UOP OLEFLEX PROCESS FOR LIGHT OLEFIN PRODUCTION

INTRODUCTION

The UOP* Oleflex* process is catalytic dehydrogenation technology for the production
of light olefins from their corresponding paraffin. An Oleflex unit can dehydrogenate
propane, isobutane, normal butane, or isopentane feedstocks separately or as mixtures
spanning two consecutive carbon numbers. This process was commercialized in 1990,
and by 2002 more than 1,250,000 metric tons per year (MTA) of propylene and more
than 2,800,000 MTA of isobutylene were produced from Oleflex units located throughout
the world.

PROCESS DESCRIPTION

The UOP Oleflex process is best described by separating the technology into three different
sections:
● Reactor section
● Product recovery section
● Catalyst regeneration section

Reactor Section

Hydrocarbon feed is mixed with hydrogen-rich recycle gas (Fig. 5.1.1). This combined
feed is heated to the desired reactor inlet temperature and converted at high monoolefin
selectivity in the reactors.

The reactor section consists of several radial-flow reactors, charge and interstage
heaters, and a reactor feed-effluent heat exchanger. The diagram shows a unit with four
reactors, which would be typical for a unit processing propane feed. Three reactors are
used for butane or isopentane dehydrogenation. Three reactors are also used for blends of
C3-C4 or C4-C5 feeds.
Because the reaction is endothermic, conversion is maintained by supplying heat
through interstage heaters. The effluent leaves the last reactor, exchanges heat with the
combined feed, and is sent to the product recovery section.

Product Recovery Section

A simplified product recovery section is also shown in Fig. 5.1.1. The reactor effluent
is cooled, compressed, dried, and sent to a cryogenic separation system. The dryers
serve two functions: (1) to remove trace amounts of water formed from the catalyst
regeneration and (2) to remove hydrogen sulfide. The treated effluent is partially condensed
in the cold separation system and directed to a separator.
Two products come from the Oleflex product recovery section: separator gas and separator
liquid. The gas from the cold high-pressure separator is expanded and divided into
two streams: recycle gas and net gas. The net gas is recovered at 90 to 93 mol % hydrogen
purity. The impurities in the hydrogen product consist primarily of methane and ethane.
The separator liquid, which consists primarily of the olefin product and unconverted paraffin,
is sent downstream for processing.

Catalyst Regeneration Section

The regeneration section, shown in Fig. 5.1.2, is similar to the CCR* unit used in the
UOP Platforming* process. The CCR unit performs four functions:
● Burns the coke off the catalyst
● Redistributes the platinum
● Removes the excess moisture
● Reduces the catalyst prior to returning to the reactors
The slowly moving bed of catalyst circulates in a loop through the reactors and the
regenerator. The cycle time around the loop can be adjusted within broad limits but is typically
anywhere from 5 to 10 days, depending on the severity of the Oleflex operation and
the need for regeneration. The regeneration section can be stored for a time without interrupting
the catalytic dehydrogenation process in the reactor and recovery sections.

DEHYDROGENATION PLANTS

Propylene Plant
Oleflex process units typically operate in conjunction with fractionators and other
process units within a production plant. In a propylene plant (Figure 5.1.3), a propanerich
liquefied petroleum gas (LPG) feedstock is sent to a depropanizer to reject butanes
and heavier hydrocarbons. The depropanizer overhead is then directed to the Oleflex
unit. The once-through conversion of propane is approximately 40 percent, which
closely approaches the equilibrium value defined by the Oleflex process conditions.
Approximately 90 percent of the propane conversion reactions are selective to propylene
and hydrogen; the result is a propylene mass selectivity in excess of 85 wt %. Two
product streams are created within the C3 Oleflex unit: a hydrogen-rich vapor product
and a liquid product rich in propane and propylene.
Trace levels of methyl acetylene and propadiene are removed from the Oleflex liquid
product by selective hydrogenation. The selective diolefin and acetylene hydrogenation
step is accomplished with the Hüls SHP process, which is available for license through
UOP. The SHP process selectively saturates diolefins and acetylenes to monoolefins
without saturating propylene. The process consists of a single liquid-phase reactor. The
diolefins plus acetylene content of the propylene product is less than 5 wt ppm.
Ethane and lighter material enter the propylene plant in the fresh feed and are also created
by nonselective reactions within the Oleflex unit. These light ends are rejected from
the complex by a deethanizer column. The deethanizer bottoms are then directed to a
propane-propylene (P-P) splitter. The splitter produces high-purity propylene as the overhead
product. Typical propylene purity ranges between 99.5 and 99.8 wt %. Unconverted
propane from the Oleflex unit concentrates in the splitter bottoms and is returned to the
depropanizer for recycle to the Oleflex unit.

Ether Complex

A typical etherification complex configuration is shown in Fig. 5.1.4 for the production
of methyl tertiary butyl ether (MTBE) from butanes and methanol. Ethanol can be substituted
for methanol to make ethyl tertiary butyl ether (ETBE) with the same process
configuration. Furthermore, isopentane may be used in addition to or instead of field
butanes to make tertiary amyl methyl ether (TAME) or tertiary amyl ethyl ether
(TAEE). The complex configuration for a C5 dehydrogenation complex varies according
to the feedstock composition and processing objectives.
Three primary catalytic processes are used in an MTBE complex:
● Paraffin isomerization to convert normal butane into isobutane
● Dehydrogenation to convert isobutane into isobutylene
● Etherification to react isobutylene with methanol to make MTBE
Field butanes, a mixture of normal butane and isobutane obtained from natural gas condensate,
are fed to a deisobutanizer (DIB) column. The DIB column prepares an isobutane
overhead product, rejects any pentane or heavier material in the DIB bottoms, and makes
a normal butane sidecut for feed to the paraffin isomerization unit.
The DIB overhead is directed to the Oleflex unit. The once-through conversion of
isobutane is approximately 50 percent. About 91 percent of the isobutane conversion reactions
are selective to isobutylene and hydrogen. On a mass basis, the isobutylene selectivity
is 88 wt %. Two product streams are created within the C4 Oleflex unit: a hydrogen-rich
vapor product and a liquid product rich in isobutane and isobutylene.
The C4 Oleflex liquid product is sent to an etherification unit, where methanol reacts
with isobutylene to make MTBE. Isobutylene conversion is greater than 99 percent, and
the MTBE selectivity is greater than 99.5 percent. Raffinate from the etherification unit is
depropanized to remove propane and lighter material. The depropanizer bottoms are then
dried, saturated, and returned to the DIB column.

