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Annual Meeting

March 19-21, 2017

Marriott Rivercenter

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AM-17-27 Prepare, Produce, Profit: Debottlenecking

Refineries through Comprehensive Feedstock

Preparation

Presented By:

Austin Schneider

Crystaphase

Houston, TX

Patrick Gause

Crystaphase

Houston, TX

This paper has been reproduced for the author or authors as a courtesy by the American Fuel & Petrochemical Manufacturers. Publication of this paper does not signify that the contents necessarily reflect the opinions of the AFPM, its officers, directors, members, or staff. Requests for authorization to quote or use the contents should be addressed directly to the author(s).

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Prepare, Produce, Profit: Debottlenecking refineries through comprehensive feedstock preparation

What are the obstacles limiting your planned cycle lengths and turn around schedules? Alternatively, what are the impediments to simply regaining control of your cycle and running your most valuable assets the way you need to? What are the impacts of modified turnaround schedules to your refinery throughput? Shutdowns result in skims, catalyst replacement, and poorly performing equipment and are among the costliest events in a refinery. Taking these assets out of service limits throughput of upstream processing units, and results in significant opportunity losses. The ability to avoid these costly events ultimately comes down to defining and understanding feedstock contaminants and identifying the bottlenecks in your facility. Combining the capabilities of Baker Hughes and Crystaphase® addresses these obstacles. With tools to plan and execute holistic strategies, refiners mitigate bad actors on multiple fronts. This In turn greatly increases reliability, availability, and cycle length.

Commercially advantaged crudes offer improved profitability, but at the cost of a wide array of particles and poisons that can quickly erase any expected windfall if not adequately addressed. Additional contaminants are generated throughout the processing train, from initial distillation to sulfur recovery. It is well known that these contaminants can constrain throughput in distillation and desalting operations and, if not dealt with properly, can further impact downstream hydrotreating operations.

Provided in the remainder of this discussion are strategies to deal with inherent and in-situ contaminants throughout the refinery. Following the path of the feedstock through the refinery, the authors demonstrate the benefits of complementary approaches to managing the particles and poisons that can limit refinery profitability.

Desalter Optimization

In the refinery, the desalter is often regarded as the first and only line of defense to remove particles, poisons, and soluble contaminants. In the desalting process, fresh wash water is mixed with the incoming crude so that it can contact entrained salts, solids, and other contaminants. When the desalter is upset, the amount of these solid and particulate contaminants released to the crude unit can increase significantly. For this reason, the desalter is often the focus of attention when unexpected and unacceptable levels of contaminants carry downstream with the desalted crude.

Maximizing contaminant removal in the desalting process requires attention to optimizing the wash water rates, temperature, mixing, level and chemical demulsifier choice and dosage. However, operating outside of design conditions or with process limitations can result in inadequate desalting performance. In such cases, refiners are faced with few options and often must limit the types of crude oils processed, foregoing profit opportunities. Baker Hughes has developed a method called Crude Oil Management™ approach that looks beyond the desalting operation and takes a more comprehensive view of all equipment, processes, and feedstocks that ultimately contribute to reliable desalter operations 1. The program features a suite of tools including engineering

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practices, monitoring tools, and a variety of chemical treatments to provide a targeted and effective solution to the problem at its actual source while minimizing negative downstream impacts.

One tool that has been applied successfully to improve desalter efficiency in many refineries is crude oil pretreatment. Crude oil pretreatment is a strategy to relocate demulsifier injection from the desalter to the crude storage tank in order to significantly increase the contact time of the demulsifier with the crude oil. It allows time for the demulsifier to penetrate through the crude oil to treat surfaces and interfaces. When pretreated crude oil is charged to the unit and enters the desalter, it is poised for quick and efficient emulsion resolution and release of solids to the brine. In addition, pretreatment breaks up emulsions in crude tank bottoms and minimizes sludge release from the tankage. It stabilizes the quality of the crude feedstock, allowing the desalter to operate at higher mixing pressures and maximize salt and contaminant removal.

