Note: Descriptions are shown in the official language in which they were submitted.
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I TARGETED HYDROGENATION HYDROCRACKING
2
3 FIELD OF THE INVENTION
4
This invention is directed to a partial conversion hydrocracking (HCR) unit,
in
6 which unconverted oil is fed to a Fluid Catalytic Cracking (FCC) unit.
7
8 BACKGROUND OF THE INVENTION
9
In the refining of crude oil, vacuum gas oil hydrotreaters and hydrocrackers
11 are employed to remove impurities such as sulfur, nitrogen and metals from
12 the feed. Typically, the middle distillate boiling material (boiling in the
range
13 from 250 F.-735 F.) from VGO hydrotreating or moderate severity
14 hydrocrackers does not meet the smoke point, the cetane number or the
aromatic specification required.
16
17 Removal of these impurities in subsequent hydroprocessing stages (often
18 known as upgrading), creates more valuable middle distillate products.
19 Hydroprocessing technology (which encompasses hydrotreating,
hydrocracking and hydrodewaxing processes) aims to increase the value of
21 the crude oil by fundamentally rearranging molecules. The end products are
22 also made more environmentally friendly.
23
24 In most cases, this middle distillate is separately upgraded by a middle
distillate hydrotreater or, alternatively, the middle distillate is blended
into the
26 general fuel oil pool or used as home heating oil. Recently hydroprocessing
27 schemes have been developed which permit the middle distillate to be
28 hydrotreated in the same high pressure loop as the vacuum gas oil
29 hydrotreating reactor or the moderate severity hydrocracking reactor. The
investment cost saving and/or utilities saving are significant since a
separate
31 middle distillate hydrotreater is not required.
32
33 There are U.S. patents which are directed to multistage hydroprocessing
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I within a single high pressure hydrogen loop. In U.S. Patent No. 6,797,154,
2 high conversion of heavy gas oils and the production of high quality middle
3 distillate products are possible in a single high-pressure loop with
reaction
4 stages operating at different pressure and conversion levels. The
flexibility
offered is great and allows the refiner to avoid decrease in product quality
6 while at the same time minimizing capital cost. Feeds with varying boiling
7 ranges are introduced at different sections of the process, thereby
minimizing
8 the consumption of hydrogen and reducing capital investment.
9
U.S. Pat. No. 6,787,025 also discloses multi-stage hydroprocessing for the
11 production of middle distillates. A major benefit of this invention is the
12 potential for simultaneously upgrading difficult cracked stocks such as
Light
13 Cycle Oil, Light Coker Gas Oil and Visbroken Gas Oil or Straight-Run
14 Atmospheric Gas Oils utilizing the high-pressure environment required for
mild hydrocracking.
16
17 U.S. Pat. No. 7,238,277 provides very high to total conversion of heavy
oils to
18 products in a single high-pressure loop, using multiple reaction stages.
The
19 second stage or subsequent stages may be a combination of co-current and
counter-current operation. The benefits of this invention include conversion
of
21 feed to useful products at reduced operating pressures using lower catalyst
22 volumes. Lower hydrogen consumption also results. A minimal amount of
23 equipment is employed. Utility consumption is also minimized.
24
U.S. Publication 20050103682 relates to a multi-stage process for
26 hydroprocessing gas oils. Preferably, each stage possesses at least one
27 hydrocracking zone. The second stage and any subsequent stages possess
28 an environment having a low heteroatom content. Light products, such as
29 naphtha, kerosene and diesel, may be recycled from fractionation (along
with
light products from other sources) to the second stage (or a subsequent
31 stage) in order to produce a larger yield of lighter products, such as gas
and
32 naphtha. Pressure in the zone or zones subsequent to the initial zone is
from
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1 500 to 1000 psig lower than the pressure in the initial zone, in order to
provide
2 cost savings and minimize overcracking.
3
4 Most refineries run the FCC unit at full capacity for optimal asset
utilization.
During planned and/or unplanned shutdown of Residue Desulfurization unit(s)
6 feeding FCC unit, it is desirable to reduce the conversion in the FCC feed
7 hydrocracker in order to maximize the feed to FCC unit. The patents
8 disclosed above do not address the following issues:
9 1. Production of on-specification Jet and Diesel products during low
conversion HCR operation.
11 2. Avoidance of undesirable over-saturation of the unconverted oil
12 (UCO) from the HCR unit feeding FCC unit and reduce hydrogen
13 consumption. Normally, further aromatic saturation of the middle
14 distillate products from a low conversion HCR is achieved in a
separate Post Treatment unit.
