Q&A

(2010) Question 56: Some crude tower overhead deposition appears to be linked to corrosion treatment programs (i.e. filming corrosion inhibitors and neutralizers). Have you confirmed this and what are the potential mechanisms that can lead to this deposition?

Corrosion inhibitors (filmers) have been known to cause deposition in several different ways. Generally, the cause is injection into an overhead that is too hot, flashing off the carrier, or injection of neat chemical, flashing off its solvent.

(2010) Question 58: In your experience has a non-phosphorous corrosion inhibitor been successfully used to mitigate naphthenic acid corrosion? In what circumstances and under what conditions are non-phosphorous corrosion inhibitors used?

Phosphorus-based naphthenic acid corrosion inhibitors have been successfully used in the refining industry since the early 1980’s. Phosphorus provides its protection to steel by corroding it and forming a passive layer that, under SEM/EDS, proves to be an Iron/Phosphorus/Sulfur blend.

(2010) Question 59: What are refiners using to define the corrosivity of high acid crude oils and how is this data obtained?

In line with industry rules of thumb, Marathon considers a crude to be high acid with a whole crude Total Acid Number (TAN) above 0.5% or a side stream above 1.5%. With low sulfur crude slates the maximum TAN may be reduced, as one of our refineries that runs a predominantly sweet slate experienced naphthenic acid corrosion resulting in the TAN limit being reduced to 0.3%. Crudes are blended to the refinery TAN limit with sulfur, metallurgy and specific stream temperatures taken into account.

(2010) Question 60: Please discuss advanced methods you use to monitor corrosion in operating units. Are any of these used in conjunction with the DCS for continuous on-line monitoring?

Marathon utilizes three methods of corrosion monitoring in the crude/vacuum units: multipoint resistance measurement (iicorr, FSM, GEBetz RCM) systems for naphthenic acid corrosion, ER probes, and corrosion coupons. While the use of coupons may not be considered an ‘advanced method’ for monitoring corrosion, we do continue to utilize them in our refining system.

(2018) Question 26: How do you monitor furnace convection section fouling? What mitigation steps do you implement?

Monitoring the flue gas temperature leaving the process convection section is a simple method of tracking the heat transfer in the convection section. The excess air needs to be taken into consideration as a higher O2 concentration will shift heat transfer into the convection section and causes the total quantity of flue gas to increase.

(2018) Question 27: What is your experience with chemical treatment to reduce furnace coking?

For conventional fouling, which is the result of asphaltene destabilization due to temperature, chemical treatment programs have not been effective for Coker heaters. For premature asphaltene precipitation due to resid compatibility concerns, chemical treatment programs have been effective in reducing or eliminating fouling.

(2018) Question 34: What is considered your practical limit on TAN (Total Acid Number) of blended crude diet before monitoring, treatment, or metallurgy upgrades should be considered to avoid naphthenic acid corrosion issues?

Understanding the mechanism of naphthenic acid corrosion, we model the hot circuits looking at the potential TAN of the stream, metallurgy and fluid velocity within the circuit. Once this has been done, we evaluate the options, if the corrosion potential is high enough.

(2018) Question 51: For advanced (closed) riser termination systems, where does coke form inside the reactor vessel? What is the typical amount accumulated during a run?

The quantity of coke is heavily dependent on reactor technology, feed quality, and operating conditions. In earlier termination devices the riser outlet was open to the reactor. The vapors would spend a lot of time in the reactor resulting in coking.

(2018) Question 53: In the Third Stage Separator (TSS), what is the expected life of swirl tubes or cyclones assuming good performing regenerator cyclones? Of these two types, which handle upsets/ variable particulate loadings better?

The performance of swirl tubes is comparable with cyclones in terms of separation efficiency. Swirl tubes have distinct advantages over cyclones in being more compact, much easier to construct and have high mechanical integrity.

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