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Achieve success in gasoline hydrotreating

09.01.2011  |  Sanghavi, K.,  Alon USA, Big Spring, TexasSchmidt, J. ,  Axens North America, Inc., Houston, Texas

Case history describes how to achieve superior performance during FCC gasoline hydrotreating

Keywords: [gasoline] [ultra-low sulfur gasoline] [hydrotreating] [sulfur] [catalyst] [hydrogen] [revamp] [clean fuels] [refining]

Superior FCC gasoline hydrotreating performance is achievable by selecting the optimal process scheme to minimize octane loss. Enlisting help from a refinery process consultant (PC) and technology licensor and collaborating early in the design stage, further ensures the success in determining the better design for the facility. Consequently, maintaining cost-effective solutions for a staged project investment and operating the world’s shortest FCC main fractionator subjected Alon Big Spring Refinery (BSR) with difficult project challenges. The roadmap used for a two-phase project and the lessons learned during Phase I (Interim Case) contributed to the successful implementation of Phase II (Ultimate Case). By knowing the key process and operational principals, the Alon’s Big Spring new hydrotreater yields world class performance with an excellent economic advantage.

Case history.

In early 2002, Alon, being an owner of a single refinery in Big Spring, Texas, was granted the status of a small refiner and was initially required to reduce sulfur (S) in refinery’s gasoline pool to less than 300 ppm between 2004–2009 (Interim Case) and thereafter the refinery had to meet EPA’s ultimate requirement of less than 30 ppm S (Ultimate Case). Typically, the refinery’s PC would initially lead all process aspects of such a major project such as determining the process design basis including, feed analysis, selecting processing scheme and/or process licensor and setting process scope. Early evaluations revealed that treating FCC gasoline would be the most optimal investment solution for the BSR. Of the five different processing schemes available at the time, the initial study narrowed down the list to three processes for further study. Then BSR acquired access to an idle 6,000 bpd (6 Mbpd) straight-run (SR) naphtha hydrotreater (NHT) complete with a recycle compressor from an adjacent idle reformer.

Consequently, the refinery management asked the PC these questions loaded with monumental challenges:
a) Can we relocate and revamp the acquired idle equipment sized for only 6 Mbpd of SR naphtha to a 13.8 Mbpd unit treating FCC gasoline rich with 36 vol% olefins?
b) Can we decrease FCC gasoline sulfur from 3,000 ppm to 30 ppm with enviably limited octane loss?
c) Can we do all this with an intermediate operation (Interim Case) with undercut FCC gasoline with 1,650 ppm S–1,700 ppm S and achieve 90% sulfur reduction, to differ capital expenditure and thus utilize the advantage of being a small refiner?

The PC believed that it can all be done by working with a lot of due diligence and fiduciary responsibility and selecting a game-changer FCC gasoline hydrotreating process as well as selective hydrodesulfurization catalyst. This task was even more difficult at BSR as:
• The refinery has the world’s shortest FCC main fractionator, at only 61 ft in height with 15 trays and two packed-bed sections. Thus, the FCC gasoline can have some heavy and tough-to-treat sulfur compounds from the light cycle oil (LCO).
•  The semi-regen reformer is the refinery’s sole source for hydrogen, where hydrogen purity varies from 88.6% at start of run to 74% at the end of the run. When reformer is down, hydrogen purity from purchased liquid hydrogen is 99.9%.

FCC hydrodesulfurization principles.

The key to treating FCC gasoline is in the ability to achieve the required sulfur reduction while maintaining octane levels. Octane loss results from hydrosaturation of olefins in the feed during hydrodesulfurization (HDS) of thiophenes and benzothiophenes in FCC gasoline in several steps. Both reactions occur in parallel and are shown here:

Olefin + Hydrogen r Paraffin

Example: 4-Methyl -2-pentene +H2 r 2-Methyl-pentane

Thiophene + Hydrogen r Butane + H2S

Fig. 1 shows the olefins and sulfur distribution in BSR’s FCC gasoline, with the highest amount of olefins and lowest sulfur occurring in the front end. Table 1 lists the octane numbers for olefins vs. resulting saturated paraffins. Fractionation upstream of the HDS section is an attractive first step to concentrate the olefin-rich light-cat gasoline (LCG) as a product and the sulfur-rich heavy-cat gasoline (HCG) for hydrodesulfurization (HDS).


