Application Discussion
AD126
June 15, 2003

As environmental regulations tighten relating to sulfur, heavy metals and aromatic hydrocarbons, hydroprocessing has become a much more utilized process in the refining industry. Hydroprocessing enables the processing of many different feedstocks to produce products that are economically favorable at a given time while removing entrained contaminants.

Hydroprocessing includes processes such as hydrotreating and hydrocracking. Hydrotreating processes are used to remove undesirable materials from a feedstock by selective reactions with hydrogen in a heated catalyst bed. This removes sulfur, nitrogen and certain metal contaminants. This process is often used to remove catalyst poisons from a feedstock before downstream processing. In this process, olefins and aromatics are converted to saturated hydrocarbons.

The hydrocracking process converts (cracks) heavy feedstocks into lighter components by selective reactions with hydrogen in multiple heater catalyst beds. This process is most commonly used to create gasoline or diesel product streams.

Most hydroprocessing today utilizes a single stage fixed-bed catalytic process. The fresh feed is mixed with makeup hydrogen and recycle gas (rich in hydrogen content) and sent through a heater to the first reactor. If the feed has not been hydrotreated, there is a guard reactor before the hydrocracking reactor. The catalyst in the guard reactor converts organic sulfur and nitrogen compounds to hydrogen sulfide (H2S), ammonia (NH3) and additional hydrocarbons to protect the precious metal catalysts in the other reactors. The hydrocracking reactor is operated at a sufficiently high temperature to convert 40 – 50 percent (volume) of the reactor effluent to material boiling below 400 degrees. The reactor effluent goes through heat exchangers to the hot high pressure separator (HHPS) where the hydrogen-rich gases flashed off overhead. The hydrogen rich gases are then sent to the cold high pressure separator (CHPS) for additional separation from which the hydrogen rich gases are recycled to the first stage of the process for mixing with additional hydrogen and the fresh feed. The liquid effluent from both the HHPS and CHPS is sent to a fractionalization column where the butane and lighter gases are taken off overhead and the light and heavy naphtha, jet fuel and diesel fuel are removed as liquid side streams. Figure 1 shows the process flow diagram of a hydrocracking operation.

Figure 1: Generic Hydrocracking Process Flow Diagram

The separator letdown valves control the liquid level in the HHPS and CHPS. In some processes, these valves may dump the liquid effluent from the HHPS and CHPS to a low pressure separator before flowing to the fractionalization tower. Utilizing a low pressure separator allows additional removal of hydrogen and light hydrocarbons.

In order to control the level in the CHPS, two valves (typically angle style) ranging in size from 2” to 4” are normally used to control flow to the fractionalization column or low pressure separator. With pressures in the CHPS ranging between 1500 and 3000 psig and pressures in the fractionalization tower ranging from 100 to 300 psig, concerns arise due to flashing damage and vibration.

Not only will the flashing fluid be erosive it can also be corrosive. This is because the entrained H2S and NH3 can attack the trim and body materials. Because there may be some entrained catalyst from the reactor, the valve also must be able to pass the flowing particulate without plugging the flow passages and without causing erosion damage. The most common material used for the trim components is 316 SST with an Alloy 6 overlay. Valve bodies can be either WCC (heat treated for NACE) or 316 SST, however additional trim and body materials are available if necessary.

For this application, Fisher recommends the use of the Dirty Service Trim (DST) in the appropriate valve body. DST utilizes a staged pressure reduction to eliminate the formation of damaging cavitation and also compensates for volume expansion of flashing fluids via expanded area staging. DST is also designed to pass particulate up to ¾” in diameter ensuring the plugging due to catalyst fines will not occur.