16
17 SUMMARY OF THE INVENTION
18
19 A new process scheme has been developed to design a partial conversion
hydrocracking (HCR) unit, feeding the unconverted oil to a FCC unit. The
21 steps of this invention are summarized as follows:
22
23 A method for hydroprocessing a hydrocarbon feedstock, said method
24 employing multiple hydroprocessing zones within a single reaction loop,
each zone having one or more catalyst beds, comprising the following
26 steps:
27
28 (a) passing a hydrocarbonaceous feedstock to a first
29 hydroprocessing zone having one or more beds containing
hydroprocessing catalyst, the hydroprocessing zone being
31 maintained at hydroprocessing conditions, wherein the
32 feedstock is contacted with catalyst and hydrogen;
33
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1 (b) passing the effluent of step (a) directly to a hot high pressure
2 separator, wherein the effluent is separated to produce a vapor
3 stream comprising hydrogen, hydrocarbonaceous compounds
4 boiling at a temperature below the boiling range of the
hydrocarbonaceous feedstock, hydrogen sulfide and ammonia
6 and a liquid stream comprising hydrocarbonaceous
7 compounds boiling approximately in the range of said
8 hydrocarbonaceous feedstock;
9
(c) passing the vapor stream of step (b) after cooling and partial
11 condensation, to a hot high pressure separator where it is
12 flashed, thereby producing an overhead vapor stream and a
13 liquid stream, wherein the liquid stream, which comprises
14 hydrotreated hydrocarbons in the middle distillate range, is
passed to a second hydroprocessing zone;
16
17 (d) passing the overhead vapor stream from the hot high
18 pressure separator of step (c), after cooling and contact with
19 water, said vapor stream comprising hydrogen, ammonia,
hydrogen sulfide, light gases and naphtha, to a cold high
21 pressure separator, where hydrogen, hydrogen sulfide, and
22 light hydrocarbonaceous gases are removed overhead,
23 ammonia is removed from the cold high pressure separator as
24 ammonium bisulfide in the sour water stripper, and naphtha
and middle distillates are passed to fractionation
26
27 (e) passing the liquid stream from the hot high pressure separator
28 of step (b) to a hot low pressure separator, where it is flashed
29 to produce an overhead stream comprising gases and a liquid
stream comprising unconverted oil;
31
32 (f) passing the liquid stream of step (e) which comprises
33 unconverted oil, to a steam stripper, where lighter material is
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1 removed overhead as a vapor stream, and a liquid stream,
2 which comprises stripped unconverted oil, is recovered.
3
4 BRIEF DESCRIPTION OF THE FIGURE
6 The Figure illustrates the flow scheme of the current invention.
7
8
9 DETAILED DESCRIPTION OF THE INVENTION
11 Feeds
12 A wide variety of hydrocarbon feeds may be used in the instant invention.
13 Typical feedstocks include any heavy or synthetic oil fraction or process
14 stream having a boiling point above 392 F. (200 C.). Such feedstocks
include vacuum gas oils (VGO), heavy coker gas oil (HCGO), heavy
16 atmospheric gas oil (AGO), light coker gas oil (LCGO), visbreaker gas oil
17 (VBGO), demetallized oils (DMO), vacuum residua, atmospheric residua,
18 deasphalted oil (DAO), Fischer-Tropsch streams, Light Cycle Oil, Light
Cycle
19 Gas Oil and other FCC product streams.
21 Products
22 The process of this invention is especially useful in the production of
middle
23 distillate fractions boiling in the range of about 250-700 F (121-371 C). A
24 middle distillate fraction is defined as having an approximate boiling
range
from about 250 to 700 F. At least 75 vol.%, preferably 85 vol.% of the
26 components of the middle distillate have a normal boiling point of greater
than
27 250 F. At least about 75 vol.%, preferably 85 vol.% of the components of
the
28 middle distillate have a normal boiling point of less than 700 F. The term
29 "middle distillate" includes the diesel, jet fuel and kerosene boiling
range
fractions. The kerosene or jet fuel boiling point range refers to the range
31 between 280 and 525 F (138-274 C). The term "diesel boiling range" refers
to
32 hydrocarbons boiling in the range from 250 to 700 F (121-371 C).
33
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1 Gasoline or naphtha may also be produced in the process of this invention.
2 Gasoline or naphtha normally boils in the range below 400 F. (204 C), or C5
to
3 400 F. Boiling ranges of various product fractions recovered in any
particular
4 refinery will vary with such factors as the characteristics of the crude oil
source, local refinery markets and product prices.
6
7 Conditions
8 "Hydroprocessing conditions" is a general term which refers primarily in
this
9 application to hydrocracking or hydrotreating.
11 Hydrotreating conditions include a reaction temperature between
12 400 F.-950 F. (204 C.-482 C.), preferably 600 F.-850 F. (315 C-464 C); a
13 pressure between 500 to 5000 psig (pounds per square inch gauge)
14 (3.5-34.6 MPa), preferably 1000 to 3000 psig (7.0-20.8 MPa): a feed rate
(LHSV) of 0.3 hr-1 to 20 hr-1 (v/v) preferably from 0.5 to 4.0; and overall
16 hydrogen consumption 300 to 2000 SCF per barrel of liquid hydrocarbon feed
17 (63.4-356 m3/m3 feed).
