September 2021

Special Focus: Refining Technology

HPNA woes—A thing of the past

2020 can be viewed as one the most challenging periods in the history of the oil and gas sector.

Singh, S., Clarke, I., Honeywell UOP; Önder, E. R., Tüpraş

2020 can be viewed as one the most challenging periods in the history of the oil and gas sector. Unprecedented quarantines and lockdowns imposed due to the COVID-19 pandemic had a dwindling effect on fuel demand and oil prices. Refineries across the world were either shut down or had to operate at their turndown capacities. These unforeseen developments exerted significant pressure on refining volumes and margins, forcing refiners to improvise continuously to survive in this challenging market.

Hydrocracking units play an important role in converting the bottom of the barrel, waste streams and renewable feedstocks into high-value fuels, lubricants and chemicals to boost the value of refinery product slate. However, without adequate means of managing heavy poly nuclear aromatics (HPNAs), most operators would struggle to process these challenging refractory feedstocks, especially in high-conversion units.

Adapting to cyclical market demands, new product specifications and increasingly stringent environment regulations are nothing new for refiners, but they now need to act swiftly and conduct thorough evaluations of their assets to remain competitive.

Refiners are increasingly processing heavier feeds, such as heavy coker gasoil, heavy vacuum gasoil and deasphalted oil, in their hydrocracker units. This is due to the industry trend for increased fuel oil conversion, particularly since the rollout of the latest International Maritime Organization (IMO) regulations. However, these factors can cause a host of operational issues, such as fouling of both equipment and catalysts that can curtail the cycle length.

The authors’ company has been successfully tackling these reliability issues and offers proven catalytic and equipment solutions that ensure uninterrupted cycle runs. Each solution is tailored around the unique features of unit configuration to harness its full potential. This proven approach reduces both the revamp scope and duration that, in most cases, ensures a swift budgetary approval and unit turnaround to implement revamp modifications. Timely commissioning of revamp is critical to the success of these projects and puts refiners in a unique position to make the most from evolving market needs.

HPNA formation, challenges and mitigation options

Straight-run vacuum gasoil (VGO) feeds naturally contain 2–6 ringed polynuclear aromatic (PNA) compounds. The concentration of these PNAs—and, therefore, their tendency to form HPNAs—increases with the increase in the VGO end point and type. For example, the HPNA formation potential of straight-run HVGO with an end point of 600°C is significantly lower compared to heavy coker gasoil or any other residue processed stream with the same end point.

As the feed passes through the hydrocracking reactors, a combination of condensation and side-chain cyclization reactions form HPNAs. These compounds, formed by undesired side reactions, are stable and virtually impossible to crack. HPNAs are fused polycyclic aromatic compounds with more than seven rings [e.g., coronenes (C24H12) and ovalenes (C32H14)]. The rate of HPNA formation increases at low hydrogen partial pressures, high conversion and at high temperatures, with the bulk of these compounds ending up in the recycle oil due to their high boiling points. HPNA build-up affects both the unit performance and reliability. Some of the key detrimental effects include:

  • Hydrogen-deficient, high-molecular weight species increase the rate of coke formation, which deactivates the catalyst and shortens the cycle length. HPNA formation will depend on several factors (hydrogen partial pressure, catalyst type, etc.) but experience suggests that the rate of deactivation increases exponentially as coronenes in recycle oil reaches 1,000 ppm.
  • As concentration of HPNAs and other difficult-to-crack compounds build up in recycle oil, reactor temperatures are raised further to achieve the target conversion. The increase in reactor temperatures often shifts the selectivity towards lighter products, leading to a decline in valuable product yields.
  • HPNA buildup increases the risk of fouling in heat exchangers, leading to increased heater duty and high pressure drop across the reactor circuit. As the reactor effluent cools, HPNAs drop out of the solution due to their limited solubility and deposit in the colder exchangers in the reactor effluent train—particularly in the air cooler and cold separators—causing plugging of tubes and coalescer pads. As their concentration increases, they will also begin to deposit in warmer upstream exchangers. In some instances, plugging in unconverted oil (UCO) rundown circuits has also been reported, either due to excessive cooling or high HPNA concentration. Once this happens, it becomes virtually impossible to convert or remove these HPNA deposits online, eventually leading to unplanned unit shutdown.