PROPYLENE PRODUCTION ECONOMICS

A plant producing 350,000 MTA of propylene is chosen to illustrate process economics.
Given the more favorable C4 and C5 olefin equilibrium, butylene and amylene production
costs are lower per unit of olefin when adjusted for any differential in feedstock
value. The basis used for economic calculations is shown in Table 5.1.1. This basis is
typical for U.S. Gulf Coast prices prevailing in mid-2002 and can be used to show that
the pretax return on investment for such a plant is approximately 24 percent.
Material Balance
The LPG feedstock is the largest cost component of propylene production. The quantity of
propane consumed per unit of propylene product is primarily determined by the selectivity
of the Oleflex unit because fractionation losses throughout the propylene plant are small.
The Oleflex selectivity to propylene is 90 mol % (85 wt %), and the production of 1.0 metric
ton (MT) of propylene requires approximately 1.2 MT of propane.
An overall mass balance for the production of polymer-grade propylene from C3 LPG
is shown in Table 5.1.2 for a polymer-grade propylene plant producing 350,000 MTA,
based on 8000 operating hours per year. The fresh LPG feedstock is assumed to be 94 LV %
propane with 3 LV % ethane and 3 LV % butane. The native ethane in the feed is rejected in
the deethanizer along with light ends produced in the Oleflex unit and used as process fuel.
The butanes are rejected from the depropanizer bottoms. This small butane-rich

stream could be used as either a by-product or as fuel. In this example, the depropanizer
bottoms were used as fuel within the plant.
The Oleflex process coproduces high-quality hydrogen. Project economics benefit
when a hydrogen consumer is available in the vicinity of the propylene plant. If chemical
hydrogen cannot be exported, then hydrogen is used as process fuel. This evaluation
assumes that hydrogen is used as fuel within the plant.

Utility Requirements

Utility requirements for a plant producing 350,000 MTA of propylene are summarized
in Table 5.1.3. These estimates are based on the use of an extracting steam turbine to
drive the Oleflex reactor effluent compressor. A water-cooled surface condenser is used
on the steam turbine exhaust. A condensing steam driver was chosen in this example for
the propane-propylene splitter heat-pump compressor.

Propylene Production Costs

Representative costs for producing 350,000 MTA of polymer-grade propylene using the
Oleflex process are shown in Table 5.1.4. These costs are based on feed and product

values defined in Table 5.1.1. The fixed expenses in Table 5.1.4 consist of estimated
labor costs and maintenance costs and include an allowance for local taxes, insurance,
and interest on working capital.

Capital Requirements

The ISBL erected cost for an Oleflex unit producing 350,000 MTA of polymer-grade
propylene is approximately $145 million (U.S. Gulf Coast, mid-2002 erected cost).
This figure includes the reactor and product recovery sections, a modular CCR unit, a
Hüls SHP unit, and a fractionation section consisting of a depropanizer, deethanizer,
and heat-pumped P-P splitter. The costs are based on an extracting steam turbine driver
for the reactor effluent compressor and a steam-driven heat pump. Capital costs are
highly dependent on many factors, such as location, cost of labor, and the relative workload
of equipment suppliers.
Total project costs include ISBL and OSBL erected costs and all owner’s costs. This
example assumes an inclusive mid-2002 total project cost of $215 million including:
● ISBL erected costs for all process units
● OSBL erected costs (off-site utilities, tankage, laboratory, warehouse, for example)
● Initial catalyst and absorbant loadings
● Technology fees
● Project development including site procurement and preparation

Overall Economics

Because the feedstock represents such a large portion of the total production cost, the
economics for the Oleflex process are largely dependent on the price differential
between propane and propylene. Assuming the values of $180/MT for propane and
$420/MT for propylene, or a differential price of $240/MT, the pretax return on investment
is approximately 24 percent for a plant producing 350,000 MTA of propylene.

CATALYTIC CRACKING con't

MAXOFIN FCC

The proprietary MAXOFIN FCC process, licensed by KBR, is designed to maximize the production of propylene from traditional FCC feedstocks and selected naphthas (Fig. 3.1.6).
In addition to processing recycled light naphtha and C4 LPG, the riser can accept naphtha
from elsewhere in the refinery complex, such as coker naphtha streams, and upgrades
these streams into additional light olefins. Olefinic streams, such as coker naphtha, convert

most readily to light olefins with the MAXOFIN FCC process. Paraffinic naphthas, such
as light straight-run naphtha, also can be upgraded in the MAXOFIN FCC unit, but to a
lesser extent than olefinic feedstocks.
A MAXOFIN FCC unit can also produce an economic volume of ethylene for petrochemical
consumption if there is ready access to a petrochemical plant or ethylene
pipeline. For instance, while traditional FCC operations have produced less than about 2
wt % ethylene, the MAXOFIN FCC process can produce as much as 8 wt % ethylene.
Spent Catalyst Stripping
Catalyst separated in the cyclones flows through the respective diplegs and discharges into
the stripper bed. In the stripper, hydrocarbon vapors from within and around the catalyst

