Refiners are
actively developing new solutions to decarbonize
their finished products—such as transportation fuels or commodity chemicals—as
part of the energy transition. As a result, refiners are now exploring the co-feeding
of alternative feedstocks, including renewable and recyclable crude oils, as a
means of lowering the carbon footprint of their products. Given its inherent flexibility,
the fluid catalytic cracking (FCC) process has potential to lower the carbon
intensity of its products. However, these new feeds still present challenges,
such as additional contaminants, instability and miscibility issues, and
elevated acidity that can lead to a variety of operational challenges in an FCC
unit (FCCU). This article provides an overview of the different sustainable feedstocks
and possible solutions to overcome these challenges,
including feed pretreatment, operational adjustments and hardware design options.
In Europe, the decarbonization of the transportation
sector is driven in large part by the Renewable Energy Directive III (RED III),
which was officially adopted on October 18, 2023.1 RED III has
established two objectives, requiring European member states to adopt one of
these targets by 2030: (1) a reduction of greenhouse gas (GHG) intensity by
14.5% in transport, or (2) a 29% share of renewables in the total energy consumption
of transportation (FIG.
1). There are also minimum requirements for renewable fuels of non-biological
origin (RFNBO), established, at minimum, to be a goal of 1% by 2030.
Non-EU countries also have systems encouraging renewable
fuels use, such as the Renewable Fuel Standard (RFS) in the U.S., which incentivizes
U.S. refiners2 to blend renewables into transportation fuels or to obtain
renewable identification number (RIN) credits. Another example is the RenovaBio
policy in Brazil (adopted in December 2017) that aims to reduce the carbon
intensity of transportation fuels by the production, commercialization and use
of biofuels.
Potential refinery
insertion points for sustainable feedstocks. Typical
locations to add sustainable feeds in refineries are: (1) before the crude
distillation column without pretreatment, (2) in some of the processing units
with and without pretreatment, or (3) with the finished fuels after high-severity
upgrading. Refiners likely will see the most
benefit if the alternative feed is introduced into processing units such as the
FCCU, hydrotreater or hydrocracker. The insertion of sustainable feeds, such as
biocrude, at the distillation stage contains risk, as contaminants—mainly
oxygenates—could be distributed throughout the refinery. Coprocessing through an
FCCU offers the benefit of requiring no additional hydrogen (H2) and
minimal modifications to the refinery. The FCCU’s catalysts are continuously
regenerated by burning off coke in the regenerator before recirculating the
catalyst to the riser for further cracking reactions, and by breaking down
large molecules to more valuable products, such as gasoline and liquefied petroleum
gas (LPG) olefins. Hydroprocessing applications can pose higher risk compared
to FCC because reactors are loaded with fixed catalytic beds that can result in
metal deactivation and coking during the cycle length. Furthermore, FCCU catalysts
are highly tunable and can be designed to adjust yields, or to direct
deoxygenation pathways toward water (H2O) production to preserve
renewable carbon or toward carbon oxides to preserve hydrogen in products.
Sustainable feedstock options and their
associated challenges. Coprocessing through FCCUs offers a refinery flexibility
to introduce a variety of different sustainable feedstocks (FIG. 2) to create
lower-carbon-intensity fuels or chemicals, such as:
Pyoils
from waste plastics might contain significant amounts of chlorine [e.g., polyvinyl
chloride (PVC)], metals and oxygenates [e.g., polyethylene terephthalate (PET)
and polycarbonates]. The waxy/heavy fractions of plastic pyoils are typically
soluble in conventional vacuum gasoil (VGO) or resid feeds and are mainly composed with aliphatic compounds that can be easily
further cracked through FCCUs.
Plant-
and livestock-derived oils and fats—such as vegetable oils, animal fats and
used cooking oils—contain triglycerides and are soluble in conventional FCCU
feeds. They are typically paraffinic and can be easily cracked through FCCUs. While
they do not contain free H2O and have lower oxygen content compared
to other bio-oils, they might contain elevated levels of free fatty acids and
metal impurities, such as alkali and earth alkaline metals.
Biomass
wastes, like fast pyrolysis and HTL oils, have already demonstrated
crackability in FCCUs, but they have also introduced operational challenges in
FCC co-processing applications, including:
A
summary of these impurities and their impacts is detailed in TABLE 1.
