erosion corrosion at the fluid inlet end of the air-cooling fin tubes in the high-pressure air cooler of the hydrocracking unit’s reaction effluent stream. For example, the perforation in the air cooling system of a hydrocracking unit was caused by poor fitting of the stainless steel liner at the tube end, along with erosion and corrosion in the area where the end was bent upward. The perforation in the air cooling system of a hydrocracking unit was caused by high sulfur content in the feedstock, insufficient water injection, and the accumulation of large amounts of scale inside the air cooling tubes; erosion and perforation occurred near this scale. In a hydrogen cracker unit at a certain plant, electrochemical corrosion-induced perforations occurred due to deteriorating feedstock and insufficient water injection, resulting in the accumulation of scale. Anti-corrosion measures: 1. Air-cooling tube bank design: Use header boxes; avoid elbow or U-shaped tube structures. Adopt a completely symmetric design, with the number of air-cooling tubes being 2n, where n is any integer. When the Kp value is high, use alloy materials such as 825. The maximum allowable peak tube velocity is 6 m/s for carbon steel tubes and 9 m/s for alloy tubes. If erosion occurs at the ends of the tube bank, lining tubes made of 300-series stainless steel should be used, with the lower end of these lining tubes having a smooth slope. 2. Pipe header design: Both inlet and outlet pipe structures should be completely symmetric. There should be no dead zones in the inlet and outlet headers. Outlet pipes coming from the REAC tube bank should be equipped with temperature indicators. When the Kp value is high, alloy materials such as 825 should be used. The maximum allowable peak tube velocity is 6 m/s for carbon steel tubes and 9 m/s for alloy tubes. 3. Water injection: The amount of water injected should be sufficient to keep the NH4HS concentration in the wastewater below 8 wt%. The amount of water injected and the locations where it is injected must ensure that at least 20% of the injected water remains in liquid form at those points. Multiple injection points are only used in asymmetric designs, and instrumentation should be used to control and adjust the amount of water injected at each point. Tubing-based injection systems are more commonly used than direct connection methods. The quality of the flushing water (i.e., levels of O2, pH, iron, Cl-, and cyanide) must meet specified requirements. 4. Operation: Prevent the deposition of polycyclic aromatic hydrocarbons. All tube banks should maintain the same temperature when the unit is shut down. Last edited by yongshi518 on 2007-10-10 21:25

How can wealth be accumulated? There are many areas in hydrocracking that may suffer from corrosion; upgrading the materials used is one approach, but it is also important to employ anti-corrosion measures and ensure stable operation. For example, in hydrocracking processes that use a stripping tower, it should theoretically not be possible for corrosive substances to exist in the distillation column section. However, if the operation of the stripping tower is not stable, severe corrosion can occur at the bottom of the distillation column, and this has been observed in China as well

Kp = [H2S] × [NH3] Where: Kp———corrosion coefficient of the fluid； ［H2S］———Molar concentration of hydrogen sulfide in logistics, % ； [NH3]———Molar concentration of NH3 in logistics, %. Kp is less than 0.07%, the material is carbon steel, and the maximum flow velocity is limited to 9.3 m/s ； Kp is equal to 0.1%–0.5%; the material is carbon steel, and the flow rate range is 4.6–6.09 m/s ； When Kp is greater than 0.5%, and the flow rate is below 1.50–3.05 m/s or above 7.62 m/s, the high-alloy materials 3RE60, Monel, or Incoloy 825 should be used.

Everyone is familiar with the Kp value, but how can NH3 and H2S in materials be detected? I hope someone with insight can give me some advice. Thank you!

Sampling analysis – field workers often do this; what else can they do? This post was last edited by zndong666 on 2008-10-28 at 21:00

As is known from sampling and analysis, what’s important is where to take the samples from. Should one analyze high- or low-pressure liquids or gases? How can these values be applied in the calculation of Kp values?

What is the difference in corrosion between the hydrocracking reaction section and the hydrogen sulfide removal tower?

