Filters

(2010) Question 51: In your experience, what are the implications on coker heater run length and coke drum operations with the following feedstock quality: Contaminants (Na, Ca), low saturates or high asphaltenes, crude compatibility, solvent deasphalt (SDA) pitch, low asphaltenes and high saturates?

There are at least three main mechanisms under which the heater tubes become fouled: •Inorganic material deposition or precipitation, •Rapid asphaltene precipitation, •Coke formation
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(2010) Question 55: What is considered the best-in-class design for coker main fractionator wash zones? Have refiners seen good performance and target run lengths using grids in this service?

Cokers today are normally designed to operate to maximize liquid yield from the unit. This will require the coker to operate at as low a recycle as possible while still maintaining the required product specifications for the heavy coker gas oil (carbon content, metals, asphaltenes, etc.). For a low recycle operation a spray chamber is the best-in-class.
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(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.
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(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.
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(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.
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(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.
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(2010) Question 64: Please discuss the latest tray and packing technologies for improved fractionation efficiency in existing crude and vacuum units. In particular, what is the effectiveness in terms of fouling/plugging and resulting run length?

Well designed and installed fractionator tray, packing and liquid/vapor distributor equipment are one important tool in ensuring the crude/vacuum unit is able to reach its targeted runlength. A good understanding of operating parameters along with measures and systems to ensure that operation stays within those parameters are the other tools necessary to meet that targeted runlength.
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