The upgradability
of bio-oils also induces another challenge due to their oxygenate content. Huber and Corma3 described that the conversion of
oxygenates from biomass-derived feedstocks in the FCCU mainly occurs through five
different reactions: (1) dehydration reactions, (2) the cracking of large oxygenated
molecules to smaller molecules, (3) H2-producing reactions, (4) H2-consuming
reactions (H2 transfer), and (5) the production of larger molecules
by C–C bond-forming reactions (aldol condensation
or Diels-Alder reactions).
An example of this concept is the
crackability of glycerol toward
propylene. According to Eq. 1, the yield of propylene from glycerol in FCC can
be up to 77% (based on carbon), the balance being carbon dioxide (CO2)
and H2O. However, oxygen could be rejected as carbon monoxide (CO)
and H2O (Eq. 2), resulting in a maximum propylene yield of 66%. Oxygen
could also be rejected as H2O by dehydration reactions (Eq. 3), giving
an even lower maximum propylene yield of 33%:
9/7 C3H8O3
→ C3H6 + 6/7 CO2 + 15/7 H2O Carbon yield to propylene = 77% (1)
1.5 C3H8O3
→ C3H6 + 1.5 CO + 3 H2O Carbon yield to propylene = 66% (2)
3 C3H8O3
→ C3H6 + 6 C + 9 H2O Carbon yield to propylene = 33% (3)
Therefore,
to maximize propylene yield from glycerol, the dehydration, H2 forming
and H2 transfer reactions (H2
consuming) should be minimized by choosing proper catalyst designs and
operating conditions to maximize the reaction in Eq. 1.
Pretreatment of sustainable feedstocks. Sustainable
feedstocks—including both biogenic feedstocks and waste plastic-derived oils—differ
from crude oils due to the presence of oxygen and elevated levels of alkali
metals (e.g., Na, K), earth alkaline metals (e.g., Ca, Mg), chlorides and
phosphorus. Since these contaminants can cause catalyst deactivation and operational
issues, such as fouling or corrosion issues, it is recommended to reduce their
concentration prior to co-processing. At commercial scale, several pretreatment
processes exist to remove contaminants,4 such as:
Particles
and other solids in these sustainable feeds can lead to instability. Filtration
has been shown to remove particulates such as char and alkali metals. Degumming
is another technique that has demonstrated the ability to remove phospholipids
and trace metal ions from crude vegetable oils. H2O degumming is
effective for phospholipid removal, while alkali salts require acid degumming. FIG. 3 shows an
example of methane sulfonic acid (MSA) vs. citric acid for the degumming of
crude soybean oil, with MSA reducing the concentration of Ca, Mg and phosphorus.
Sustainable
feedstocks might also contain elevated chloride levels that should be minimized
prior to FCC introduction. Chemically, chlorides can result in the reactivation
of contaminant Ni deposited on equilibrium catalysts, leading to unwanted dehydrogenation
reactions (higher H2 make and delta coke). Operationally, since there is
often an excess of ammonia (NH3) from feed cracking, any additional chlorides
can lead to the formation of incremental ammonium chloride (NH4Cl) deposits
at the top of the main fractionator. As such, the introduction of chlorides
should be limited by feed management and careful catalyst selection to minimize
chlorides in FCCU catalysts, such as in-situ catalyst technology. Feed chlorides
can be reduced with adsorbents. Conventional alkali-promoted alumina will not
be efficient for dechlorinating waste-plastic pyoils. A chloride guard oriented
toward the removal of organic chlorides is preferred to maximize the
dechlorination process.
Crude
oils typically contain < 2% oxygen, while biogenic feedstocks can contain up
to 60% oxygen. The oxygen exists in a variety of chemical functional groups, including
carboxylic acids, alcohols, aldehydes, esters, sugars, furans, ethers and
hydroxyl groups. As noted previously, oxygen is undesirable in an FCCU, as it
can limit conversion of the intended reaction. Additionally, oxygen-containing
functional groups in bio-based feedstocks are hydrophilic and the presence of H2O
can cause significant problems, including the corrosion of metallurgy in
refinery processing units and piping. Finally, oxygen-containing groups are
also very reactive and can cause polymerization between molecules, forming
gums, acids and other impurities during storage.4 Mild
hydrotreatment, performed at low temperatures, is a treatment method to reduce
the oxygen-containing molecules in biocrudes. During such a mild hydrotreatment
step, deoxygenation reactions will take place (Eqs. 4–6):
R–CH2–CH2–COOH
→ R–CH=CH2 + CO + H2O (Decarbonylation) (4)
R–CH2–CH2–COOH
→ R–CH2–CH3 + CO2 (Decarboxylation) (5)
R–CH2–CH2–COOH
+ 3H2 → R–CH2–CH2–CH3
+ 2H2O (Hydrodeoxygenation) (6)
Catalytic
pyrolysis has also been used to stabilize the bio-oil before coprocessing
through the FCCU. In catalytic pyrolysis, oxygen is removed as H2O and
carbon oxides over a zeolite-based catalyst.