particles are displaced by steam into the disengager dilute phase, minimizing hydrocarbon
carry-under with the spent catalyst to the regenerator. Stripping is a very important function
because it minimizes regenerator bed temperature and regenerator air requirements,
resulting in increased conversion in regenerator temperature or air-limited operations. See
Fig. 3.1.7.
The catalyst entering the stripper is contacted by upflowing steam introduced through
two steam distributors. The majority of the hydrocarbon vapors entrained with the catalyst
are displaced in the upper stripper bed. The catalyst then flows down through a set of hat
and doughnut baffles. In the baffled section, a combination of residence time and steam
partial pressure is used to allow the hydrocarbons to diffuse out of the catalyst pores into
the steam introduced via the lower distributor.
Stripped catalyst, with essentially all strippable hydrocarbons removed, passes into a
standpipe, which is aerated with steam to maintain smooth flow. At the base of the standpipe,
a plug valve regulates the flow of catalyst to maintain the spent catalyst level in the
stripper. The catalyst then flows into the spent catalyst distributor and into the regenerator.
Regeneration
In the regenerator, coke is burned off the catalyst with air in a fluid bed to supply the heat
requirements of the process and restore the catalyst’s activity. The regenerator is operated

in either complete CO combustion or partial CO combustion modes. In the regenerator
cyclones, the flue gas is separated from the catalyst.
Regeneration is a key part of the FCC process and must be executed in an environment
that preserves catalyst activity and selectivity so that the reaction system can deliver the
desired product yields.
The KBR Orthoflow converter uses a countercurrent regeneration system to accomplish
this. The concept is illustrated in Fig. 3.1.8. The spent catalyst is introduced and distributed
uniformly near the top of the dense bed. This is made possible by the spent catalyst
distributor. Air is introduced near the bottom of the bed.
The design allows coke burning to begin in a low-oxygen partial pressure environment
which controls the initial burning rate. Controlling the burning rate prevents excessive particle
temperatures which would damage the catalyst. The hydrogen in the coke combusts more
quickly than the carbon, and most of the water formed is released near the top of the bed.
These features together minimize catalyst deactivation during the regeneration process.
With this unique approach, the KBR countercurrent regenerator achieves the advantages
of multiple regeneration stages, yet does so with the simplicity, cost efficiency, and
reliability of a single regenerator vessel.
Catalyst Cooler
A regenerator heat removal system may be included to keep the regenerator temperature
and catalyst circulation rate at the optimum values for economic processing of the feedstock.
The requirement for a catalyst cooler usually occurs when processing residual feedstocks
which produce more coke, especially at high conversion.

The KBR regenerator heat removal system is shown in Figure 3.1.9. It consists of an
external catalyst cooler which generates high-pressure steam from heat transferred from
the regenerated catalyst.
Catalyst is drawn off the side of the regenerator and flows downward as a dense bed
through an exchanger containing bayonet tubes. The catalyst surrounding the bayonet tubes
is cooled and then transported back to the regenerator. Air is introduced at the bottom of the
cooler to fluidize the catalyst. A slide valve is used to control the catalyst circulation rate and
thus the heat removed. Varying the catalyst circulation gives control over regenerator temperature
for a broad range of feedstocks, catalysts, and operating conditions.
Gravity circulated boiler feedwater flows downward through the inner bayonet tubes
while the steam generated flows upward through the annulus between the tubes.

CATALYTIC CRACKING

INTRODUCTION

Fluid catalytic cracking (FCC) technology is a technology with more than 60 years of commercial operating experience. The process is used to convert higher-molecular-weight hydrocarbons to lighter, more valuable products through contact with a powdered catalyst at appropriate conditions. Historically, the primary purpose of the FCC process has been to produce gasoline, distillate, and C3/C4 olefins from low-value excess refinery gas oils and heavier refinery streams. FCC is often the heart of a modern refinery because of its adaptability to changing feedstocks and product demands and because of high margins that
exist between the FCC feedstocks and converted FCC products. As oil refining has evolved
over the last 60 years, the FCC process has evolved with it, meeting the challenges of cracking heavier, more contaminated feedstocks, increasing operating flexibility, accommodating environmental legislation, and maximizing reliability.
The FCC unit continuously circulates a fluidized zeolite catalyst that allows rapid
cracking reactions to occur in the vapor phase. The KBR Orthoflow FCC unit (Fig. 3.1.1)
consists of a stacked disengager-regenerator system that minimizes plot space requirements. The cracking reactions are carried out in an up-flowing vertical reactor-riser in
which a liquid oil stream contacts hot powdered catalyst. The oil vaporizes and cracks to
lighter products as it moves up the riser and carries the catalyst along with it. The reactions
are rapid, requiring only a few seconds of contact time. Simultaneously with the desired
reactions, coke, a material having a low ratio of hydrogen to carbon, deposits on the catalyst
and renders it less catalytically active. Catalyst and product vapors separate in a disengaging vessel with the catalyst continuing first through a stripping stage and second
through a regeneration stage where coke is combusted to rejuvenate the catalyst and provide heat for operation of the process. The regenerated catalyst then passes to the bottom of the reactor-riser, where the cycle starts again. Hydrocarbon product vapors flow downstream for separation into individual products.
KBR, through its ancestry in The M.W. Kellogg Company, has been a leader in FCC
technology developments since the inception of the process. In recent years, KBR has
worked with its FCC partner, ExxonMobil, to create and refine FCC technology features
that have led the industry. To date, KBR has licensed more than 120 grassroots FCC

units throughout the world, including 13 grassroots units and more than 120 revamps
since just 1990.

FEEDSTOCKS

The modern FCC unit can accept a broad range of feedstocks, a fact which contributes to
FCC’s reputation as one of the most flexible refining processes in use today. Examples of
common feedstocks for conventional distillate feed FCC units are
● Atmospheric gas oils
● Vacuum gas oils
● Coker gas oils
● Thermally cracked gas oils
● Solvent deasphalted oils
● Lube extracts
● Hydrocracker bottoms

Residual FCCU (RFCCU) processes Conradson carbon residue and metals-contaminated
feedstocks such as atmospheric residues or mixtures of vacuum residue and gas oils.
Depending on the level of carbon residue and metallic contaminants (nickel and vanadium),
these feedstocks may be hydrotreated or deasphalted before being fed to an RFCCU.
Feed hydrotreating or deasphalting reduces the carbon residue and metals levels of the
feed, reducing both the coke-making tendency of the feed and catalyst deactivation.

