Revamps 2025 Issue

A number of hydroprocessing unit types are amenable to some level of revamp to co-process: kerosene hydrotreat- ers, diesel hydrotreaters, VGO (vacuum gas oil) hydrotreat- ers, and hydrocrackers. The first three, likely needing liquid recycle, will readily produce renewable diesel and will have some flexibility toward SAF selectivity. The resultant paraffin products from HEFA co-processing will produce a significant amount of C 18 + (and C 17 paraffins if appreciable decarboxy - lation occurs), which exceeds the desirable C8 -C 16 range for jet fuel. This dictates that a hydrocracking component will be required in a co-processing process for SAF production. Furthermore, the product paraffin content is inadequate to meet the cold flow properties required for jet fuel needs. Hence, a hydroisomerisation, or dewaxing, step will also be required. Hydrotreaters are generally not designed to be overly selective to appreciable conversion to jet-range material owing to quench limitations and unit configuration. Single-stage, once-through hydrocrackers fall into a similar category. Even so, revamp activities can alleviate this prob- lem. Hence, a kerosene hydrotreater will require modifica - tions, the incorporation of dewaxing catalyst, and adequate quench at the least, to be able to feed renewable feeds that produce paraffinic product within the jet boiling range that meet freeze point requirements. At least one technology provider maintains that kerosene hydrotreater co-processing is the preferred cost-effective means to maximise SAF yield.4 Two-stage hydrocrackers have the most potential to both maximise SAF yield as desired, concurrent with fossil fuel jet yield, and retain flex - ibility to adjust renewables content and selectivity between diesel and jet. IEA publications provide an approximate indication of SAF yield potential and overall yield debits from carbon chain reduction: maximum jet mode is about 55% with a naphtha plus light ends yield of approximately 20% contrasted to a roughly 10% naphtha plus light ends yield in diesel mode. Technology providers have given some guidelines on co-pro- cessing routes. As an example (adapted from references3 ): • For <5% co-processing. ■ Requires feed rate adjustment or lower cycle length to manage planned cycle. ■ No unit revamp, uses hydroprocessing catalyst system with guard catalyst for renewable feed contaminants. • For 5-10% co-processing. ■ Requires minor compressor modifications and metal - lurgy upgrades in a few locations. ■ Uses tailored catalyst system, including significant guard catalyst for implementation. • For 10-20% co-processing. ■ Requires new equipment with metallurgy upgrade. ■ Uses tailored catalyst system and guard catalysts. Approximate operational impacts of co-processing have also been provided: • Some 40-50 Nm3 /m 3 (18-24 scf/bbl) of hydrogen con - sumption per % of renewable co-processed. • Roughly 3°C (5°F) temperature rise per % of renewable in feed. • Propane yield about 0.2 wt% fresh feed per 5% renew- able feed.

Other than corrosion considerations discussed subse- quently, areas of concern include stripper overhead and fractionation limitations that can arise due to increased pro- pane, methane, CO, and CO₂ production, as well as poten - tial amine treating effects resulting from a CO₂ dominated recycle gas. The higher heat of reaction for CO₂ with amines may require more reboiler energy in the regenerator. Corrosion considerations With respect to corrosion potential for co-processing, it is important that a unit undergo a corrosion analysis and audit to set a baseline for further corrosion risk evaluation in order to co-process renewables.⁹ Any unit with corro - sion issues, however minor, prior to co-processing, will only have exacerbated problems later. Feed system corrosion issues will most likely occur due to the free fatty acid (FFA) content, chloride content, and mois - ture content associated with renewable feeds. Chlorides introduce potential for chloride stress corrosion cracking (CSCC) in feed piping, heaters, and preheat exchangers. Carbon steel could pose an unacceptable corrosion risk, and even austenitic stainless steels (304, 316) may not prove adequate. Duplex stainless steels may need eval - uation. FFAs present corrosion risk that is not unlike high TAN in fossil fuel feeds. TAN can be readily estimated from renewables per cent FFA by TAN ~ % FFA X 2. Any upstream low-carbon or 0.5 molybdenum (Mo) steel metal- lurgy can be at risk. Stainless steels with higher Mo provide good resistance, such as 316, 317L, and 317LM. Unfortunately, chlorides accelerate FFA corrosion.⁹ Reactor downstream metallurgy corrosion is made worse by the significant CO₂ production, plus water that intro - duces carbonic acid corrosion potential, plus ammonium carbamate corrosion, as well as increased salt deposition (ammonium chloride, ammonium bisulphide). Existing water wash rates may certainly need to be increased, and additional water wash injection may be required. Areas of concern, particularly for CSCC, are the effluent side of F/E exchangers and the reactor effluent air coolers (REACs). Carbon steel (CS) is inadequate for the service. Older REACs, frequently constructed with CS, now need upgrading to stainless steels (316, 316L) to address ammonium carbamate and CSCC. More than 10% co-processing could necessitate mov- ing to materials such as Hastelloy C-276 alloy.9 Further downstream, in the LP separator, stripper overhead, and amine absorber section, CS would need to be replaced to avoid carbonic acid and alkaline stress corrosion cracking (ASSC) due to high levels of CO₂ and moisture and high carbonate concentrations at high pH. 316L should be suit - able in most cases. Metallurgy upgrades can be capital-in- tensive, and the options with some pros and cons noted are as follows: • Replacement: ■ Expensive for major components. ■ Long lead times in many cases independent of project scope. • Field-applied weld metal overlay (WMO): ■ Potential damage to vessel shell or existing cladding.

Revamps 2025