Regenerator overhead

The regenerator overhead is caustic and water washed, yielding a 95-96%... 

In gas dehydration service, triethylene glycol (TEG) will absorb limited quantities of BTEX from the gas. Based on literature data, predicted absorption levels for BTEX components vary from 5-10% for benzene to 20-30% for ethylbenzene and xylene [2]. Absorption is fa vored at lower temperatures, increasing TEG concentration and circulation rate. The bulk of absorbed BTEX is separated from the glycol in the regeneration unit and leaves the system in the regenerator overhead stream. 

Condense the regenerator overhead vapor in a partial condenser and combust the remaining vapor. The imcondensed vapors are typically routed to an incinerator or, if a direct-fired reboiler is used, routed to the reboiler fuel gas. The liquid hydrocarbons are collected and disposed of by blending into a crude oil or condensate stream. The condensed water is typically routed to produced water disposal. 

Route the regenerator overhead vapors to another process stream in the facility. This is typically a low pressure stream such as flash vapors from the last stage of a crude or condensate stabilization system. 

A blue tinge in the lean amine indicates the presence of cyanides. The cyanides are coming from the FCCU wet gas. They should have been scrubbed out of the wet gas with an aqueous-phase polysulfide wash. These cyanides will promote corrosive failures in amine regenerator overhead system and hydrogen blistering or cracking in piping and vessels that contact the lean amine. 

Reducing the water vapor content of acid gas to a minimum also increased Claus capacity. During periods when one of the two sulfur trains was out of service, the amine regenerator reflux drum temperature was reduced from 135°F to 110 F. This was achieved by spraying treated water on the exterior of the amine regenerators overhead fin fan tube bundles. This reduced the water content of the acid gas from 10% to 5% and thus increased sulfur recovery capacity by 2%. 

The nomograph of Figure 3-3 can be used to provide an estimate of the corrosion rate in the regenerator overhead and the contactor bottoms of amine plants when CO2 is the only acid gas present. De Waard and Lotz (1993) also discuss the use of correction factors to account for the effects of corrosion product films, pH, system pressure, system geometry, glycol or methanol, crude oil, inhibitors, and flow velocities on corrosion rates. 

In refineries, the amine regenerator overhead system is often affected by wet acid gas corrosion due to the combined presence of ammonia, CO2, and H2S. Wet acid gas corrosion of the overhead system is accelerated if HCN is also present (Ehmke 1981A, B). In these circumstances, wet acid gas corrosion due to H2S and CO2 can occur when the CO2 content of the acid gas is less than 90%. In fact, substantial corrosion can occur in the total absence of CO2 if sufficient HCN and ammonia are present. 

In the regenerator overhead condenser, the gaseous ammonia and HCN are reabsorbed in the condensed reflux water. Ammonia dissolved in the reflux water provides the alkalinity to absorb and retain add gases, such as H2S, CO2, and HCN in solution. 

Without a reflux water purge, ammonia, H2S, CO2, and HCN are trapped in the amine regenerator overhead system. If both ammonia and HCN are present, the net effect is a substantial increase of the HCN, H2S, and CO2 concentrations in the amine regenoator ovo -bead system. 

A reflux water purge to reduce the concmtration of ammonium cyanide and bisulfide in the amine regenerator overhead. See Figure 3-1. 

Injection of either ammonium or sodium polysulfide upstream of the amine regenerator or into the amine regenerator overhead system to convert the cyanide iron to thiocyanate. 

Figure 3-8. Use of amine regenerator overhead temperature to control amine stripping.

Instrument taps plugged with particulates, solids accumulation in the regenerator overhead condenser, and reduction in amine filter cycle lengtii (Lieberman, 1980)... 

Liquid hydrocarbon skimming unities in the absorber sump, the rich amine flash drum, the regenerator sump, and the amine regenerator overhead accumulator (Bacon, 1987). 

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