A change in UCO color is usually one of the first signs of HPNA build-up. The color changes progressively from white to yellow, then to orange and red as the HPNA concentration increases. FIG. 1 highlights the key areas of concern as HPNAs build up in the unit.

FIG. 1. Effects of HPNA buildup.

To address the fouling concerns, almost all high-conversion hydrocrackers are now designed with a hot high-pressure separator (HHPS) at a point between the last cracking reactor outlet and the cold high-pressure separator. An HHPS typically operates in a temperature range of 260°C (500°F)–315°C (600°F), which is sufficiently high to keep the HPNAs in liquid stream that bypasses the colder sections of effluent heat exchange and prevent solid precipitation. While the hot separator design element prevents exchanger fouling, HPNAs are still present in the UCO and will build up in the recycle stream, causing significant catalyst deactivation.

It is still necessary to physically remove the HPNAs from the hydrocracker; this is usually accomplished by removing a small portion of the UCO as a purge stream. The bleed stream from the hydrocracker can range anywhere from 3%–10%. If a refinery does not have a fuel oil system or a fluid catalytic cracking unit (FCCU), this option can lead to indirect recycling of HPNAs, further compounding the issues. It also offers limited flexibility to withstand changes in feed quality and catalyst aging with time.

Often, HPNA formation increases exponentially and refiners are forced to increase the UCO bleed rate to sustain the unit operation. The resultant decrease in conversion and middle distillate (MD) yields can cost a refiner with an average size HCU (50,000 bpd or 8,000 m3/d) more than $10 MM/yr of lost product opportunity. FIG. 2 shows a typical conversion vs. HPNA trend for units without any active HPNA management.

FIG. 2. Typical unit conversion trend to limit HPNA buildup.

Over the years, the authors’ company has developed several approaches to effectively manage and limit the HPNA formation in hydrocracker units. These include both improvements to catalyst systems for better HPNA conversion, as well as new equipment innovations to aid in HPNA removal. Catalytic solutions mainly focus on saturating the starting blocks of HPNA, i.e., feed refractory species or PNAs to prevent sedimentation in both reactor and product sections. This is particularly a concern in high-conversion recycle units processing VGO with a high end point (> 600°C) and feed blends comprised of thermally cracked gasoil streams from coker, visbreaker, and FCC units and other residue derived feedstocks. The inclusion of proprietary high-activity and deep hydrogenation catalystsa,b,c can help mitigate associated processing challenges with these difficult feedstocks.

Catalytic solutions

The authors’ company brings a unified approach to cater to diverse hydroprocessing configurations and technologies offering a vast choice of solutions for both hydrotreating and hydrocracking catalysts. The company’s hydroprocessing catalyst portfoliod comprises of large variety of catalysts specifically designed to meet diverse and unique refiner needs around the globe. A wide range of commercially proven catalysts and technical support throughout the catalyst cycle help operators to continuously optimize unit performance, improve reliability and meet challenging market needs. For units struggling with HPNA issues, an ideal combination is usually a high-activity pre-treat catalyst with a high-saturation cracking catalyst.

The use of advanced analytical techniques like a Titan 80-300 keV Super-X aberration-corrected electron microscope allows the company’s scientists to better understand interactions between the active metal and the catalyst support. These and other characterization techniques have proved to be a game-changer and helped the authors’ company to swiftly commercialize catalystse,f specifically designed to deliver improved hydrogenation. The company’s catalysts can be used alone or stacked together depending on the unit configuration, operating conditions and cycle length. These catalysts offer excellent hydrogenation that can either be utilized for converting or saturating HPNAs or for boosting UCO VI for lube oil production. Catalyst activity is ideally suited for maximum distillate production in both single- and two-stage units.