  Fig. 1. Cumulative sulfur and olefins
  distribution vs. cut-end point.

BSR focused on several essential characteristics and challenges in selecting a successful process including:
• Minimize octane loss. Gasoline is hydrodesulfurized selectively and collateral damage that can occur through olefin saturation is minimized; accordingly, the scheme achieves the total lower octane loss.
• Minimize hydrogen consumption per barrel of feed was another important consideration for BSR. Olefin and aromatic preservation is essential; otherwise, a large amount of hydrogen would be used in saturating these compounds as compared to desulfurizing them.
• Retain excellent gasoline yield with no Rvp increases. This is vital for maximizing product. This is attainable with mild operating conditions that avoid cracking reactions,
• Maintain catalyst cycle length inline with the FCC turnaround schedule to avoid untimely blending issues due to off-spec FCC gasoline.
• Conserve total capital investment to cover both the Interim and Ultimate Case operations.

Detailed evaluation showed that for BSR, the selected gasoline hydrotreating processing scheme could meet all of the essential characteristics for both the Interim and Ultimate requirements. Fig. 2 outlines the basic process flow diagram.

  Fig. 2. Design flow scheme for the Interim and
  Ultimate FCC gasoline hydrotreating process.

Selective hydrogenation principles.

In the selected scheme, for the Ultimate Case, the feed would be pretreated in a selective hydrogenation unit (SHU) to convert lighter mercaptans and light sulfides to heavier sulfur species and also to saturate unstable dienes with no octane loss and minimal hydrogen consumption. Dienes, unless removed through saturation, would thermally decompose and agglomerate into a coke crust; thereby accelerating pressure drop buildup in the downstream HDS reactor. This would then shorten the unit’s run length.

Pretreated feed would then be fractionated in a splitter to remove about 29 vol% to 33 vol% of the feed as onspec LCG with less than 30 ppm sulfur and rich in high-octane olefins.

In most cases, the balance of the feed stream, HCG, would be hydrodesulfurized to reduce sulfur to below 30 ppm. LCG can be blended back with HCG. Otherwise, if a separate storage sphere is available, then the LCG can be segregated for blending flexibility. BSR chose the former option for LCG. Selectivity of the HDS catalyst to minimize octane saturation while treating heavier sulfur compounds in HCG would determine the total octane loss.

Challenges of the Interim Case.

With the idle 6,000 bpd-SR naphtha hydrotreater available as part of the FCC gasoline hydrotreater revamp, the first of many project challenges were presented. In combination with a minimal investment requirement for the Interim Case, the challenges increased significantly. A joint effort between BSR and licensor to develop a scheme was initiated to not only minimize investment but to meet the required HDS level with acceptable octane loss for both the Interim and Ultimate Cases.

Roadmaps. BSR developed roadmaps for both Interim and Ultimate Cases so that the least amount of equipment would be wasteful during the transfer from the Interim to Ultimate processing schemes. The licensor and BSR worked closely to arrive at the final Interim and Ultimate cases that encompassed the project challenges and requirements. For the Interim Case, a simpler initial flow scheme was developed to meet the immediate processing requirements, while simultaneously considering future requirements for the Ultimate Case. Despite the challenges presented, the design basis for each case was studied, and the technology licensor provided BSR with the final process design package. Both cases are shown in Fig. 3.

  Fig. 3. Final process design for BSR FCC gasoline revamp.

Lessons learned contributed to success. The Interim Operation during January 2004 to September 2009 was with full-range gasoline feed to the HDS reactor without pretreatment by the SHU. This operating mode provided an opportunity to study features needed for optimal Ultimate Operation. Fig. 4 shows that the pressure drop buildup in the HDS reactor during Interim Operation determined the unit’s run length. The high pressure drop would require frequent outages to skim the top-bed catalyst or a complete catalyst changeout. This was attributed to the absence of SHU pretreating and the protection it offers to the HDS reactor. The importance of installing an SHU reactor in the Ultimate Case was further strengthened. With a 30-wppm S gasoline pool requirement for the Ultimate Case, frequent unit downtime would jeopardize refinery economics/blending.