A proper pretreatment program reduces the amount of demulsifier applied at the desalter in direct proportion to the amount injected into the crude storage tank. Pretreatment programs, therefore, often result in a net decrease in chemical spend. Pretreatment demulsifiers are engineered for low-temperature functionality in the tank farm, and, in addition to demulsification properties, they should be designed to condition solids for partitioning into the desalter brine.

One US Gulf Coast refiner was running a heavy crude (API 16-18) and experiencing frequent desalter upsets. The desalter emulsion interface was difficult to control and often in excess of 5 feet. The brine contained significant amounts of oil, resulting in excessive slop oil generation. A pretreatment program was applied at the tank farm using the XERICTM heavy oil demulsifier program. Within 24 hours of initiating the pretreatment program, the desalter emulsion layer was reduced from 5 feet to less than 18 inches. Oil in the brine leaving the desalter was reduced to <500 ppm, and the refiner was actually able to increase the amount of heavy Canadian Crude in the feed from approximately 10% to over 30%. Significantly, the pretreatment program provided reliable desalter operation which allowed an increase in the mixing energy. This, in turn, resulted in an increase in salt removal efficiency from approximately 88% to 94%. (Figure 1). This translated to significantly fewer contaminants and catalyst poisons being charged to the crude unit.

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Figure 1. Improvement in salt removal with optimized mix valve DP.

Another Crude Oil Management tool that has been applied successfully to improve desalter efficiency is the JETTISONTM solids release agent (SRA)2. The SRA conditions solids in the crude oil to facilitate their partitioning into the desalter brine, where they drop out and are removed from the bottom of the vessel. In a successful SRA program, a significant amount of solids are removed from the crude oil and transferred to the brine. The effluent brine is dirty with solids, but these solids are oil-free.

In one US Gulf Coast refinery, heavy crude oil was being processed with high levels of solids. These particles promoted emulsion interface growth in the desalter and poor brine quality. Removal of the solids from the crude was inefficient, ultimately causing fouling of downstream equipment. An SRA treatment program was developed and initiated. Immediate benefits were seen as the emulsion layer was reduced by 35% and solids loading was shifted to the lowest trylines (Figure 2). Solids removal efficiency across the desalter (desalted crude vs raw crude) was improved to more than 70%. This actually allowed the refiner the ability to increase the solids-laden opportunity crude to approximately 50% of the total charge, resulting in $135,000/day incremental profit while minimizing negative downstream impact.

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Figure 2. Solids release to bottom of desalter with JETTISON program.

Metallic contaminants in crude oil can influence the desalter operations and, if allowed to continue past the desalter, can affect downstream catalyst performance. Two particular metals of prominence are sodium (Na) and calcium (Ca). While routinely present as chloride salts, these metals can also exist as salts of naphthenic acids. When improperly treated and carried over with emulsions, these naphthenate salts can also impact downstream operations and catalysts.

Removal of naphthenate salts is a critical objective if a refiner wishes to process opportunity crudes. Desalter acidification offers an approach to converting the metals into water soluble salts that are easily removed with the desalter brine. This not only removes the metals from the desalted crude, it improves desalter operation and reliability by converting the naphthenates into oil soluble naphthenic acids. These acids must be accounted for downstream in both a corrosion program and in the impact these corrosive components could have on hydrotreater fouling.

The solution offered by Baker Hughes to provide safe, cost effective desalter acidification is its EXCALIBUR™ contaminant removal technology3. The EXCALIBUR product line features acids selected to achieve metals removal targets while avoiding the major downstream impacts of commodity acids.

A European refiner was attempting to process a deeply discounted African crude high in calcium naphthenates. The crude blend, containing up to 20% of the African crude, contained calcium levels as high as 119 ppm. Desalting performance when processing the crude oil was unacceptable, limiting the amount of crude in the crude blend. Baker Hughes recommended a desalter acidification program using the EXCALIBUR

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technology. The treatment program achieved an average calcium removal of more than 75% (Figure 3) while at the same time meeting the required salt removal and crude dehydration targets and providing improved waste water treatment operation.