Similarly, proprietary high-activity treating catalystsg,h with enhanced metal formulation and support have proven experience in handling heavy refractory feeds. These catalysts offer high start-of-run (SOR) activity that is suited to saturate PNA, and excellent stability that delays the approach to aromatic saturation equilibrium and allows consistent operation at low nitrogen slips, all of which drastically reduce the HPNA make.

A novel unsupported catalystc delivers step out performance especially for refiners struggling with catalyst bed volume limitations. An advanced characterization of feedstocks and products is applied to elucidate the catalysis kinetics and determine the most suitable location for the catalyst layer(s)c in the right quantity. Performance testing results indicate increased hydrotreating activity in terms of both hydrodesulfurization (HDS) and hydrodenitrogenation (HDN) mainly due to saturation of the least reactive species like dimethyldibenzothiophenes and dimethylcarbazoles. Resultant activity improvements translate to reduced bed volumes, thereby saving the undesired capital expenditure associated with new reactor installation to meet the elevated severity at low SOR temperatures.

In commercial applications, the novel unsupported catalystc is loaded in combination with conventional, high-performance catalystsg,h to debottleneck activity, and improve reliability and product quality constraints.

Equipment solutions

While the catalytic solutions described here can help reduce the HPNA make, this is not enough to guarantee a constant low HPNA make throughout the catalyst cycle. Irrespective of the unit configuration, fluctuations in unit feed quality and the gradual fouling of catalyst hydrogenation function impact the ability of even the best hydrogenation catalysts to maintain a UCO HPNA concentration that is steady and within limits.

The exact timing and concentration at which HPNAs begin affecting unit performance may vary, but the associated economic losses are not trivial to justify living with them. Including an equipment solution, therefore, becomes imperative to overcome HPNA woes and allow the processing of opportunity feedstocks without having to bother about product yields and cycle length.

The authors’ company has commercially proven equipment solutions for HPNA separation and removal that caters to the diverse needs of both new and existing unit designs. These options can be either combined with the catalytic solutions or implemented alone as part of revamp to cost effectively mitigate HPNA reliability issues.

Solution 1 of FIG. 3 shows a recycle oil management systemi that utilizes activated carbon beds to adsorb HPNAs. It comprises of two single-bed vessels that operate as lead and lag beds with the flexibility to isolate and change the adsorbent bed as it gets saturated. The lead bed becomes the lag bed following the change out. The frequency of change out can vary from 6 mos–1 yr, depending on unit operating severity and catalyst system. This option offers a simplistic design that can be conveniently incorporated into the existing unit flow scheme with minimum downtime. This technologyi was commercialized in 1990 and has more than 10 units successfully operating across the globe.

FIG. 3. Authors’ company’s HPNA separation equipment options.

A product fractionator split-shell design (Solution 2) is considered the best option for new units where the main fractionator can be built with a split-shell to include the HPNA removal section within the same column. This patented fractionation scheme utilizes high boiling point of HPNA species, especially with > 11 rings to achieve the desired separation. All HPNAs get concentrated in the UCO with a purge rate as low as 0.5% of the fresh feed rate, thereby significantly reducing the HPNA content in recycle oil to the reactors. It requires no material handling and has a minimal footprint. Since its commercialization in 2008, more than 15 units with split-shell fractionator design for both single-stage and two-stage configurations have been licensed, with multiple in commercial operation.

The external HPNA stripper design (Solution 3) utilizes the same fractionation concept but employs a small external stripper connected to the main column instead. A small slip stream from the fractionator bottoms pump is routed to the HPNA stripper, where the target HPNA separation is achieved using superheated steam. Stripper overhead is routed to the main fractionator column to provide the necessary stripping, while the concentrated HPNA stream is withdrawn from the stripper bottoms.

The external HPNA stripper design is a good retrofit option with minimum changes to product fractionator operating conditions and design. Only a few pieces of new equipment, all of which are relatively small, makes this an ideal option for a modular offering. This further reduces the footprint, unit downtime and refiners work scope. The first unit was sold in 2016 and was commercialized in 2020. First-hand commissioning experience and the commercial performance details are covered in the subsequent case study.