PRODUCTS

Products from the FCC and RFCC processes are typically as follows:
● Fuel gas (ethane and lighter hydrocarbons)
● C3 and C4 liquefied petroleum gas (LPG)
● Gasoline
● Light cycle oil (LCO)
● Fractionator bottoms (slurry oil)
● Coke (combusted in regenerator)
● Hydrogen Sulfide (from amine regeneration)

Although gasoline is typically the most desired product from an FCCU or RFCCU, design
and operating variables can be adjusted to maximize other products. The three principal
modes of FCC operation are (1) maximum gasoline production, (2) maximum light cycle
oil production, and (3) maximum light olefin production, often referred to as maximum
LPG operation. These modes of operation are discussed below:
Maximum Gasoline The maximum gasoline mode is characterized by use of an intermediate cracking temperature (510 to 540°C), high catalyst activity, and a high catalyst/oil ratio. Recycle is normally not used since the conversion after a single pass through the riser is already high. Maximization of gasoline yield requires the use of an effective feed injection system, a short-contact-time vertical riser, and efficient riser effluent separation to maximize the cracking selectivity to gasoline in the riser and to prevent secondary reactions from degrading the gasoline after it exits the riser.
Maximum Middle Distillate The maximum middle distillate mode of operation is a low-cracking-severity operation in which the first pass conversion is held to a low level to restrict recracking of light cycle oil formed during initial cracking. Severity is lowered by reducing the riser outlet temperature (below 510°C) and by reducing the catalyst/oil ratio. The lower catalyst/oil ratio is often achieved by the use of a fired feed heater which significantly increases feed temperature. Additionally catalyst activity is sometimes lowered by reducing the fresh catalyst makeup rate or reducing fresh catalyst activity. Since during low-severity operation a substantial portion of the feed remains unconverted in a single pass through the riser, recycle of heavy cycle oil to the riser is used to reduce the yield of lower-value, heavy streams such as slurry product. When middle distillate production is maximized, upstream crude distillation units are operated to minimize middle distillate components in the FCCU feedstock, since these components either degrade in quality or convert to gasoline and lighter products in the FCCU. In addition, while maximizing middle distillate production, the FCCU gasoline endpoint would typically be minimized within middle distillate flash point constraints, shifting gasoline product into LCO.
If it is desirable to increase gasoline octane or increase LPG yield while also maximizing
LCO production, ZSM-5 containing catalyst additives can be used. ZSM-5 selectively
cracks gasoline boiling-range linear molecules and has the effect of increasing gasoline
research and motor octane ratings, decreasing gasoline yield, and increasing C3 and C4
LPG yield. Light cycle oil yield is also reduced slightly.

Maximum Light Olefin Yield

The yields of propylene and butylenes may be increased above that of the maximum gasoline operation by increasing the riser temperature above 540°C and by use of ZSM-5 containing catalyst additives. The FCC unit may also be designed specifically to allow
maximization of propylene as well as ethylene production by incorporation of MAXOFIN
FCC technology, as described more fully in the next section. While traditional FCC operations typically produce less than 6 wt % propylene, the MAXOFIN FCC process can produce as much as 20 wt % or more propylene from traditional FCC feedstocks. The process increases propylene yield relative to that produced by conventional FCC units by combining the effects of MAXOFIN-3 catalyst additive and proprietary hardware, including a second high-severity riser designed to crack surplus naphtha and C4’s into incremental light
olefins. Table 3.1.1 shows the yield flexibility of the MAXOFIN FCC process that can
alternate between maximum propylene and traditional FCC operations.

PROCESS DESCRIPTION

The FCC process may be divided into several major sections, including the converter section, flue gas section, main fractionator section, and vapor recovery units (VRUs). The

number of product streams, the degree of product fractionation, flue gas handling steps,
and several other aspects of the process will vary from unit to unit, depending on the
requirements of the application. The following sections provide more detailed descriptions
of the converter, flue gas train, main fractionator, and VRU.

Converter

The KBR Orthoflow FCCU converter shown in Fig. 3.1.2 consists of regenerator, stripper,
and disengager vessels, with continuous closed-loop catalyst circulation between the
regenerator and disengager/stripper. The term Orthoflow derives from the in-line stacked
arrangement of the disengager and stripper over the regenerator. This arrangement has the
following operational and cost advantages:
● Essentially all-vertical flow of catalyst in standpipes and risers
● Short regenerated and spent catalyst standpipes allowing robust catalyst circulation
● Uniform distribution of spent catalyst in the stripper and regenerator
● Low overall converter height
● Minimum structural steel and plot area requirements
Preheated fresh feedstock, plus any recycle feed, is charged to the base of the riser reactor.
Upon contact with hot regenerated catalyst, the feedstock is vaporized and converted to lower boiling fractions (light cycle oil, gasoline, C3 and C4 LPG, and dry gas). Product vapors are separated from spent catalyst in the disengager cyclones and flow via the disengager

overhead line to the main fractionator and vapor recovery unit for quenching and fractionation.
Coke formed during the cracking reactions is deposited on the catalyst, thereby reducing
its activity. The coked catalyst, which is separated from the reactor products in the
disengager cyclones, flows via the stripper and spent catalyst standpipe to the regenerator.
The discharge rate from the standpipe is controlled by the spent catalyst plug valve.
In the regenerator, coke is removed from the spent catalyst by combustion with air. Air
is supplied to the regenerator air distributors from an air blower. Flue gas from the combustion of coke exits the regenerator through two-stage cyclones which remove all but a
trace of catalyst from the flue gas. Flue gas is collected in an external plenum chamber and
flows to the flue gas train. Regenerated catalyst, with its activity restored, is returned to the
riser via the regenerated catalyst plug valve, completing the cycle.