Figure 3. Calcium removal program.

Corrosion Byproduct Removal

While many of the constituents and contaminants in crude oil are directly responsible for harming catalyst bed operation, some of the concerns arise from a secondary impact. Three examples of crude contaminants that fit this description are the feedstock presence of tramp amines, the presence of naphthenic acids, and the presence of sulfur. All three of these can produce conditions of high corrosion in the process units. The byproducts of the corrosion (iron salts) can contribute to reactor bed plugging and hydraulic limitations. The corrosion mechanisms involved differ for these three contaminants, as do the locations where the metal loss will occur; however, the impact to reactor bed is the same.

Tramp amines can enter the crude distillation unit in the crude oil, in refinery slops streams, and via the desalter wash water4. Regardless of the source, these amines create stable emulsions and react with hydrolyzed HCl, producing corrosive salts that liberate iron from equipment surfaces. The released iron salts can, in turn, carry to distillate hydrotreating beds and contribute to hydraulic limitations. Tramp amines, consequently, represent a dual threat to reliability and operation of refinery processes, including fixed bed catalysts. Mitigating these tramp amines can be achieved by proper management of desalter pH. Baker Hughes EXCALIBUR™ contaminant removal technology provides a means to reduce desalter pH, which, in addition to improving salt

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removal efficiency, causes tramp amines to partition to the desalter brine, reducing the potential for overhead system corrosion.

A gulf coast US refinery processed a topped crude that was treated to mitigate H2S. The scavenger chemistry used in the crude produced a byproduct tramp amine, monoethanolamine (MEA), which reacts aggressively to form HCl salts. Tower top corrosion was severe, leading to operational limitations and increased maintenance to repair corrosion damage, all while generating corrosion products that foul downstream reactor beds. A multi-step mitigation program was implemented to reduce overhead HCl concentration and EXCALIBUR treatment to bring desalter pH under control and reduce overhead MEA concentration. Figure 4 shows the corrosion risk, reflected as the salt approach temperature at the tower top before and with mitigation. The salt approach, shown as MEA Salt Point ΔT (in °F), indicates high risk of corrosion as the value approaches and goes below 0°F. Best Practice guidelines call for a target of +25°F to minimize risk of tower corrosion. Figure 5A and 5B show the tower internals for operation without and with the mitigation strategy. Minimizing the corrosion in the upstream distillation process reduced the secondary impact of downstream reactor bed fouling.

Figure 4. Mitigating amine salt corrosion in crude distillation tower.

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Figure 5A. Tray condition without mitigation. Figure 5B. Tray condition with mitigation.

Complementing a robust corrosion mitigation strategy focused on minimizing the generation of iron sulfide and other corrosion byproducts is a Crystaphase particle filtration system immediately upstream of the catalyst bed. Crystaphase designs filtration systems which will remove particles before the catalyst bed while minimizing pressure drop build.

Illustrated in Figure 6 is an example of iron fouling where pressure drop was neither an issue nor an indicator. Instead, this Gulf Coast refiner was experiencing catalyst deactivation within six weeks of startup. This is a costly problem, as the catalyst in question was made from platinum.

The refiner originally planned to perform a hot-hydrogen strip, then reactivate the catalyst to run for additional 13-month cycles. However, when it came time for the strip, they discovered iron deposits binding with and killing the catalyst. Instead of reactivating, they had to vacuum out the reactor, haul the material to a metal reclaimer to separate the iron from the poisoned catalyst, then install a new catalyst load.

Crystaphase recommended adding filtration to the catalyst bed in order to remove the iron from the feed, mitigating the loss of activity and enabling regeneration of the catalyst. At the next scheduled changeout—and for the first time since the unit had been in operation—the refiner found no iron deposits and was able to regenerate the catalyst. This operational change saved the refinery $3,000 per day in lost catalyst and operating capability.