With either solution, the refiner benefits from being able to maintain very high conversion throughout the catalyst cycle, maximizing carbon management. All equipment options offer significant economic incentives primarily due to a boost in middle distillate product yields, reduced unit conversion and the flexibility to process VGO with high end point. In most instances, these revamp options offer a very high return on investment (ROI), with a typical payback time of less than 1 yr for an average size HCU (50,000 bpd or 8,000 m3/d).


In response to the changing refining landscape, TÜPRAŞ (Türkiye Petrol Rafinerileri) was one of the few refiners in the European region that began evaluating the impact of IMO regulations on refinery profitability as early as 2009. Turkey relies heavily on imports for almost all its energy and fuel needs, as it lacks any hydrocarbons production facilities. It has a surplus of gasoline but is heavily dependent on diesel imports.

TÜPRAŞ could see the silver lining quite early and acted swiftly to upgrade the refinery configuration and take advantage of the declining fuel oil market. The shift in market dynamics provided a perfect opportunity to leverage the difference in fuel oil and diesel prices to justify the Residuum Upgrade Project (RUP), which aimed to increase the flexibility of the Izmit refinery (one of four TÜPRAŞ refineries) to process heavier and high-sulfur crude oils, together with the capability to convert 4.2 MMtpy of high-sulfur fuel oil to 3.5 MMtpy of valuable high-quality white products, such as diesel, jet fuel, gasoline and LPG conforming to Euro-5 specifications.

Based on its internal evaluation, TÜPRAŞ had clear aspirations to reduce its fuel oil production and chose one of the most common and proven refinery configurations for residue conversion: a delayed coking unit (DCU) with downstream hydrocracking and hydrotreating units for upgrading all coker products. This widely used option offers a reliable configuration with minimal risk at the lowest capital cost. However, the biggest challenge was to create an integrated hydroprocessing complex design that offered the desired degree of flexibility between the hydrocracking and hydrotreating units at optimum CAPEX and OPEX costs to keep the project economically viable.

Tailored integrated design

The authors’ company developed several potential configurations and analyzed the pros and cons to help TÜPRAŞ choose the most optimum solution. Each potential configuration included an analysis of resources requirements for both people and equipment, high-level performance projections, cost estimates and constructability rankings. This iterative process enabled the TÜPRAŞ team to refine objectives, understand the numbers in detail and provide feed definitions to optimize the cut point between straight-run VGO and coker feed to optimize unit sizes. The collaboration ultimately resulted in an ideal configuration to meet the project objectives. FIG. 4 shows the refinery location (left) and an aerial view (right) of the site.

FIG. 4. (Left) Location of TÜPRAŞ’ refineries, Turkey; (right) Aerial view of the RUP complex, Izmit refinery.

The selected design comprised of an integrated coker naphtha and distillate process unitj, with all product rundowns routed to a process unit fractionation sectionk. Key common high-pressure equipment, such as washwater pumps, make-up gas compressors and amine pumps, helped improve the integration and reduce costs without compromising the degree of flexibility. Extensive heat recovery between the units and common PSA for recovery of CLPS off-gases from the complex helped minimize the carbon footprint.

For the hydrocracking unit configuration, TÜPRAŞ chose a proprietary enhanced two-stage processl to minimize the impact of difficult feeds on the product yields. The unique flow scheme and the tailored catalyst system offered high middle distillate yields, while reducing energy, hydrogen consumption and other costs compared with competing technologies. A high-level flow scheme of the integrated hydroprocessing units is shown in FIG. 5.

FIG. 5. Integrated RUP hydroprocessing units flow schematic.

The RUP complex comprised the following main units: vacuum unit, delayed coker, integrated hydrocracker and hydrotreating units, hydrogen generation unit, two trains of sulfur recovery units, an amine regeneration and a sour water stripper unit as well as a new cogeneration unit (120 MW). The project was completed in ~4 yr at an estimated cost of $3.2 B, including utilities and tank farm area. All units were successfully commissioned by 3Q 2015.