 ATOMAX Feed Injection System

The Orthoflow FCC design employs a regenerated catalyst standpipe, a catalyst plug
valve, and a short inclined lateral to transport regenerated catalyst from the regenerator to
the riser. The catalyst then enters a feed injection cone surrounded by multiple, flat-spray, atomizing feed injection nozzles, as shown in Fig. 3.1.3. The flat, fan-shaped sprays provide
uniform coverage and maximum penetration of feedstock into catalyst, and prevent catalyst
from bypassing feed in the injection zone. Proprietary feed injection nozzles, known
as ATOMAX nozzles, are used to achieve the desired feed atomization and spray pattern
while minimizing feed pressure requirements. The hot regenerated catalyst vaporizes the
oil feed, raises it to reaction temperature, and supplies the necessary heat for cracking.
The cracking reaction proceeds as the catalyst and vapor mixture flow up the riser. The
riser outlet temperature is controlled by the amount of catalyst admitted to the riser by the
catalyst plug valve.

Riser Quench

The riser quench system consists of a series of nozzles uniformly spaced around the upper
section of riser. A portion of the feed or a recycle stream from the main fractionator is
injected through the nozzles into the riser to rapidly reduce the temperature of the riser
contents. The heat required to vaporize the quench is supplied by increased fresh feed preheat or by increased catalyst circulation. This effectively increases the temperature in the
lower section of the riser above that which would be achieved in a nonquenched operation,
thereby increasing the vaporization of heavy feeds, increasing gasoline yield, olefin production, and gasoline octane.

Riser Termination

At the top of the riser, all the selective cracking reactions have been completed. It is important to minimize product vapor residence time in the disengager to prevent unwanted thermal or catalytic cracking reactions which produce dry gas and coke from more valuable
products. Figure 3.1.4 shows the strong effect of temperature on thermal recracking of
gasoline and distillate to produce predominantly dry gas.
Closed cyclone technology is used to separate product vapors from catalyst with minimum
vapor residence time in the disengager. This system (Fig. 3.1.5) consists of riser
cyclones directly coupled to secondary cyclones housed in the disengager vessel. The riser
cyclones effect a quick separation of the spent catalyst and product vapors exiting the
riser. The vapors flow directly from the outlet of the riser cyclones into the inlets of the

secondary cyclones and then to the main fractionator for rapid quenching. Closed cyclones
almost completely eliminate postriser thermal cracking with its associated dry gas and
butadiene production. Closed cyclone technology is particularly important in operation at
high riser temperatures (say, 538°C or higher), typical of maximum gasoline or maximum
light olefin operations.

hydrocarbon liquids separation

Transmix/DistillationFractionation

PETROGAS has years of experience in designing and building modular distillation systems. PETROGAS designs systems to meet your application, and builds its units to suit your needs.

Transmix Distillation is a simple process of using heat to separate light hydrocarbon products from a diesel or similar interface fluid.

PETROGAS can work in any size range and any metal or alloy to produce a distillation system that predictably distills fluids.

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Vapor Recovery Unit Meets Regulations

During loading of motor gasoline at underground storage tanks located at our stations, the liquid introduced displaces vapors from previous loadings that still exist in the tank and those vapors generated by the current product loading. These vapors contain some volatile organic compounds (VOCs). The Clean Air Act of 1990 requires the control of VOC emissions, and the refinery's Marketing Terminal's Vapor Recovery unit meets Clean Air Act (Title 33, Code of Federal Regulations, Part 154) requirements.

Marketing Terminal Vapor Recovery Unit

As a tank truck drops (delivers) new product into the underground storage tank at Chevron stations, the vapors created during the drop are pushed back into the tank truck and stored there.

As the tank truck loads new product at the Marketing Terminal using a "bottom loading" method, the product being loaded into the bottom of the tank pushes the collected vapors into a vapor recovery hose connected to the recovery system. The Adsorb/Absorb vapor recovery unit condenses the vapors, recovering about 2 gallons of gasoline per 1000 gallons loaded product.

Terminal Vapor Recovery Unit

Tanker truck connects to vapor recovery system

Processing Crude Oil

Hi-Tech Process Control

Using the latest electronic technology to monitor and control the plants, operators run the process units around the clock, 7 days a week. From control rooms located in each Operations area, operators use a computer-driven process control system with console screens that display color interactive graphics of the plants and real-time (current) data on the status of the plants. The process control system allows operators to "fine tune" the processes and respond immediately to process changes. With redundancy designed into the control system, safe operations are assured in the event of plant upset.

Refining's Basic Steps

Most refineries, regardless of complexity, perform a few basic steps in the refining process: DISTILLATION, CRACKING, TREATING andREFORMING. These processes occur in our main operating areas – Crude/Aromatics, Cracking I, RDS/Coker, Cracking II, and at the Sulfur Recovery Unit.

Pascagoula Refinery skyline

1. Distillation

Modern distillation involves pumping oil through pipes in hot furnaces and separating light hydrocarbon molecules from heavy ones in downstream distillation towers – the tall, narrow columns that give refineries their distinctive skylines.

The Pascagoula Refinery's refining process begins when crude oil is distilled in two large Crude Units that have three distillation columns, one that operates at near atmospheric pressure, and two others that operate at less than atmospheric pressure, i.e., a vacuum.

Click on image for Distillation Column Diagram

During this process, the lightest materials, like propane and butane, vaporize and rise to the top of the first atmospheric column. Medium weight materials, including gasoline, jet and diesel fuels, condense in the middle. Heavy materials, called gas oils, condense in the lower portion of the atmospheric column. The heaviest tar-like material, called residuum, is referred to as the "bottom of the barrel" because it never really rises.

This distillation process is repeated in many other plants as the oil is further refined to make various products.

In some cases, distillation columns are operated at less than atmospheric pressure (vacuum) to lower the temperature at which a hydrocarbon mixture boils. This "vacuum distillation" (VDU) reduces the chance of thermal decomposition (cracking) due to over heating the mixture.

As part of the 2003 Clean Fuels Project, the Pascagoula Refinery added a new low-pressure vacuum column to the Crude I Unit and converted the RDS/Coker's VDU into a second vacuum column for the Crude II Unit. These and other distillation upgrades improved gas oil recovery and decreased residuum volume.