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Figure 6. Reformer catalyst before and after Cystaphase CatTrap filtration system installed.

Corrosion in higher temperature zones can lead to the same secondary impact of fouling at reactor beds. As temperatures increase, amine-HCl salt corrosion ceases to be a concern. In its place, corrosion due to naphthenic acids and sulfur compounds results in release of iron that will flow downstream and deposit in reactor beds. Naphthenic acids are high molecular weight carboxylic acids that have been shown to corrode tower internals, piping, drums, and heat transfer equipment at temperatures as low as 400°F. The iron liberated from this corrosion mechanism will be soluble iron naphthenate, which flows downstream and will react spontaneously in the reactor to form iron sulfide. Like naphthenic acids, sulfur compounds can also corrode refining equipment at high temperatures, producing iron sulfide scale that can foul reactor beds. Crude oils high in TAN and high in sulfur are frequently discounted compared to benchmark crudes. For both naphthenic acid and sulfur corrosion concerns, profitability can be limited when feedstock limits on TAN and sulfur are required.

Mitigating against high temperature corrosion while processing high TAN or high sulfur crudes can be accomplished in the long term by capital investment to upgrade metallurgies to corrosion-resistant alloys. In the short term, high temperature corrosion inhibitors have proven to be a reliable means to manage operation while processing these attractively priced crude oils. Baker Hughes SMARTGUARD™ high temperature corrosion control program offers a suite of corrosion inhibitors and application monitoring capabilities that control high temperature corrosion and unlock the refinery’s profit potential. An inhibitor program application shows a clear benefit by reducing corrosion rates by more than 80%, as shown in Figure 7. Reactor pressure drop benefits from high temperature inhibitor treatments were also demonstrated (Figure 8), as the reduction in corrosion products achieved by controlling corrosion resulted in a lower rate of pressure drop increase in the reactor beds.

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Figure 7. High temperature corrosion inhibitor provides > 80% reduction in metal loss.

Figure 8. Pressure drop trend data.

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In a characteristic example, one gulf coast refiner had experienced pressure drop issues for years. A filtration system installed above the main catalyst bed had little effect, and the reactor was unable to go beyond a 24-month production cycle. Pressure drop limited cycle time to as little as six months.

Crystaphase identified the offending problem as a high TAN, iron naphthenates issue with the ability to evade capture until precipitation as iron sulfide in the catalyst bed. Iron naphthenates are formed in situ by the following mechanism7:

Reaction 1. Corrosion of iron by organic acids, likely occurring on the walls of upstream piping and equipment

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Scanning electron microscopy (SEM) confirmed the precipitation problem, as shown in Figure 9.

Installing a system employing ActiPhase® and CatTrap® technologies enabled the unit to achieve a 20-month production cycle with no increase in pressure drop (Figure 10). The improved cycle lengths have resulted in a profitability increase of over $25,000 per day.

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Figure 9. Precipitated iron sulfide generated from iron naphthenates.

Figure 10. CFHT processing high-TAN VGO feed stock. Crystaphase increased cycles more than threefold following sample analysis and optimization.

Utilizing these tools to control and address corrosion issues, large increases in cycle lengths can be realized. Simultaneously mitigating the source of the foulant, controlling the size of the particles, and optimizing the filtration for the prepared feedstock removes costly bottlenecks and shutdowns. By leveraging the advantages of these approaches, refiners are free to work with catalyst vendors to drive their cycle lengths with activity design. In this way, feedstock preparation can increase profitability on the order of millions of dollars per year.

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Fouling Mitigation

When addressing hydraulic limitations (or pressure drop issues), a number of variables come into play when identifying the root cause of the problem. The most common is particle deposition in the catalyst bed, which is not something catalyst is designed to handle well. Additionally, there are special cases where this particle accrual can occur upstream of the reactor, wreaking havoc on the thermal and hydraulic efficiency of heat exchangers and furnaces alike. Most polymerization products react in this portion of the reactor and tend either to require shutdown due to hydraulic limitation in the heater or exchanger, or to build to catastrophic levels. At this point, flow conditions or processing conditions cause a sloughing event, dumping copious quantities of particles directly into the upstream reactor, moving the hydraulic problem from the heating train into the reactor bed. Even the most advanced filtration solutions can have trouble dealing with these situations.