The 50,000-bpd (8,000-m3/d) unitk was designed to process a 60:40 feed blend of HVGO/HCGO at 98 wt% conversion. An integrated hydroprocessing complex checkout was begun in July 2014 and the units were successfully commissioned in May 2015. A demonstration test run confirmed that the units are meeting or exceeding performance guarantees.

Technical support

The original unit design solely relied on the UCO purge and a customized catalyst system to prevent the HPNA buildup. It worked well with feeds similar to the design feed case. Encouraging test run results coupled with spare margin in unit hydraulics and hydrogen availability offered further potential to increase ROI. Within 4 mos of commissioning, capacity was gradually increased to 110% of design in continuous collaboration with the authors’ company’s technology services to harness the full potential of the unit. Catalyst performance, key unit variables and the health of key equipment were closely monitored to stay within the design limits. Changes to feed blend, both in terms of cracked to straight-run ratio and increase in HVGO/HCGO end points, were necessary to allow TÜPRAŞ to push the feed rate further and reduce the reliance on imported HVGO. Sustained operation at high capacity coupled with the processing of relatively heavier feed blends eventually increased the operating severity to a point where the design UCO bleed rate was no longer enough to purge the HPNAs from the system. UCO color turned from off-white to orange in a matter of days following the increase in HCGO end point by ~45°C.

Reducing the feed end point and conversion helped improve the situation but was obviously not the most optimum solution. Processing heavier feeds was essential to sustain the unit operation at 110% of design, but not at the cost of unit reliability and cycle length. The company performed several yield estimates at different conversion levels and feed rates for the revised feed definition. Each estimate included details on catalyst deactivation rates, products yield slate and UCO purge rate to develop a risk vs. profit metrics to help TÜPRAŞ make an informed decision. Eventually, operating the unitk at 110% design capacity at a slightly lower conversion (~95 wt%) was selected as the most cost-effective short-term solution. FIG. 6 shows the key differences between the design and actual feed properties at high capacity.

FIG. 6. Actual vs. design feed properties.

The next step was to devise a robust feed monitoring system to effectively analyze and limit the contaminants in the feed blend and UCO. Tracking these refractory and unusual species in thermally cracked feedstocks like HCGO is often a challenge, and bulk properties analysis is simply not enough. Over the years, the authors’ company has developed a number of analytical techniques for obtaining a detailed molecular compositional analysis of extremely complex heavy streams. These analyses identify feedstock compounds that are known to be precursors of catalyst coke and of 11+ ring HPNAs.

The two most frequently used and reliable analyses are high-performance liquid chromatography (HPLC) and fluorescence spectroscopy (FS). The HPLC test method harvests and quantifies the refractory species—especially pure ovalenes and coronenes—in both feeds and UCO, while FS reports HPNA types as a function of different wavelengths at which peak fluorescence intensity occurs. The higher the wavelength, the greater the number of rings. FS is usually the preferred test method for tracking HPNAs with 11+ rings.

The authors’ company provided the necessary training, lab equipment specifications and test methods to help TÜPRAŞ set up an in-house capability to perform quick analysis and make necessary adjustments to prevent HPNA buildup. Another change was to replace the ASTM D1160 distillation test method with SIMDIST D7169 to better control the feed tail end and minimize residue entrainment.

Simultaneously, process unitk feed and UCO samples were shipped to the authors’ company’s laboratories to develop a better understanding of the feed recalcitrant species using advanced characterization techniques. Detailed compositional analysis of these hydrocracker streams was then used to estimate the difficulty of feedstock processability using the authors’ company’s correlations to both develop catalytic solution for the next cycle and to optimize the unit operation for the existing cycle.

