A series of sudden tube leaks in four first-stage overhead exchangers of a crude tower of a major Gulf Coast refinery was attributed to repeated contamination of the crude charge with organic chlorides. Corrosion in these exchangers increased to the point where the remaining life of the exchangers was used up in a matter of weeks. The contaminated crude oils were traced back to a single supplier that had dumped organic-chloride containing hydrocarbon waste streams into one of the refinery's pipelines over a period of 10 months, and possibly longer. The organic chloride content of the contaminated crude oils was found to have ranged from approximately 3 to 3,000 ppm (rag/L). Organic chlorides in crude oil are known to cause severe corrosion in crude tower overhead systems. Therefore, most refineries allow no more than 1 ppm (mg/L) organic chlorides in the crude charge. In this particular case, the actual crude charge contained at least 50 ppm (mg/L) at the time when most leaks occurred, and possibly as much as 255 ppm (mg/L).
This paper summarizes the results of an investigation into the cause of a series of sudden tube leaks in four first-stage overhead exchangers of the crude tower of a major Gulf Coast refinery. Based on past inspection reports, no unusual problems were experienced with these shell-and-tube heat exchangers prior to February 1997, when the unit operators first noticed that jet fiael did not meet color specifications. This often indicates that crude oil somehow ended up in the jet fuel. The crude unit had a nominal throughput of 175,000 bbl/d (28 MM L/d). The unit processed a variety of sweet crudes with salt contents between 2.5 and 5 Ib/l,000 bbl (7 and 14 kg/IMM L), corresponding to 10 to 20 ppm (rag/L) inorganic chlorides. A two-stage desalter maintained the salt content of the desalted crude at approximately 0.1 lb/I,000 bbl (0.28 kg/IMM L), corresponding to approximately 0.4 ppm (mg/L) chlorides.
The crude tower overhead system consisted of two condensing stages. Both condensing stages operated "wet", i.e., water condensate was withdrawn from both overhead drums. An organic neutralizer and a filming-amine corrosion inhibitor were injected upstream of the overhead exchangers of both condensing stages.
The amount of water withdrawn from the first-stage drum (reflux drum) was usually not large enough for reliable pH measurements. At the low salt content of the desalted crude charge, the chloride content of water from the first-stage drum probably did not exceeded 2.5 to 5 ppm (mg/L). The pH of the combined water condensate from both condensing stages was measured once a week and typically ranged from 6.5 to 7. The chloride content of the combined water condensate also was measured once a week and typically ranged from 15 to 35 ppm (mg/L). Prior experience had shown that neither pH or chloride content varied significantly under normal operating conditions. No corrosion probes had been installed.
Naphtha from the overhead system was sent to several downstream units, but primarily to a naphtha hydrodesulfurizer where leaks occured in 300 series stainless steel tubes of reactor effluent coolers just prior to the time the tube leaks in the overhead exchangers of the crude unit were discovered. The tube leaks at the naphtha hydrodesulfurizer will be mentioned only in passing.
FAILURE HISTORY
Tube leaks in the first-stage overhead exchangers early in February 1997 were the first indication that corrosion in the first condensing stage of the crude tower overhead system had increased for some yet unknown reason. These four parallel heat exchangers cooled and condensed crude tower overhead vapors from approximately 275 F (1