An engineer might look at this problem in two different ways, either as a particle infiltration problem to be solved with particle removal, or as an antifoulant problem to be solved with chemicals and additives. Both options should be examined in parallel so the designed systems and programs complement one another to reach targeted run lengths.

Antifoulant treatment programs will inhibit the formation, growth, and deposition of offending materials in refinery processes. Fouling control programs reduce the rate of fouling in refinery operating systems. LIFESPAN™ fouling control additives include surfactants that disperse organic and inorganic particulates, and polymerization inhibitors that reduce formation of high molecular weight polymers and gums. Dispersant and asphaltene stabilizer antifoulants reduce agglomeration and particle size growth to keep the particles suspended in the process stream. Polymerization inhibitors act to terminate free radical or condensation polymerization reactions, thereby reducing formation of insoluble organic particulates. These programs may consist of multiple additives which are selected based on the deposition mechanism(s) contributing to the problem.

LIFESPAN antifoulant programs have been highly successful in controlling fouling in hydrotreating units, not only preheat exchangers, but also in guard beds and reactor beds.5 In hydrotreating units, deposits are typically composed of inorganics, such as iron sulfide, and polymerized organic particles formed of reactive species in the feed. When fouling control programs are used, the ability of CatTrap technology to remove poisons and dissolved impurities is enhanced because the particles are restricted from growing beyond the capability of reactor filtration systems. In one refinery study at a naphtha hydrotreating unit, the particle size of iron sulfide was measured at three locations of the feed system, as shown in Figure 11. By controlling the particle size in a predictable way, filtration systems can be optimized to match the expected behavior.

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Figure 11. Effects of LIFESPAN antifoulant program to control particle growth of iron species.

A distillate hydrotreating unit at a major integrated refinery was experiencing rapid fouling in the feed-effluent exchangers and guard bed. Analyses of the various feeds being processed revealed the major problem was a light coker gas oil (LCGO) coming to the unit via a blanketed intermediate storage tank. A LIFESPAN fouling control program was implemented after a unit shut down for cleaning. A polymer inhibitor was injected into the hot LCGO prior to the intermediate storage tank and a dispersant antifoulant was injected into the combined feed to the unit to control inorganic and organic particle growth. Fouling of the unit effectively ceased once the treatment program commenced. Figure 12 shows flow corrected pressure drop across the guard bed before and with treatment to control the rate of deposition.

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Figure 12. Guard bed pressure drop - distillate hydro-desulfurization unit fouling

Different feedstocks present different challenges. In another case involving a cracked naphtha feedstock, the challenges had become so severe that cycle lengths had become limited to 93 and 74 days before engineers began work with Crystaphase to design a filtration system for the vessel. Prior to Crystaphase, this unit was using a standardized system of medallions, macroporous lobes, and ring grading, a system which was ill-suited to the feedstock it was facing.

Crystaphase was able to assess the problems facing the unit and develop a cycle-extending solution for the refiner. The results are depicted in Figure 13. The initial installation quadrupled the cycle, reaching 320 days on oil before shutdown. Gathering valuable samples from the unit, Crystaphase was able to determine an additional component in the fouling process, polymer breakthrough, which was bypassing the CatTrap system and then reacting and accumulating on the catalyst bed. Crystaphase corrected this issue by implementing a complete filtration system using a combination of CatTrap and ActiPhase DOS, enabling the capture of reactive polymerization products prior to deposition of the catalyst bed. Typical carbonaceous materials found in these filtration systems are shown in Figure14. This solution further enhanced the Crystaphase filtration system, enabling a cycle of over 500 days. Further optimizations to this system have been pursued and installed to meet a cycle requirement of 24 months. Table 1 depicts the enhanced capture of carbon and polymer conversion ActiPhase solutions are able to offer. Furthermore, a dispersing program such as LIFESPAN has been recommended to the refiner to keep the heat exchangers and CatTrap/ActiPhase system performing in top condition. The combined profitability impact on the hydrotreater alone is over $10,000 per day.