FIG. 7 shows how advanced characterization methods like high-resolution mass spectroscopy (HRMS) can be utilized to optimize unit operations by identifying the feed contaminants at a molecular level and reduce the potential for rapid catalyst deactivation. The four bars indicate the PNA/HPNA breakup by ring numbers. Red dots are the distillation end point of each of the feed blend components. The relative concentration of 5 and 7+ ring compounds or PNA precursors is much higher in HCGO, even though its end point is lower than the straight-run VGO.

FIG. 7. HPNA break-up for different feed types.

An increased proportion of these precursors in the feed eventually results in HPNA buildup in the unit at high conversion. These analyses were consistent with the authors’ company’s recommendations to either control the HCGO end point to operate the unit at design conversion or reduce the unit conversion to address HPNA buildup issues. It also serves as a reminder that feed bulk properties like distillation, API, etc., are insufficient to predict the HPNA precursors, particularly in thermally cracked feedstocks. Advanced feed characterization and improved in-house feed and UCO monitoring helped improved the unit reliability and achieve the guaranteed cycle. FIG. 8 shows the impact of HPNA buildup on unit conversion.

FIG. 8. Plot showing impact of HPNAs on unit conversion.

Addressing HPNA woes

The first catalyst cycle clearly exposed the vulnerabilities of high-conversion units without any active HPNA management solution to changes in the feed slate. Costs associated with reduction in MD yields and shorter cycle length were simply too high to justify living with HPNA woes for the next cycle. The authors’ company continued to work closely with TÜPRAŞ to develop a comprehensive HPNA mitigation solution based on its future needs. The primary objective was to consistently push the unit operating severity by processing HS feed blends with high EP (> 600°C) at 110% capacity at ≥ 98 wt% conversion. TÜPRAŞ also wanted to extend the catalyst length from 3 yr to 4 yr with > 80 wt% distillate yields without any HPNA buildup.

Equipment solution:

Different HPNA options, such as an activated carbon bed chamber, split-shell fractionator and SDA on HCGO stream, were reviewed with TÜPRAŞ. In 2016, the split-shell fractionator design and carbon beds for HPNA absorption were fully commercialized solutions. The standalone HPNA stripper design, though commercially unproven, met TÜPRAŞ’ needs and processing objectives. The risk in trying this option was low, as it was based on the split-shell fractionator working principle and offered the same separation efficiency but without any major modifications to the existing equipment.

The carbon beds option was also considered but rejected due to plot constraints and the associated recurring costs of adsorbent replacement. A standalone HPNA stripper was found to be the most economically attractive option, requiring no additional unit downtime to include the new equipment with the unit flow scheme. With the installation of an HPNA stripper, TÜPRAŞ could increase the unit conversion to 99.5 wt%, while processing high-end point (> 600°C) HVGO/HCGO feed. Project work commenced in January 2016 and the basic engineering design package was delivered within a couple of months.

Catalytic solution

Maximizing the middle distillate yields and flexibility to process opportunity feedstocks without any HPNA buildup was a key requirement to improve refinery margins. TÜPRAŞ had good commercial success with the typical low-activity and high-selectivity catalyst system designed specifically for a second-stage environment. However, catalytic activity was simply not enough to guarantee a low HPNA make with constant fluctuations in feed quality throughout the cycle. The knowledge gained from the unit operation, constraints and catalysts’ shortcomings were leveraged to develop a tailored catalytic solution specifically designed, keeping the following TÜPRAŞ needs in mind:

  • Ability to operate the unit at 110% design feed rate, while meeting desired cycle length of 48 mos
  • Flexibility to intermittently process heavy feed blends
  • Superior hydrogenation for HPNA conversion in Stage 2 environment
  • Flexibility to shift the conversion between the two stages with minimal impact on middle distillate yields
  • Ability to operate the unit at 99.5 wt% conversion with the HPNA stripper online
  • Improved product quality throughout the catalyst lifecycle.

High-activity treating catalyste,g with superior hydrogenation functionality were chosen to maximize the volume swell and HPNA conversion. A pilot plant (PP) test was performed with TÜPRAŞ feed and operating conditions to verify representations.