The importance of miscibility. Coprocessing
mixtures of fossil and biogenic feeds might result in blending issues. Lipids,
such as triglycerides and fatty acids, are miscible with fossil feeds and form stable
emulsions. However, for bio-oils, the presence of many oxygen-containing
molecules results in a polar phase immiscible with fossil feedstocks.4
Other factors—such as the density, viscosity, surface tension, heteroatom
distribution, refractive index and boiling point ranges—might limit feed miscibility,
as well.
The mild hydrotreatment of biocrudes could improve
miscibility through oxygen removal. However, the oxygen content at which
miscibility is no longer an issue could vary. Another solution is to use
separate injection nozzles at the bottom of the FCCU’s riser.5 This
allows using lower temperatures for the bio-oil (< 50°C) and higher
temperatures for the fossil oil (220°C–280°C) to reduce its viscosity and
achieve good atomization and dispersion through the feeding nozzle. The
preferred location for injection of the bio-oil is at the reactor bottom close
to the feed injection area, where thermal cracking of bio-oil can occur at high temperatures and high catalyst/oil ratios. This
thermal cracking transfers the large bio-oil molecules into smaller ones, which
can penetrate and react in the catalyst pores to lead to cracking reactions. Careful
consideration with the FCC technology licensor should be taken to determine the
type of oil, the ratio of the coprocessing oil to the primary feedstock and the
location of injection, since operating conditions, feed zone configuration and
coprocessing objectives will vary among FCCUs.
The licensor and testing arms of the FCC Alliancea,
in collaboration with a spray nozzle manufacturerb, have developed a
two-fluid atomizing nozzle specifically for injecting fast pyrolysis bio-oil (FPBO)
into the FCCU’s riser. Understanding the issues of immiscibility with petroleum
crude, along with the unique mixture of components of bio-oil that can
polymerize and cause plugging, and the role that both time and temperature can
play in increasing bio-oil viscosity, enables several features to be
incorporated in the injector’s design to ensure that refiners can co-process
bio-oils while also minimizing potential plugging or corrosion. A schematic of
the bio-oil injector is shown in FIG. 4.
To limit exposure of bio-oil to hot metal
surfaces inside the injector, the inner bio-oil lance is insulated. This layer
of insulation helps maintain bio-oil temperatures between 40°C and 70°C, which
is low enough to prevent bio-oil polymerization while providing a suitable
viscosity for good atomization. Dispersion gas—which can be steam or fuel gas—flows
in the annulus between the outside diameter of the insulation casing and the
inner diameter of the injector barrel before mixing with the bio-oil near the
injector tip. The mixing chamber is designed to minimize the contact time
between dispersion gas and the bio-oil, and does not require bio-oil to flow
through very small orifices to minimize the
tendency for plugging. The mixture of bio-oil and dispersion gas exits through
a slotted tip at the end of the injector where the spray pattern is formed. While
specifically designed for injecting fast-pyrolysis-type bio-oils, the injector
is flexible to atomize a wide variety of other hydrocarbon feedstocks. Operation of the injector is like typical petroleum
injectors, although several additional steps must be taken to minimize plugging
when bringing the injector into or out of service.
Since FPBOs tend to have elevated
concentrations of organic acids and chlorides, the injector is fabricated with
317L stainless-steel material. For feedstocks with high chloride content,
Hastelloy may be used for additional protection against pitting and corrosion
within the injector. Bio-oil storage and feed lines should also be a stainless-steel
material like 316L or 317L, as these have proven resistant to corrosion over
long-duration exposures to bio-oils.