NACE Publication 34103‑2004, \"An Overview of Sulfide Corrosion in Refineries,\" states that since 1990, some refineries have observed abnormal sulfur corrosion in the pipelines of the hydrogenation unit’s distillation systems as well as in the tubes of reboilers. In these areas, hydrogen is not present, and the sulfur concentration is low; yet the corrosion rate of Cr–Mo steel is the same as that of carbon steel. To this end, NACE established a dedicated T176 working group. The furnace tubes and high-temperature pipelines of the distillation systems in 12 hydrocracking units and 2 diesel hydrotreating units were investigated. After analyzing these survey data, the literature puts forward the following view: (1) The corrosion rate may be higher than the rate predicted using the modified McConomy curve or the Couper-Gorman curve ； ⑵Alloy steels containing 5% Cr or even 9% Cr have the same corrosion rate as carbon steel ； ⑶Local corrosion can be severe, for example in areas with high flow rates or turbulent flow, or at the top of horizontal furnace tubes ； ⑷The corrosion rate can be very high, even when the total sulfur content is very low (a few PPm by mass) ； ⑸All forms of sulfur exhibit a certain degree of corrosivity ； ⑹The role of hydrogen in the corrosion mechanism of equipment remains unclear ； According to the recommendations in NACE Publication 34103–2004: For the heating furnaces in hydrogenation units, carbon steel, 5Cr, and 9Cr furnace tubes are used, and they should be considered to have the same corrosion rate. Based on various studies, this value is estimated to be between 1–2 mm/year. When the wall temperature is high and the H2S concentration is high, 2 mm/a is adopted for safety reasons. When necessary, the horizontally arranged shielding tubes are made of stainless steel. Special Cases ⑴ Case: Fire incident in the bottom reboiler of the distillation tower at the Ulsan Refinery in South Korea. The heavy oil processing unit at the Ulsan Refinery, located in a city in southwestern South Korea, was put into operation in 1992; it mainly includes a vacuum distillation unit, a hydrocracking unit, a residue hydrodesulfurization unit, and a hydrogen production facility. The plant’s maximum processing capacity for high-sulfur fuel oil is 19,078.44 m3/day, with the main products being naphtha, kerosene, gasoline, ultra-low sulfur fuel oil, and sulfur. The heavy oil treatment unit operates mainly under high temperature and pressure, and the reboiler at the bottom of the distillation tower is a radial-convection type cylindrical furnace. One midnight in October 2003, a fire broke out due to the leakage of feed oil when the bottom reboiler of the fractionation tower in the hydrocracking unit of that heavy oil treatment plant suffered a rupture in the upper part of the third tube in the third row of the convection section, counted from the side where the flue gas flowed. The fire burned for 2 hours, destroying the reboiler. The lower shielding section of the convection chamber consists of two rows of light tubes; the failure point is located in the first row of nail-head tubes above the shielding tubes, and the material of these furnace tubes is 1Cr5Mo. ⑵Case: Fire accident in the distillation furnace of the residue nitrogenation and desulfurization unit at the Maoming branch. The residue hydrogenation and desulfurization unit at Sinopec’s Maoming branch came online in 1999; the furnace tubes in the convection and radiation sections of its distillation furnace were made of 1Cr5Mo material, with specifications of Ф152×8mm. The main parameters are as follows: cylindrical furnace design, four feed paths; the pressure of the material entering the furnace is 2.35 Mpa and the temperature is 366°C, while the temperature of the material exiting the furnace is 384.1°C. On April 19, 2003, the furnace tube of the internal oil transfer line within the radiant section of the unit’s distillation furnace broke and caught fire, resulting in an emergency shutdown of the unit; no damage to the furnace’s internal components occurred. The top of the horizontal section of the oil transfer line cracked at a distance of 15 mm from the elbow weld; the crack was fan-shaped, approximately 120 mm long and 50 mm wide. Thickness measurements taken of the radiant furnace tubes revealed that the upper portion of the straight sections of the horizontal oil transfer lines was severely corroded, while the thickness in the lower portion remained essentially unchanged (tube wall thickness: 1.8–2.4 mm). The measured maximum corrosion rate is 1.96 mm/a. ⑶Case: Fire in the bottom reboiler of the butane removal column in the hydrocracking unit at Sinopec Zhenhai Branch. The hydrocracking unit at Sinopec Zhenhai Branch was designed with a capacity of 800 kt/a; it uses vacuum distillates from Shengli crude oil as raw material, and it came online in March 1993. At the end of 1995, to meet the needs of processing high-sulfur crude oil from the Middle East, the plant was upgraded to a capacity of 900 kt/a. In 1999, the plant’s capacity was further increased to 2.2 Mt/a. The bottom reboiler of the butane stripping tower is of cylindrical design, with four feed streams. The pressure of the material entering the reboiler is 1.95 Mpa and its temperature is 290°C, while the temperature of the material exiting the reboiler is 355°C. In June 2000, a leak and fire occurred in the furnace tubes of the convection section, then the radiant section, and finally the oil transfer line in the bottom reboiler of the unit’s butane removal tower, resulting in an emergency shutdown of the facility. During inspection, thickness measurements of the furnace tubes revealed severe thinning in the straight sections of the 4 oil transfer lines (furnace tube specifications: Ф152×8mm, material: grade 20 steel). Upon further examination, it was found that the top part of these oil transfer lines was the most severely corroded, with the actual wall thickness being less than 1.9 mm. Based on the processing of high-sulfur crude oil starting in June 1996, the tube corrosion rate is approximately 1.5 mm/year. The above 3 cases share the following common characteristics: ① reboilers in hydrogenation units, ② severe corrosion at the horizontal shielding section or above the oil transfer line, ③ a corrosion rate far higher than the design value. Based on the above cases and literature, I estimate that after passing through the low-pressure separator, the reaction effluents from hydrogenation units still contain dissolved hydrogen, and in addition to hydrogen sulfide, sulfides should also include thiols. Based on production experience, this situation may result in a large amount of unremoved thiol compounds at the end of the catalyst’s lifespan, which enter the distillation system along with the hydrogen carried by the fluid under high load conditions. In the horizontal tubes of the fractionator, low flow rates lead to a gas-liquid stratification, creating an environment of high hydrogen + hydrogen sulfide/thiol concentrations at the upper part. Therefore, the design of this area should take into account that the material is a hydrogen-containing sulfide, with particular attention to thiol compounds, as their corrosion rate is twice that of hydrogen sulfide. Therefore, it is recommended to use 321 material for thickness measurement on the upper part of the shielding tube during shutdown.

A similar accident occurred in Maoming on April 16, 2008, and it indeed requires in-depth investigation. Similar problems have occurred with hydrogenation reboilers in many Sinopec companies. This post was last edited by enen007 on 2009-2-11 21:27.]