The process unitk was shut down in February for a scheduled turnaround and catalyst changeout, and was reloaded with the selected catalyst system and started up in May 2019. While all the tie-in connections for the HPNA side stripper were taken during the unit turnaround, the HPNA stripper could only be commissioned in September 2020 due to delays in mechanical completion.

The new catalyst system has now been online for more than 18 mos and has successfully met or exceeded all key processing objectives. Unlike the last cycle, the unit is consistently running at 110% design capacity at or above design conversion, with significantly reduced and steady HPNA make. High second-stage SOR activity and improved hydrogenation has allowed TÜPRAŞ to regularly process heavier feed. It is also now possible to swing the conversion between the two stages and balance the catalyst deactivation rates, especially while processing difficult feeds, without impacting MD selectivity.

The first plot on the left in FIG. 9 shows consistent high distillate yields, better than the previous catalyst system. The plot on the right in FIG. 9 shows the difference between the WABT of two catalyst systems. An SOR temperature of the catalyste was and continues to be about 30°C lower than the previous cycle. Improved activity has not only helped to reduce HPNA make, but offers the flexibility to regularly process heavier feeds without having to compromise on conversion.

FIG. 9. (Left) Distillate selectivity cycle comparison; (right) 2nd-stage catalyst activity cycle comparison.

Low SOR temperatures and higher bed exotherms in the second stage also reduced the fired heater duty by about 10%. The resultant spare margin provides further flexibility to increase the feed rate to second stage and therefore improve the middle distillate selectivity by reducing the conversion per pass, especially while processing difficult feed stocks.

Good and consistent catalyst performance prompted TÜPRAŞ to push the operating severity further both by increasing the feed end point and by increasing the HCGO in the feed blend. In the last cycle, processing such heavy feeds was unimaginable without having to reduce the unit conversion to keep recycle oil HPNAs below 200 ppm, especially at EOR conditions. This is now a thing of the past.

The plot on the left in FIG. 10 demonstrates superior hydrogenation performance of the catalyste that has kept the HPNA make consistently below 50 ppm while processing feeds with an EP > 600°C. With the reduction in refinery margins and the advent of IMO regulations, the new catalyst system has helped boost the overall revenue by operating the coker unit at higher capacity and increasing the feed end point by 20°C–30°C. The plot on the right in FIG. 10 shows the HPNA generation as a function of unit conversion. At SOR conditions, the HPNAs were in the range of 20 ppm–40 ppm at or above design conversion, as compared to 100 ppm–120 ppm HPNAs in the previous cycle.

FIG. 10. (Left) HPNA make vs. feed EP comparison; (right) HPNA make vs. conversion comparison.

The catalyst systemd continues to meet or exceed TÜPRAŞ’ goals, consistent with predicted performance. In addition to providing excellent catalyst activity and selectivity, the catalyst system has demonstrated good temperature stability and is on target to meet the desired lifecycle. These process improvements are proof of the successful application of the proprietary catalyste in a second-stage environment to reduce HPNA make without compromising middle distillate yields.

HPNA stripper commissioning

The majority of the equipment and piping installation work for the HPNA stripper project was performed with the unitk online. All tie-in points were identified during the project stage and taken during the turnaround to enable the HPNA stripper to go online when ready without hampering the unitk operation. These tie-in isolations also provide the flexibility to take the HPNA stripper offline for any maintenance, if required. Key HPNA stripper facts and figures are summarized here:

  • Total installed cost: ~ $5.5 MM
  • Simple design, no additional unit downtime required
  • Stripper size: 2-m ID × 9.1-m T/T (designed for enhanced two-stage processk,l feed rate of 9,200 m3/d)
  • Increased unit conversion by ~1.5 wt%
  • Reduced bleed rate by 75%
  • Unlocked potential to process heavy feeds and further increase profitability.