Potential
corrosion impacts. As bio-oils and plastic pyrolysis oils present
higher chlorides, total acid numbers (TANs), H2O and oxygen, they are more prone to
cause corrosion. For bio-feedstocks, organic acid [carboxylic acid (RCOOH),
measured by TAN] and chlorides are the main corrosion-causing pollutants. The
long-chain organic acids that are usually present in these feedstocks are weak
acids that only slightly acidify free H2O in contact with the feedstock (e.g.,
storage system) at ambient temperature. The corrosion rate of carbon steel may
increase to moderate values if there is a continuous wetting of carbon-steel
surfaces with free H2O that dissolves organic acids. Conversely, if H2O content is minimized by free H2O separation, continuous wetting and
moderate corrosion by acidic H2O are no longer expected, and carbon steel-like
metallurgy is adapted for and operated (from the storage system) at ambient
temperature. Finally, stainless steel is preferred for bio-oil
storage and feed lines for an extended design life, and to avoid injector fouling
by corrosion products of carbon steel.
Organic acids can
also promote high-temperature corrosion similar to naphthenic acids in crude
distillation towers. Carbon steels and low-alloy steel materials are the first
to be impacted, but acids at high temperatures
might also attack non-molybdenum (Mo) stainless steels. The selection of SS
317L is a standard countermeasure to reduce high-temperature corrosion by
organic acids. It is recommended to select this grade for severe conditions
with high temperatures and high TANs.
After reaching
very high temperatures > 400°C in the FCCU’s reaction section, organic acids
are degraded to CO2 and do not promote high-temperature corrosion by
organic acids anymore. However, CO2 is a weak acid that promotes
further corrosion of carbon steel and low-alloy steel materials in the presence
of a humid or a free H2O phase (“wet CO2”) in downstream
equipment and piping. This corrosion is mainly
influenced by temperature, the presence of hydrogen sulfide (H2S),
H2O wetting of metallic surfaces and CO2 partial
pressure, and it may require the selection of a high-chromium corrosion-resistant
alloy (e.g., SS 316L) or the injection of corrosion inhibitors for the neutralization
of carbonic acid.
Chloride-containing
compounds may quickly form hydrogen chloride (HCl) in reaction sections, which
promotes the formation of hydrochloric acid (a strong acid) in the presence of
free H2O. Free H2O acidified by HCl dissolution and
without any neutralizing agent will be very corrosive to carbon steel and to
low-alloy steel materials (generalized corrosion), but also to stainless steels
(localized corrosion: pitting and stress corrosion cracking). The selection of
corrosion-resistant materials with significant chromium (resistance to
generalized corrosion) and significant nickel (resistance to localized
corrosion) is a standard countermeasure to mitigating corrosion by wet HCl. In the main fractionation overhead
system, corrosion by wet HCl is linked to an acidic pH. If the pH remains near
neutral or alkaline, then the impact of corrosion on the materials in place (carbon
steel) should remain limited, and the co-authors’ company recommends an
inhibitor injection package to be implemented in the H2O recycle line to the main fractionator air condenser.
There are different types of corrosion inhibitors:
anodic, cathodic, neutralizing and film forming, among others. The design of
the inhibitor solution depends on many factors, including the metallurgy and
operating conditions, and it should be performed in partnership with
experienced suppliers of inhibitor solutions.
NH4Cl salt deposition represents another phenomenon
that negatively impacts FCCUs, specifically in the mid-sections to upper
sections of the main fractionator column and overhead condensing system. The
formation of solid NH4Cl occurs when the salts “precipitate” from
the vapor phase, and the deposition takes place when the temperature at any
point drops below the salt’s dewpoint (at cold spots). Salts are deposited in
different zones (FIG. 5).
The main consequences of salt fouling are the plugging of trays, distributors
and products draws; the loss of fractionation efficiency between gasoline and light-cycle
oil (LCO); an impact on the pressure balance of the unit; and increased
corrosion, among others.
NH4Cl corrosion occurs primarily on cold spots
(like the pumparound return) inside the column. Once formed, the NH4Cl
salts are highly hygroscopic, and the result can be a very aggressive
under-deposit corrosion of the tower internals. For column internals, H2O
can be injected at the column top (using the reflux line at reduced capacity),
or salt dispersant can be injected in the reflux or the pumparound return. To
prevent salt deposition in the overhead system, washwater is recycled
continuously upstream of the fractionator air condenser. In addition, a
chloride-free catalyst is recommended to minimize the introduction of chlorides
from the catalyst through the FCCU, such as in-situ technology.