  Fig. 4. Pressure drop due to buildup in the
  HDS reactor due to lack of pretreating feed.

Analysis of crusts from the reactor revealed high coke buildup from thermal decomposition and agglomeration of unstable dienes in the feed, as shown in Fig. 5. Also, the catalyst deactivation rate was high during the Interim Operation. Analyses done on the spent catalysts revealed significant arsenic contamination which was linked to the feed. The lessons learned confirmed the need for feed filters, feed pretreatment with SHU and arsenic guard as a part of the grading system for the HDS reactor. Table 2 highlights the design feed characteristics for the Interim and Ultimate Cases.


  Fig. 5. Example of coke buildup on catalyst
  and the agglomeration from unstable dienes
  in feed.

BSR full-range FCC gasoline has a longer end-point tail than normal due to its very short FCC main column. This material was being undercut for the Interim Case operation. When compared to typical FCC naphtha feedstocks, the BSR feed proves to be one of the most difficult with high sulfur and olefin content. The concentration of dienes, as measured by MAV analysis, is exceptionally high and resulted in frequent pressure drop buildup events during the Interim Case.

Despite the difficult feedstock processed even during the Interim Case, the results met BSR product sulfur specification with excellent octane retention. Fig. 6 highlights the feed sulfur and (R+M)/2 octane loss during the Interim Case while meeting the 150 ppm S gasoline pool specification. The higher than design feed sulfur during the Interim Case was the result of processing higher end-point material, a step closer to the planned future ultimate case full-range feed. During this period, there were refinery hydrogen limitations. To conserve hydrogen in the diesel hydrotreater, LCO make was reduced by increasing the Interim Case gasoline end point.

  Fig. 6. Feed sulfur and octane loss during the
  Interim operating case while meeting
  150-ppm S in gasoline.

New thinking for the ultimate operation.

The ultra-low-sulfur gasoline (ULSG) requirement of 30-ppm sulfur in the gasoline pool was required by BSR starting after 2009. To meet the regulation, the Interim operation was now set to be revamped to the Ultimate operation. Not only was it necessary for the product sulfur to meet requirements but also 1) excellent octane retention to meet refinery economics and 2) a continuous catalyst cycle to meet the four-year FCC turnaround schedule. Also during the Interim operation, the BSR crude capacity increased thus raising the FCC gasoline rate. This required a new study to assess the impact from a higher feedrate to the HDS section, from the original Ultimate Case value of 8 Mbpd to 10.8 Mbpd.

A common industry practice is to design the unit’s reactor and heat transfer equipment including the heater(s) based on a) both reactors being at the start of the run (SOR) and/or both reactors being at the end of the run (EOR), in tandem, based on a four-year run length and b) the average hydrogen purity at 80.2% for BSR.

But during mid-2008 when restarting work for the Ultimate Case to increase operational flexibility and economic advantage, the refinery’s PC asked that other scenarios be considered in the design and equipment to cover:
a) Staggered reactor operation, with SHU reactor being at SOR while HDS reactor continues to run its course and vice versa, which de-couples the reactors
b) Unit flexibility to cover the expected 74%–88.6% hydrogen purity as the semi-regen reformer cycle progresses.

This revised basis increased sizes for the HDS reactor and the unit’s heat exchange equipment, as well as the sizes of the hydrogen heater and reactor effluent air-fin condenser, as shown in Table 3.


Also the refinery’s PC requested adding a macroporous trapping media for scales as a part of the HDS reactor grading system and using wedges and pins in place of traditional nuts and bolts for reactor internals, for easier installation and removal. Additionally, due to the arsenic measured on the catalyst during the Interim operation, a layer of arsenic trap was installed on top of the main HDS catalyst bed.

Another unit re-design included a continuous wash-water injection system due to the extra bay at the reactor effluent air-fin condensers, which were susceptible to chlorides in the makeup hydrogen. It also provided the option for a future water-wash column to minimize amine carryover.

Startup of ultimate operation.