Using the most up-to-date computer control systems, refinery operators precisely control the temperatures in the distillation columns which are designed with pipes to withdraw the various types of products where they condense. Products from the top, middle and bottom of the column travel through these pipes to different plants for further refining.

Click on image above for Catalytic Cracking Diagram

Click on image above for Hydrocracking Diagram

Click on image above for Alkylation Diagram

Click on image above for Reforming Diagram

2. Cracking

Since the marketplace establishes product value, our competitive edge depends on how efficiently we can convert middle distillate, gas oil and residuum into the highest value products.

At the Pascagoula Refinery, we convert middle distillate, gas oil and residuum into primarily gasoline, jet and diesel fuels by using a series of processing plants that literally "crack" large, heavy molecules into smaller, lighter ones.

Heat and catalysts are used to convert the heavier oils to lighter products using three "cracking" methods: fluid catalytic cracking (FCC), hydrocracking (Isomax), and coking (or thermal-cracking).

The Fluid Catalytic Cracker (FCC) uses high temperature and catalyst to crack 63,000 barrels (2.6 million gallons) each day of heavy gas oil mostly into gasoline. Hydrocracking uses catalysts to react gas oil and hydrogen under high pressure and high temperature to make both jet fuel and gasoline.

Also, about 58,000 barrels (2.4 million gallons) of lighter gas oil is converted daily in two Isomax Units, using this hydrocracking process.

We blend most of the products from the FCC and the Isomaxes directly into transportation fuels, i.e., gasoline, diesel and jet fuel. We burn the lightest molecules as fuel for the refinery's furnaces, thus conserving natural gas and minimizing waste.

In the Delayed Coking Unit (Coker), 105,000 barrels a day of low-value residuum is converted (using the coking, or thermal-cracking process) to high-value light products, producing petroleum coke as a by-product. The large residuum molecules are cracked into smaller molecules when the residuum is held in a coke drum at a high temperature for a period of time. Only solid coke remains and must be drilled from the coke drums.

Modifications to the refinery during its 2003 Clean Fuels Project increased residuum volume going to the Coker Unit. The project increased coke handling capacity and replaced the 150 metric-ton coke drums with new 300 metric-ton drums to handle the increased residuum volume.

The Coker typically produces 6,200 tons a day of petroleum coke, which is sold for use as fuel or in cement manufacturing.

Combining

While the cracking processes break most of the gas oil into gasoline and jet fuel, they also break off some pieces that are lighter than gasoline. Since Pascagoula Refinery's primary focus is on making transportation fuels, we recombine 14,800 barrels (622,000 gallons) each day of lighter components in two Alkylation Units. This process takes the small molecules and recombines them in the presence of sulfuric acid catalyst to convert them into high octane gasoline.

3. Treating (Removing Impurities)

The products from the Crude Units and the feeds to other units contain some natural impurities, such as sulfur and nitrogen. Using a process called hydrotreating (a milder version of hydrocracking), these impurities are removed to reduce air pollution when our fuels are used.

Because about 80 percent of the crude oil processed by the Pascagoula Refinery is heavier oils that are high in sulfur and nitrogen, various treating units throughout the refinery work to remove these impurities.

In the RDS Unit's six 1,000-ton reactors, sulfur and nitrogen are removed from FCC feed stream. The sulfur is converted to hydrogen sulfide and sent to the Sulfur Unit where it is converted into elemental sulfur. Nitrogen is transformed into ammonia which is removed from the process by water-washing. Later, the water is treated to recover the ammonia as a pure product for use in the production of fertilizer.

The RDS's Unit main product, low sulfur vacuum gas oil, is fed to the FCC (fluid catalytic cracker) Unit which then cracks it into high value products such as gasoline and diesel.

4. Reforming

Octane rating is a key measurement of how well a gasoline performs in an automobile engine. Much of the gasoline that comes from the Crude Units or from the Cracking Units does not have enough octane to burn well in cars.

The gasoline process streams in the refinery that have a fairly low octane rating are sent to a Reforming Unit where their octane levels are boosted. These reforming units employ precious-metal catalysts ‑ platinum and rhenium – and thereby get the name "rheniformers." In the reforming process, hydrocarbon molecules are "reformed" into high octane gasoline components. For example, methyl cyclohexane is reformed into toluene.

The reforming process actually removes hydrogen from low-octane gasoline. The hydrogen is used throughout the refinery in various cracking (hydrocracking) and treating (hydrotreating) units.

Our refinery operates three catalytic reformers, where we rearrange and change 71,000 barrels (about 3 million gallons) of gasoline per day to give it the high octane cars need.

Blending

A final and critical step is the blending of our products. Gasoline, for example, is blended from treated components made in several processing units. Blending and Shipping Area operators precisely combine these to ensure that the blend has the right octane level, vapor pressure rating and other important specifications. All products are blended in a similar fashion.

Quality Control

In the refinery’s modernly-equipped Laboratory, chemists and technicians conduct continuous quality assurance tests on all finished products, including checking gasoline for proper octane rating. Techron®, Chevron’s patented performance booster, is added to gasoline at the company’s marketing terminals, one of which is located at the Pascagoula Refinery.

Marine Vapor Recovery System

Loading Displaces Vapors

During loading of bulk liquid tankers or barges, the liquid introduced displaces vapors from previous cargoes that still exist in the tank and those vapors generated by the current cargo loading. The vapors of certain cargoes contain volatile organic compounds (VOCs) that include hydrocarbons, oxygenated hydrocarbons, and organic compounds containing nitrogen or sulfur.

Chevron MVR System meets federal requirements

The Clean Air Act of 1990 requires the control of VOC emissions, and the Marine Vapor Recovery units at the refinery’s marine facility meet Coast Guard (Title 33, Code of Federal Regulations, Part 154) and Clean Air Act (Title 40, Code of Federal Regulations, Part 61 and 63) requirements.