Takeaways. Coprocessing renewable or recycled oils offers refiners the
possibility to lower the carbon footprint of the transportation fuels or
chemicals they produce, and the FCCU stands out as an ideal process within a
refinery for upgrading these alternative feeds. However, these alternative
feedstocks introduce significant challenges in both catalyst performance and unit
operations. For instance, elevated metal levels in the feeds can lead to
catalyst deactivation by active site neutralization, zeolite destruction or
through pore mouth plugging. Operationally, some alternative feeds demonstrate
miscibility issues with fossil-based feedstocks. Additionally, they are unstable
at standard temperatures and can cause corrosion of process equipment.
This article
introduces practical solutions to each of these challenges. A drop-in catalyst
activity or changes in product selectivity can be mitigated by careful
selection of optimal catalyst technology. The immiscibility and instability of biogenic
feedstocks can be addressed through the correct feed injection technology. The
selection of the correct metallurgy and corrosion inhibitors is important to
guard against possible corrosion introduced by some
alternative feeds. In this article, several pretreatment solutions—such as mild
hydrotreatment, degumming, adsorption, catalytic pyoil and others—have also been
highlighted to further minimize these operational challenges. The process of increasing
the share of renewables in transportation fuels to reach 29% by 2030—as per RED
III—can be achieved by taking advantage of the flexibility of the FCCU to co-process
a variety of alternative feedstocks. Today, the industry is collectively taking
a step into the future of refining as we learn how to implement these changes
together more fully. HP
NOTE
LITERATURE CITED
Guillaume Vincent is a Technology Manager for BASF’s
Refining Catalysts in Europe, for the Middle East and Africa. He joined BASF in
January 2023 and has 15 yr of experience in refining industries, including
purification adsorbents and hydroprocessing catalysts. Dr. Vincent started his
experience with the Porocel Group (which was acquired by Evonik) and developed his
career through several key positions as a lab manager, a technical service manager
and a business segment manager. He earned a PhD in chemical engineering from
the École Nationale
Supérieure des
Industries Chimiques (ENSIC), France.
Stefano
Riva is a Technical Service Manager for BASF’s Refining
Catalysts business in Europe and the Middle East. He has more than 30 yr of
experience in FCC and various refining optimization projects. In 2002, he
joined BASF’s technical sales team. Prior to BASF, Riva worked with ExxonMobil
at the Trecate refinery near Milan, Italy. He earned a degree in chemical engineering
from the Politecnico di Milano.
Francy Barrios is a Technology
Engineer for FCC and sweetening technologies at Axens. She has 16 yr of
experience in the refining industry. Her primary responsibilities are technical
proposals for new or revamped FCCUs and sweetening units, FCC catalysts
evaluation and technical support. Barrios joined Axens in 2018 after working
for 11 yr in PDVSA Intevep—the research center of
PDVSA—as a Technical Assistance Engineer for FCCUs, providing technical support
and participating in research and development (R&D) activities related to
FCC catalysts and additives. She earned a degree in chemical engineering from
the Universidad de Los Andes of Venezuela.
François Dubois is a Corrosion Specialist with Axens. For the past 10 yr, he has
been in charge of developing material selection philosophies for the process
technologies licensed by Axens, including bio-oil co-processing hydrotreatments
and FCC. Dr. Dubois has 20 yr of experience in the field of materials and
corrosion, mostly in oil, gas and refinery applications. He began his career in
academic research and R&D. Dr. Dubois earned an engineering degree and a
PhD in material science from the Institut National Polytechnique de Grenoble.
Scott Golczynski is the Manager of R&D for FCC technology at Technip Energies. He has more than 19 yr of experience in the petrochemical industry and specializes in the design of FCCUs. His experience includes front-end process engineering, pilot plant operations, process control and computational fluid dynamic simulations. Golczynski has led the process engineering efforts on several grassroots FCCUs and revamp projects. His primary responsibility at Technip Energies is leading R&D efforts to improve or develop new FCC technologies, utilizing his experience in reactor scale-up from pilot plant and cold flow experimental data. Golczynski earned a BS degree in chemical engineering from the University of Texas at Austin.