In 2009, the BSR started the revamped Ultimate Case. The successful startup was contributed to several key factors:
1) The technology licensor and BSR inspectors performed a detailed conformance check of new vessels and trays. The SHU and HDS reactor internals were a focal point to ensure proper installation and levelness.
2) Safe loading of pre-sulfided, pre-activated catalyst, that does not require in-situ sulfiding or activation step, was supervised by catalysts provider/BSR verifying correct layers and loading densities.
3) Combined efforts in writing detailed start-up procedures and complete technical assistance during startup.
4) Around the clock technical support by technology licensor and BSR technical engineers.

Modified startup procedures were necessary as BSR did not have the typical feedstock (low olefinic naphtha) required for startup. A more difficult feedstock (the normal feedstock from FCC) was used. It required several startup issues to be resolved and incorporated into the final startup procedures. Additionally, BSR provided detailed training to operations, technical support and maintenance outlining the finalized procedures. Color-coded process flow diagrams for each step with associated operating parameters were used in training. The diagrams as part of the training contributed to the successful start-up.


Post startup audit and an outside review have revealed that this unit: 1) meets the BSR gasoline pool sulfur specifications of 30 ppm S and 2) has the best performance amongst other similar functional competitor’s units, achieving very low octane losses in a single-stage unit when processing feed with high olefin and high sulfur, nominally at 2,100–2,400 ppm S, as shown in Fig. 7.

  Fig. 7. Feed sulfur and octane loss for
  Ultimate Case.

The refinery has experienced enviable octane losses as low as 0.3–0.5. The refinery PC recently developed an excellent correlation for predicting octane losses as a function of feedrate and % HDS. This helps BSR manage octane losses in the range of 0.7–0.8 at normal feedrates with 2,300 ppm S and 97.2 % HDS. Most other typical FCC gasoline hydroprocesses treat feed with less than 1,300 ppm S and while % HDS is typically less severe, at less than 96.1%, and still experience octane losses commonly in the range of 1.4–1.5 or higher. On this basis, BSR has reached top of the class in FCC gasoline hydrotreating. Higher S feeds at BSR is directly due to processing of higher sulfur West Texas sour crude, providing BSR another great economic advantage over refineries processing sweet crudes.

The issue related to high HDS reactor pressure drops has been effectively resolved with installing feed filters, SHU and macroporous media to the HDS reactor grading system, as evidenced by pressure drop charts for both SHU and HDS reactor, as shown in Fig. 8 and Table 4. The HDS reactor is almost close to start of run temperature after one-half years of operation. The arsenic contamination of HDS reactor seems to be effectively resolved too.


  Fig. 8. Pressure drop across the HDS and SHU.

Successful project.

BSR FCC gasoline HDS unit is in a position to provide the refinery excellent economic advantage and leverage. It has demonstrated that it will not constrain refinery operations while processing lower-cost sour crude oils that in turn results in feeds with higher sulfur. This can be classed as an extraordinary achievement, especially for the world’s shortest FCC main fractionator and restrictions imposed by repurposing an idle 6 Mbpd NHT and reformer compressor. Intelligent factors contributing to top of class performance are:
(1) Superior processing scheme, based on saturation of unstable dienes in a selective hydrogenation unit and separation of the front-end FCC Gasoline as LCG before HCG is treated in reactor with selective HDS catalyst. This scheme would always assure process success in terms of superior octane retention and four-year unit run length.
(2) Early roadmaps prepared for both Interim and Ultimate Cases ensure minimal wastage of investment.
(3) Implementing lessons learned from the Interim Case into Ultimate Case design resolved issues related to high reactor pressure drops, catalyst activity, catalyst stability and catalyst arsenic contamination.
(4) Excellent capability of the refinery’s PC to guide the licensor and also for setting right design basis and process direction and infusing new thinking for a more robust unit. HP

The authors 

Kirit Sanghavi is senior refinery process engineering consultant at Alon’s Big Spring Refinery. He is responsible for the largest capital projects at this refinery. Previously, Mr. Sanghavi worked at Esso Chemical and Imperial Oil in Canada for 15 years and for four Engineering Companies in the US, UK and Canada during his career. He earned a bachelor’s degree in chemical engineering from London University. 

Jeff Schmidt is a senior technical service engineer for Axens North America, Inc. He has been with the company for the past five years and is responsible for start-up and technical support for Axens’ licensed units. Previous to Axens, he worked at UOP for five years. Mr. Schmidt holds a BS degree in mechanical engineering from the University of Wisconsin-Madison. 

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