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Figure13. NHT processing cracked Naphtha Feed stock. Crystaphase increased cycles nearly eightfold following sample analysis and optimization.

Figure14. Carbonaceous fouling extracted from cracked naphtha process.

Table 1. Improved carbon capture rate from implementing active filtration systems.

CatTrap Only ActiPhase DOS

Carbon Wt % 5.1 55.5

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There are many refiners today dealing with high fouling rates and incredibly large particles due to polymerization in the heating train. By developing a plan with experts in feedstock preparation, it is possible to develop complementary solutions which will greatly enhance the fouling resistance of hydrotreaters. Simultaneously improving heat exchanger and furnace performance, controlling the size of the organic foulants, and proactively employing active filtration will minimize upsets, skims, and opportunity losses. This clears the path of all obstacles to cycle length except catalytic activity, which allows the refiner to plan for improved profitability.

Poison Control

This same synergy can also be demonstrated in the ability to deal with poisons. As an exemplary case, we will review silicon’s role and the best plan of attack to deal with that poison.

When dealing with activity limitations on the catalyst bed there are many detrimental contributors to this problem. These poisons tend to show up predominantly as soluble components of the feedstock. Poisons can be defined as chemical species with a strong gradient for chemical adsorption or absorption on catalyst sites, blocking this valuable resource for use in the desired chemistry of the vessel. In large part, the poison depends on the catalyst being used, the pressure and temperature of the vessel, and the preferred chemical reaction taking place. In the case of hydrotreating, sulfur and nitrogen species react with the hydrogen present and are released from the oil as ammonia or hydrogen sulfide. While the hydrotreating catalyst performs exceedingly well at this conversion, it also performs nefariously well at poison collection. Poisons in these cases are numerous, but can include components like silicon (from antifoam siloxanes), organometallics (nickel and vanadium species), metalloids (arsenic species), and even reactive, carbonaceous materials. If these poisons are allowed to reach the catalyst bed, accelerated reductions in catalyst reactivity are experienced and short cycles ensue.

The most common hydroprocessing poison in naphtha hydrotreating is silicone, typically quantified as wt% of elemental silicon on the catalyst. Though naturally occurring in many crudes, the primary source of silicone is poly-dimethyl siloxane (PDMS) additives used to control foam formation in coking operations. While vital to good coker operations, these compounds present a serious threat to hydrotreater catalysts. Once broken down, the silicone polymers will readily attach and block active sites on the catalyst, eventually threatening breakthrough to further impact reformer operations as well.

Newly developed antifoams reduce the amount of silicon necessary to control foaming in delayed coker operations, thereby reducing the rate of catalyst contamination in hydrotreating units. The industry has been gradually changing from shorter chain-length PDMS to higher molecular weight molecules. The higher molecular weight PDMS are more thermally stable and provide longer lasting foam control which reduces antifoam treatment rates. Table 2 shows the change in silicon concentration of the coker products when a refinery changed from a 60,000 cSt PDMS product to a higher molecular weight,

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600,000 cSt product. On average, a 50% to 60% reduction in silicon contamination of the coker products is found when upgrading to the higher viscosity PDMS.

Table 2. Silicon in cracked products – plant 1.

Naphtha LCGO HCGO Si (ppm) using 60,000 cSt Antifoam 34.0 7.9 7.3 Si (ppm) using 600,000 cSt Antifoam 12.3 3.2 2.7 Si Reduction 59 % 59 % 63 %

Baker Hughes has developed the FOAMSTOP™Low Catalyst Impact (LCI) series of products6 , which feature a modified siloxane molecule. These products control foaming with less overall silicon, therefore contamination of coker products is substantially reduced when compared to even the 600,000 cSt antifoam as shown in Table 3.