18
19 Typical hydrocracking conditions include a reaction temperature of from
400 F.-950 F. (204 C.-510 C.), preferably 650 F.-850 F. (315 C.-454 C.).
21 Reaction pressure ranges from 500 to 5000 psig (3.5-4.5 MPa), preferably
22 1000-3000 psig (7.0-20.8 MPa). LHSV ranges from 0.1 to 15 hr-1 (v/v),
23 preferably 0.5 to 5.0 hr-1. Hydrogen consumption ranges from 500 to 2500
24 SCF per barrel of liquid hydrocarbon feed (89.1-445 m3H2/m3 feed).
26 Catalyst
27 A hydroprocessing zone may contain only one catalyst, or several catalysts
in
28 combination.
29
The hydrocracking catalyst generally comprises a cracking component, a
31 hydrogenation component and a binder. Such catalysts are well known in the
32 art. The cracking component may include an amorphous silica/alumina phase
33 and/or a zeolite, such as a Y-type or USY zeolite. Catalysts having high
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I cracking activity often employ REX, REY and USY zeolites. The binder is
2 generally silica or alumina. The hydrogenation component will be a Group VI,
3 Group VII, or Group VIII metal or oxides or sulfides thereof, preferably one
or
4 more of molybdenum, tungsten, cobalt, or nickel, or the sulfides or oxides
thereof. If present in the catalyst, these hydrogenation components generally
6 make up from about 5% to about 40% by weight of the catalyst. Alternatively,
7 platinum group metals, especially platinum and/or palladium, may be present
8 as the hydrogenation component, either alone or in combination with the base
9 metal hydrogenation components molybdenum, tungsten, cobalt, or nickel. If
present, the platinum group metals will generally make up from about 0.1% to
11 about 2% by weight of the catalyst.
12
13 Hydrotreating catalyst is typically a composite of a Group VI metal or
14 compound thereof, and a Group VIII metal or compound thereof supported on
a porous refractory base such as alumina. Examples of hydrotreating
16 catalysts are alumina supported cobalt-molybdenum, nickel sulfide, nickel-
17 tungsten, cobalt-tungsten and nickel-molybdenum. Typically, such
18 hydrotreating catalysts are presulfided.
19
In some cases, high activity hydrotreating catalyst suitable for high levels
of
21 hydrogenation, is employed. Such catalysts have high surface areas (greater
22 than 140 m<sup>2</sup> /gm) and high densities (0.7-0.95 gm/cc). The high surface
23 area increases reaction rates due to generally increased dispersion of the
24 active components. Higher density catalysts allow one to load a larger
amount of active metals and promoter per reactor volume, a factor which is
26 commercially important. Since deposits of coke are thought to cause the
27 majority of the catalyst deactivation, the catalyst pore volume should be
28 maintained at a modest level (0.4-0.6). A high activity catalyst is at
times
29 desired in order to reduce the required operating temperatures. High
temperatures lead to increased coking.
31
32
33
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1 Description of the preferred embodiment
2 Please refer to the Figure:
3 In this process scheme, fresh feed (Stream 9) is passed to the top of fixed
4 bed hydrotreater reactor 10. Hydrogen passes through stream 1. Stream 29
is a sidestream from stream 1. From stream 29, streams 3 and 4 add
6 hydrogen in between the first and second beds, and second and third beds of
7 reactor 10 respectively. Hydrotreater 10 is loaded with a high activity
8 hydrotreating catalyst, where most of the feed impurities (heteroatoms) such
9 as nitrogen, sulfur, etc. are removed and some degree of aromatic saturation
is achieved.
11
12 The hydrotreated reactor effluent (stream 12) exchanges heat in exchanger 5
13 with the reactor feed (stream 2 prior to entering the exchanger 5 and
stream 9
14 upon leaving the exchanger 5). Stream 12 is flashed in hot high pressure
separator 40 at high temperature and pressure conditions to recover most of
16 the unconverted oil (UCO) components in the liquid phase (stream 13). Vapor
17 leaves separator 40 overhead in line 22, and heat is exchanged with
18 hydrogen stream 31 in exchanger 25. Stream 22, which is made up of more
19 than 85wt% diesel and lighter material, preheats the fractionator feed (not
shown in the Figure) and generates high pressure steam. Stream 22 is finally
21 cooled to about 200 C in the hot high pressure separator vapor/recycle gas
22 exchanger 25. Stream 22 is then flashed in hot high pressure separator 50.