Following the mechanical completion, the HPNA stripper was taken online in September 2020 without any product slopping. Unit commissioning was quick and easy and involved two key steps:

  • Heating the steam lines and stripper using the existing silencer and jump over lines. Stripping steam to the fractionator columnk was then slowly diverted through the HPNA stripper.
  • Introducing the fractionator bottoms to the HPNA stripper and increasing the stripping steam superheat to achieve the desired stripping efficiency. The overhead vapor comprising mostly of steam was routed to the main fractionator column as stripping steam, while the HPNA stripper bottom product can either be routed to the coker feed tank or coke drums.

The normal and preferred routing is to the coke drums to destroy the bulk of the HPNA and reduce any potential recycle to the unitk.

Results and takeaway

The authors’ company was able to support the startup remotely due to ongoing COVID-19 travel restrictions at that time, relying on its process monitoring software solution to remotely monitor the startup operation and provide necessary recommendations. Despite local labor constraints and limited vendor support, the startup of the stripper took just 1.5 d, and the drop-in recycle oil HPNAs were evident from the first shift. FIG. 11 provides a high-level flow scheme of the external HPNA stripper and a site photo.

FIG. 11. (Left) Typical external HPNA stripper flow scheme; (right) HPNA stripper in operation.

Commissioning of the stripper improved recycle oil quality further and helped raise the unit conversion to 99.5%. Steady and low recycle oil HPNA concentration keeps the catalyst deactivation rate low, providing an opportunity to either extend the cycle or process more difficult feeds. The stripper design is also energy efficient, and the bulk of the energy used for superheating the steam is offset by a reduction in the fractionator charge heater duty.

FIG. 12 shows an improvement in the recycle oil quality before and after HPNA stripper commissioning. An immediate reduction in recycle oil HPNAs can be seen following the commissioning of the HPNA stripper. However, due to some operational issues with the stripping steam electrical super heater, achieving design conditions took slightly longer than expected. The first six recycle oil analyses correspond to a heater duty of 25%–50%, which translates to about 50% of the design superheat. Despite this, it was possible to reduce the HPNAs by approximately 40%, i.e., from 140 ppm to 90 ppm. The last two analyses correspond to HPNA stripper operation at design conditions with HPNA levels at just 40 ppm. The recycle oil color changed to bright yellow during the stabilization period.

FIG. 12. Improvement in recycle oil quality.

The HPNA stripper has now been online for more than 3 mos with the process unitk consistently operating close to full conversion with no signs of HPNA buildup. TABLE 1 summarizes the key benefits of a comprehensive HPNA mitigation solution implemented at the TÜPRAŞ enhanced two-stage unitl.

The external HPNA stripper commissioning at TÜPRAŞ marks the successful commercialization of this key revamp technology that is especially suited for high-conversion units processing difficult feedstocks. The tailored comprehensive solution has not only helped TÜPRAŞ achieve all its processing objectives but surpass them with continuous support from the authors’ company’s services. The unit is now consistently able to operate at 110% capacity while processing difficult feeds above design conversion and, more importantly, without any HPNA woes. Such HPNA management customized solutions can help refiners improve unit performance and profitability via increased conversion to high-value products, which in most cases help recover the cost of investment in a matter of months.

The pivotal role of a hydrocracking unit in a modern refinery hinges on its ability to reliably process a wide variety of feedstocks. Whether a refinery is looking for a novel catalyst solution that accounts for the complexities of a new and far-reaching goal or looking for a revamp solution to achieve specific targets, the authors’ company brings a unified approach through its vast lineup of hydroprocessing catalystsd and many decades of experience in hydrocracking technology. HP


a Honeywell UOP’s HYT-6219
b Honeywell UOP’s HYT-6319
c Honeywell UOP’s ULTIMet™
d Honeywell UOP’s Unity portfolio
e Honeywell UOP’s HC410LT
f Honeywell UOP’s HC620LT
g Honeywell UOP’s HYT-6219
h Honeywell UOP’s HYT-6319
i Honeywell UOP’s HPNA RM™
j Honeywell UOP’s Unionfining™
k Honeywell UOP’s Unicracking™ Process
l Honeywell UOP’s Enhanced Two Stage (E2S) Unicracking

The Authors

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