Table 3. Silicon in cracked products - plant 2.

Naphtha LCGO HCGO Si (ppm) using 600,000 cSt Antifoam 33.8 28.7 1.8 Si (ppm) using FOAMSTOP LCI Antifoam 8.2 3.2 0.9 Si Reduction 75 % 88 % 50 %

These state of the art antifoam additives reduce the silicon loading of the cracked products which must be hydrotreated before they can be blended to final on-road fuel. Reduction of the overall concentration of silicon in the cracked products allows the hydrotreater to operate longer before catalyst changes are required. When coupled with Crystaphase MC Si silicon adsorbent, the reactor can run to its planned activity outage, as opposed to being subject to early catalyst change-outs.

After solving pressure drop issues in naphtha hydrotreaters, the second most common cycle limitation is silicon breakthrough requiring a full catalyst change and lost throughput. To further extend that approach, Crystaphase has also built systems that perform a simultaneous function of filtration and poison control using silicone-adsorbing ActiPhase, as shown in

Table 4. By moving some poison capture into the filtration design, poison control depths can be reduced and more flexibility can be provided to engineers and catalyst vendors to reach other operational goals, such as improved LHSV and operational control.

Table 4. Capture of silicone in ActiPhase filtration systems and Crystaphase poison control.

CatTrap ActiPhase Si MC Si 2.5

Silicon Wt % 0.64 6.6 22.1

By using state of the art FOAMSTOP LCI antifoam products in concert with ActiPhase high capacity silicone adsorbent, the impact of silicon on the hydrotreating catalyst is

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minimized. With this poison controlled, the refiner can now allocate more space to the vessel’s primary function, nitrogen and sulfur removal.

Summary

The primary obstacles to turning around on schedule can be characterized in terms of managing particles and poisons in hydrotreater feedstocks. Gaining control of cycle lengths and maximizing the performance of valuable refinery assets is a matter of dealing with these contaminants both inside and upstream of the reactor.

By implementing a chemical treatment program that anticipates support from a complementary in-reactor purification system—and vice-versa—a refiner can amplify the benefits of each. If suffering from hydraulic limitations, whether from organic or corrosion foulant, consider not only options which protect the catalyst, but also chemical treatment options supported by a complementary filtration system. If suffering from activity loss due to poisons, make sure all options to reduce poisons upstream are considered while also maximizing your ability to capture poisons before the hydrotreating catalyst.

With a feedstock properly prepared for nitrogen and sulfur removal, the refiner operates assets on their designed timeline. A holistic approach to feedstock preparation entails both the chemicals treatments and reactor purification systems. The resulting performance improvement affects operations across the entire refinery, with the potential to boost profitability by multiple factors.

Finally, it is critically important for refiners to coordinate strategies between their suppliers in order to capture the maximum benefits of a multi-faceted solution. Applying this concept and using the tools outlined in this paper can mitigate bottlenecks and allow the refiner to prepare, produce, and profit.

References

1. S. Cornelius, D. Jackson, D. Longtin, ”Assault on Salt”, Hydrocarbon Engineering, September, 2012

2. G. Hoffman and D. Longtin, “Innovation Leads to New Solids Management Technology”, AFPM Annual Meeting AM-14-33, Orlando, FL, March 2014

3. J. Weers and J. Nguyen, “A New Metals Removal Process for Doba Crude Oil”, ERTC 9th Annual Meeting, November, 2004

4. R. Rechtien and G. Duggan, “Identifying the Impacts of Amine Contamination on Crude Units”, NACE Corrosion 2006, paper number 06581

5. B. Wright and G. Medine, “Distillate Hydrotreater Fouling”, Presented at AIChE Spring Meeting, April, 2008

6. Proceedings from AFPM Q&A Transcript, Fall Q&A Meeting, October, 2016

7. U. Josh and A. Schneider, “Mitigating iron foulants in refinery processes”, ARTC

19th Annual Meeting, April, 2016