The Pascagoula Refinery’s Marine Vapor Recovery (MVR) system includes two units that serve Berths 2-5 and a separate unit at Berth 6, which is located a good distance away from Berths 2-5.

MVR at Main Product Dock (Berths 2 - 5)

• Units "A" and "B"; each with 35,000 barrels liquid loading per hour vapor recovery capacity; combined vapor recovery capacity 70,000 barrels per hour of liquid loading.
• Recovers vapors from VOC emissions containing vapor pressure of 1.5 psi or greater.
• The process uses Lean Oil Absorption. While a regulated product is being loaded, vapors are recovered from the marine vessels by a header system. This header carries the vapors, either by pressure from loading or pulled by vapor boosters that provide a slight vacuum on the header. The vapors are routed through a chilled absorber, entrained in the Lean Oil, then passed through a series of exchangers, and then into a stripper column where the VOCs are stripped out by heat and held in a holding drum. The recovered VOCs are then pumped in to a crude transfer line for reprocessing.

MVR at Berth 6

MVR at Berth 6 provides vapor recovery for Berth 6 only and has vapor recovery capacity of 8,000 barrels per hour of liquid loading. Like its sister unit at the Main Product Dock, this unit uses the Lean Oil Absorption system, but does not feature the vapor boosters. This unit recovers vapors from special products and chemicals including Penhep, Hydrobate, Heptane, Hexane, Penhex and Straight-run (or unblended) gasoline.

Filter Calculation

In all actual filters the resistance to the flow
of filtrate varies with time as the precipitate
deposit on the filtering sand in sand bed
filters, or as the filter cake building up on
the cloth, screen or other filter medium. The
filter medium holds back the solids as the
filtrate passes through, and the filter cake
continues to increase in thickness, adding
its resistance to the flow of filtrate. This
action continues during filtration. At the end
of the filtration, the products are filtrate
porous filtrate cake, and fluid in the porous
of the cake.
During filtration the operation is laminar
flow and the linear velocity V are
v = (1/A) (d V/d t) = (K ρ Lw)/ L μ
= K (-Δ P) / L μ [1]
where
v linear velocity
V volume f iltrate
A area of filter media
(gc Dp
2 FRe)
K permeability of cake K = -----------
32 ff
L thickness of cake

t time of filtration
ΔP pressure drop through the cake
Relation between Volume of filtrate
and Time of filtration
In order to obtain an expression relating
filtration capacity (expressed as either the
quantity of filtrate V or the cake thickness L
) with the time of filtering t, it is necessary
to obtain the relation between the variable, L
and V . This can be done by making a
material balance between solid in slurry
filtered and the solid in cake.
Mass of solid in cake = mass of solids in
slurry.
(V+ε L A) ρ x
( 1- ε ) L A ρ s = [2]
(1-x)
where
L A volume of cake
( 1- ε ) L A volume of solid in cake
ρs density of solid in cake
ρ density of filtrate
x mass fraction of solid in slurry
ε porosity of cake
note: [(mass of filtrate/total mass) /(mass of solid
/total mass)] = (1-x)/x
Then,
mass of solid = mass of filtrate ( x / 1-x )
Then
ρ s (1-x) ( 1- ε ) - ρ x ε
V = [ ] L A [3]
ρ x
V ρ x
L = [ ] [4]
A [ρ s (1-x) ( 1- ε ) - ρ x ε]
According to equation [1]
(d V/d t) = K A (-Δ P) / L μ
K A2 [ρ s (1-x) (1- ε ) - ρ x ε ] (-ΔP)
∴(dV/dt)= [5]
μ V ρ x
This equation is an expression for the
instantaneous rate of filtration in term of
properties of the slurry, cake, quantity of
filtrate and pressure drop through the cake.
For a given slurry, the only variables subject
to
the control of the operator are pressure drop
(-ΔP), filtrate volume V, an time t. If we but :
μ ρ x
Cv = [62 K [ρ s (1-x) (1- ε ) - ρ x ε]
A2 (-ΔP)
∴ (d V/d t) = [7]
2 Cv V
If the cake porosity remains essentially
constant during filtration (as is true with a
so-called non-compressible cake and may
also occur for constant pressure drop
filtration in general).
Cv may be considered as a constant, and
equation [7] is easily integrated. For
constant pressure drop and constant
porosity, this integrates to:
Cv V2
t = [8]
A2 (-Δ P)]. absolute viscosity of filtrate

FILTERATION

Filtration may be de defined as the
separation of solids from liquids by passing
a suspension through a permeable medium,
which retains the particles. Filtration is
considers one of the most common
applications of the flow of fluids through
packed bed. As carried out in industrially, it
is exactly analogues to the filtration carried
out in the chemical laboratory using filter
paper in a funnel. In every case, the
separation is accomplished by forcing the
fluid through porous media (membrane). The
solid particles are trapped within the pores
of the membrane and build up as a layer on
the surface of this membrane. The fluid,
which may be either gas or liquid, passes
through the bed of solid and through the
retaining membrane.
Industrial filtration differs from laboratory
filtration only in the bulk of material
handled and in the necessity that it be
handled at low cost. Thus, to attain a
reasonable throughput with a moderatesized
filter, the pressure drop for flow may
be increased, or the resistance to flow may
be decreased. Most industrial equipment
decreases the flow resistance by making the
filtering area as large as possible without
increasing the overall size of the filter
apparatus.
The choice of filter equipment depends
largely upon economics, but the economic
advantages will very depending upon the
following:
1. Fluid viscosity, density, and chemical
reactivity2.
Solid particle size, size distribution,
shape of particles’ flocculation
tendencies and deformability.
3. Feed slurry concentration.
4. Amount of material to be handled.
5. Absolute and relative value of liquid
and solid particles.
6. Completeness of separation required.
7. Relative costs of labor, capital, and
power