23 At these relatively high pressure and low temperature conditions, most of
the
24 hydrotreated jet and diesel range material is recovered as liquid stream 27
at
high pressure, which is pumped(pump 35) to the feedstream (stream 11) ,
26 which passes to hydrocracking reactor 20, for further processing. The
27 overhead vapor from the hot high pressure separator 50, stream 23, is then
28 cooled in an air cooler (not shown) before entering a cold high pressure
29 separator (not shown). The overhead vapor stream, stream 23, comprises
hydrogen, ammonia, and hydrogen sulfide, along with light gases and
31 naphtha. In the cold high pressure separator (not shown) hydrogen, hydrogen
32 sulfide, and light hydrocarbonaceous gases are removed overhead, ammonia
33 is removed from the cold high pressure separator as ammonium bisulfide in
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1 the sour water stripper. Naphtha and middle distillates are passed to
2 fractionation.
3
4 Stream 13 passes to hot low pressure separator 60, where it is flashed.
Vapor is removed as stream 28. The hot low pressure separator bottoms are
6 removed as stream 73 and passed to UCO (unconverted oil) stripper 30. The
7 material of stream 73 is stream stripped in stripper 30 to recover any
lighter
8 material in the UCO stream. Lighter material is removed as stream 26. Jet
9 and diesel range material is withdrawn as a side draw 17 from the column.
Side draw 17 combines with stream 19, stripper bottoms 16 (UCO) to become
11 stream 19. A side stream 18 may be taken from bottoms stream 16. Stream
12 19, recycle oil, is pumped, via pump 45, to storage drum 70. The recycle
oil
13 exits storage drum 70 through stream 21 and is pumped, by means of pump
14 55, to stream 11. Stream 11 is heated in exchanger 15 prior to entering
hydrocracking reactor 20 for further aromatic saturation. The overhead liquid
16 stream 26 from the UCO stripper 30 is sent to the main product stripper,
and
17 the offgas is sent to fuel gas (not shown).
18
19 The hydrotreated, stripped UCO (stream 16) from the bottom of the UCO
stripper, is an excellent quality FCC feed. At this point, a part of stripped
21 unconverted oil (stream 18) is sent out as FCC feed. Further saturation of
the
22 FCC feed is thus avoided. Only a limited portion of the UCO (mixed with
23 stream 19, is passed to hydrocracker 20 for further saturation of aromatic
24 components and conversion to distillate products. The amount recycled back
is based on the desired overall conversion level.
26
27 The second stage hydrocracking reactor 20 is loaded with hydrocracking
28 catalyst and operates under a clean environment (no heteroatoms), ideally
29 selectively converting the UCO to desired products and further saturating
the
aromatic components to achieve required jet and diesel properties at different
31 conversion levels. Stream 32 is a sidestream from stream 1. From stream 32,
32 streams 7 and 8 add hydrogen in between the first and second beds and
33 second and third beds of reactor 20 respectively.
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1 Both the hydrotreating reactor 10 and hydrocracking reactor 20 are designed
2 for the maximum conversion desired. During lower conversion operation, the
3 hydrotreating reaction is maintained at the same temperature as the highest
4 conversion case in order to achieve target denitrification and
desulfurization.
The temperature of the hydrocracking reactor is reduced at lower
6 conversions.
7
8 The effluent (stream 72) of second stage hydrocracking reactor 20 is cooled
9 (in exchanger 15) to preheat second stage reactor feed (stream 11)
fractionator feed and cold low pressure separator liquid stream. Stream 72,
11 now renumbered stream 74, combines with hot high pressure separator vapor
12 stream 23 for further cooling and the removal of high pressure recycle gas.
13 The hydrocarbon liquid from the cold high pressure separator (not shown) is
14 sent to the fractionation section (not shown) for product recovery.
16 EXAMPLE
17
18 The following table highlights the advantages of the process scheme of this
19 invention over a conventional process scheme for a 65,000 BPOD (barrel per
operating day) hydrocracking unit: The table indicates that there is no need
in
21 the current invention for post treatment in order to reach desired product
22 specifications. Furthermore, less hydrogen is consumed in the scheme of the
23 current invention than in the conventional case.
Conventional Process Scheme New Process Scheme
Process Scheme Single Stage Once-Through Targeted-Hydrogenation Hydrocracking
Fresh Feed Rate, BPSD 65,000 65,000
Overall LHSV, 1 hr 0.7-0.9 0.7-0.9
Product Yield Base Similar to Base case
Jet & Diesel Quality Needs post treatment for aromatic saturation On
specification product at all desired
at low conversion conversions:
Jet : S<10 ppm; Smoke Point>24mm
Diesel : S<10 ppm;Cetane Index>50
Chemical H2 Consumption Base Base - 160 SCFB at 60% cony.
Base - 100 SCFB at 40% cony.
Base - 50 SCFB at 30% cony.
24
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