Q&A

(2012) Question 3: How can lubricity be improved in ultra-low sulfur jet fuel?

The increased desulfurization of distillate fuels removes sulfur nitrogen and aromatics, which are components favorable for lubricity properties. The recent market conditions have led most refiners to not only produce ULSD, but also ULSK (ultra-low sulfur kerosene), in order to maximize distillate production.

(2012) Question 4: What are the hydrotreating operating issues when processing shale-derived light, sweet, and highly paraffinic crudes such as Bakken, Eagle Ford, and Utica? What hydrotreating/catalyst strategies can offset any negative effects? What options are available to optimize the distillate hydrotreater(s) with these light, sweet crudes?

The shale crudes in question are highly paraffinic, low sulfur, low nitrogen, and low in conventional contaminants. However, we do see some trace contaminants coming in from some of the fracking and completion chemicals. These crudes have a low resid content, which impacts the bottom of the barrel.

(2017) Question 43: What is your experience with intermittent mud washing of single-stage and two-stage desalting? What are the advantages of continuous versus intermittent mud washing?

The primary purpose of a mud wash is to suspend and remove solids that have accumulated in the bottom of the desalter. Some desalting operations use the mud wash to remove solids (asphaltenes and oil-wetted inorganic solids including iron) that have accumulated in the interface of the desalter. The desalter level may be lowered to accomplish this goal in some of these operations.

(2017) Question 44: How do you monitor exchanger fouling? How do you use that information to justify additional work scope during unplanned shutdowns?

Exchanger monitoring software or spreadsheets that pull in refinery process data can be used to monitor fouling trends. Exchanger trains should be evaluated for fouling on a routine basis to provide historical references and trends to compare pre- and post-cleanings.

(2017) Question 45: What are your typical consequences and probable sources of fuel gas fouling? What are your respective solutions?

Fuel gas fouling in refineries is an ongoing problem and is typically the result of many years of corrosion due to moisture in the fuel gas system. These systems are typically saturated with water vapor due to the amine scrubbing that is used to remove H2S, and water may drop out as a liquid in low velocity areas or in areas with inadequate insulation.

(2017) Question 46: What is your design service life of atmospheric tower overhead heat exchangers? How does that compare to actual service life? What do you do to better manage corrosion and improve reliability of these heat exchangers?

Heat exchangers are designed for heat recovery and only rarely for corrosion control. The designer’s tool for reliability is to use upgraded materials of construction. Over the years, those on our team have seen even Hastelloy C276 and titanium being used.

(2017) Question 47: What correlations do you use to predict cracked gas make in a vacuum tower from atmospheric tower bottoms based on feedstock properties and heater outlet temperature?

In the past, vacuum towers’ flash zones have operating at or below atmospheric tower flash zone temperatures. These units relied on the vacuum to increase heavy gasoil yields from the atmospheric resid without running the risk of thermal cracking associated with higher temperatures.

(2017) Question 48: What are your design and operating guidelines for vacuum tower bottoms versus crude heat exchangers such as minimum velocities, fouling rates, and pressure drop, and which process fluid should be on the tube side versus the shell side?

KPE believes the typical design for a vacuum bottom versus crude exchanger is for the crude to be on the tube side and the vacuum bottoms to be on the shell side. Most facilities I see have this setup as weli.

(2017) Question 49: How do you use today’s Advanced Process Control (APC) technology to achieve crude unit operation that supports short-and long-term planning goals? How do you achieve alignment between the crude unit APC and those of downstream units?

Without proper resources and attention, Advanced Process Control (APC) technology may experience inconsistencies as applied to crude units. Refineries where crude slate varies frequently may struggle capturing the value that APC provides for steady controls and optimization. Mode-based APC may be applicable, but irregularities in crude compositions may still provide hurdles.

(2017) Question 50: From this list of your top FCC gas plant constraints, which area is your primary constraint: 1) main column (MC) overhead, 2) wet gas compressor, 3) primary or sponge absorber, 4) stripper, or 5) debutanizer bottoms or overhead?

Refining investments in alkylation expansions and gasoline octane improvements require production of additional feedstock for the alkylation unit. The primary source of olefin feedstock for the alkylation unit is the FCC unit. Operating conditions in the FCC unit can be adjusted to favor increased propylene and butylene production. The FCC wet gas compressor becomes the first major bottleneck in recovering the incremental propylene and butylene. Modifications may be required to the compressor, as well as associated cooling, inter-stage, or after-stage equipment.

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