OVERALL REFINERY FLOW

The crude oil is heated in a furnace and charged to an atmospheric distillation
tower, where it is separated into butanes and lighter wet gas, unstabilized
light naphtha, heavy naphtha, kerosine, atmospheric gas oil, and topped (reduced)
crude (ARC). The topped crude is sent to the vacuum distillation tower and separated
into vacuum gas oil stream and vacuum reduced crude bottoms (residua,
resid, or VRC).
The reduced crude bottoms (VRC) from the vacuum tower is then thermally
cracked in a delayed coker to produce wet gas, coker gasoline, coker gas oil, and
coke. Without a coker, this heavy resid would be sold for heavy fuel oil or (if
the crude oil is suitable) asphalt. Historically, these heavy bottoms have sold for
about 70 percent of the price of crude oilThe atmospheric and vacuum crude unit gas oils and coker
gas oil are used
as feedstocks for the catalytic cracking or hydrocracking units. These units crack
the heavy molecules into lower molecular weight compounds boiling in the gasoline
and distillate fuel ranges. The products from the hydrocracker are saturated.
The unsaturated catalytic cracker products are saturated and improved in quality
by hydrotreating or reforming.
The light naphtha streams from the crude tower, coker and cracking units
are sent to an isomerization unit to convert straight-chain paraffins into isomers
that have higher octane numbers.
The heavy naphtha streams from the crude tower, coker, and cracking units
are fed to the catalytic reformer to improve their octane numbers. The products
from the catalytic reformer are blended into regular and premium gasolines for
sale.
The wet gas streams from the crude unit, coker, and cracking units are
separated in the vapor recovery section (gas plant) into fuel gas, liquefied petroleum
gas (LPG), unsaturated hydrocarbons (propylene, butylenes, and pentenes),
normal butane, and isobutane. The fuel gas is burned as a fuel in refinery furnaces
and the normal butane is blended into gasoline or LPG. The unsaturated hydrocarbons
and isobutane are sent to the alkylation unit for processing.
The alkylation unit uses either sulfuric or hydrofluoric acid as catalyst to
react olefins with isobutane to form isoparaffins boiling in the gasoline range.
The product is called alkylate, and is a high-octane product blended into premium
motor gasoline and aviation gasoline.
The middle distillates from the crude unit, coker, and cracking units are
blended into diesel and jet fuels and furnace oils.
In some refineries, the heavy vacuum gas oil and reduced crude from paraffinic
or naphthenic base crude oils are processed into lubricating oils. After removing
the asphaltenes in a propane deasphalting unit, the reduced crude bottoms
is processed in a blocked operation with the vacuum gas oils to produce lubeoil
base stocks.
The vacuum gas oils and deasphalted stocks are first solvent-extracted to
remove the aromatic compounds and then dewaxed to improve the pour point.
They are then treated with special clays or high-severity hydrotreating to improve
their color and stability before being blended into lubricating oils.
Each refinery has its own unique processing scheme which is determined
by the process equipment available, crude oil characteristics, operating costs, and
product demand. The optimum flow pattern for any refinery is dictated by economic
considerations and no two refineries are identical in their operations..

Water Removal

Moisture must be removed from natural gas to reduce corrosion problems
and to prevent hydrate formation.
Hydrates are solid white compounds
formed from a physical-chemical reaction between hydrocarbons
and water under the high pressures and low temperatures used to transport
natural gas via pipeline. Hydrates reduce pipeline efficiency.
To prevent hydrate formation, natural gas may be treated with glycols,
which dissolve water efficiently. Ethylene glycol (EG), diethylene glycol
(DEG), and triethylene glycol (TEG) are typical solvents for water
removal. Triethylene glycol is preferable in vapor phase processes
because of its low vapor pressure, which results in less glycol loss. The
TEG absorber normally contains 6 to 12 bubble-cap trays to accomplish
the water absorption. However, more contact stages may be required to
reach dew points below –40°F. Calculations to determine the number of
trays or feet of packing, the required glycol concentration, or the glycol
circulation rate require vapor-liquid equilibrium data. Predicting the interaction
between TEG and water vapor in natural gas over a broad range
allows the designs for ultra-low dew point applications to be made.6
A computer program was developed by Grandhidsan et al., to estimate
the number of trays and the circulation rate of lean TEG needed to dry natual
gas. It was found that more accurate predictions of the rate could be
achieved using this program than using hand calculation.7
Figure 1-4 shows the Dehydrate process where EG, DEG, or TEG
could be used as an absorbent.8 One alternative to using bubble-cap trays
is structural packing, which improves control of mass transfer. Flow passages
direct the gas and liquid flows countercurrent to each other. The use
of structural packing in TEG operations has been reviewed by Kean et al.9
Another way to dehydrate natural gas is by injecting methanol into gas
lines to lower the hydrate-formation temperature below ambient.10 Water
can also be reduced or removed from natural gas by using solid adsorbents
such as molecular sieves or silica gel.
Condensable Hydrocarbon Recovery
Hydrocarbons heavier than methane that are present in natural gases
are valuable raw materials and important fuels. They can be recovered by
lean oil extraction. The first step in this scheme is to cool the treated gas
by exchange with liquid propane. The cooled gas is then washed with a
cold hydrocarbon liquid, which dissolves most of the condensable hydrocarbons.
The uncondensed gas is dry natural gas and is composed mainly
of methane with small amounts of ethane and heavier hydrocarbons. The
condensed hydrocarbons or natural gas liquids (NGL) are stripped from
the rich solvent, which is recycled. Table 1-2 compares the analysis of
natural gas before and after treatment.11 Dry natural gas may then be
used either as a fuel or as a chemical feedstock.
Another way to recover NGL is through cryogenic cooling to very low
temperatures (–150 to –180°F), which are achieved primarily through
adiabatic expansion of the inlet gas. The inlet gas is first treated to
remove water and acid gases, then cooled via heat exchange and refrigeration.
Further cooling of the gas is accomplished through turbo
expanders, and the gas is sent to a demethanizer to separate methane
from NGL. Improved NGL recovery could be achieved through better
control strategies and use of on-line gas chromatographic analysis.12