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)
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 worlds
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 Alons Big
Spring new hydrotreater yields world class performance with
an excellent economic advantage.
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 refinerys gasoline pool
to less than 300 ppm between 20042009 (Interim Case) and
thereafter the refinery had to meet EPAs ultimate
requirement of less than 30 ppm S (Ultimate Case). Typically,
the refinerys 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
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
S1,700 ppm S and achieve 90% sulfur reduction, to differ
capital expenditure and thus utilize the advantage of being a
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 worlds 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
The semi-regen reformer is the refinerys
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 +
Fig. 1 shows the olefins and sulfur
distribution in BSRs 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
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 units run
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.
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. 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 units
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
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
A common industry practice is to
design the units 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 refinerys PC asked that other
scenarios be considered in the design and equipment to
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
This revised basis increased sizes
for the HDS reactor and the units 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 refinerys 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
4) Around the clock technical support by technology licensor and BSR
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
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 competitors
units, achieving very low octane losses in a single-stage unit
when processing feed with high olefin and high sulfur,
nominally at 2,1002,400 ppm S, as shown in Fig. 7.
Fig. 7. Feed sulfur and
octane loss for
The refinery has experienced
enviable octane losses as low as 0.30.5. 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 0.70.8 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
1.41.5 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.
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
worlds shortest FCC main fractionator and restrictions
imposed by repurposing an idle 6 Mbpd NHT and reformer
compressor. Intelligent factors contributing to top of class
(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 refinerys PC to
guide the licensor and also for setting right design basis and
process direction and infusing new thinking for a more robust
Kirit Sanghavi is senior refinery
process engineering consultant at Alons 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
bachelors degree in chemical engineering from
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