U.S. patent application number 11/894123 was filed with the patent office on 2009-02-26 for olefin production utilizing whole crude oil/condensate feedstock and selective hydrocracking.
Invention is credited to Richard B. Halsey.
Application Number | 20090050523 11/894123 |
Document ID | / |
Family ID | 40381165 |
Filed Date | 2009-02-26 |
United States Patent
Application |
20090050523 |
Kind Code |
A1 |
Halsey; Richard B. |
February 26, 2009 |
Olefin production utilizing whole crude oil/condensate feedstock
and selective hydrocracking
Abstract
A method for thermally cracking a feed composed of whole crude
oil and/or natural gas condensate using a vaporizer to vaporize the
feed before cracking same, recovering pyrolysis gas oil from the
cracked feed, subjecting the recovered pyrolysis gas oil to
hydrocracking to form a paraffinic hydrocracked product, and
passing at least part of the hydrocracked product to the vaporizer
as additional thermal cracking feed.
Inventors: |
Halsey; Richard B.;
(Houston, TX) |
Correspondence
Address: |
LyondellBasell Industries
3801 WEST CHESTER PIKE
NEWTOWN SQUARE
PA
19073
US
|
Family ID: |
40381165 |
Appl. No.: |
11/894123 |
Filed: |
August 20, 2007 |
Current U.S.
Class: |
208/68 |
Current CPC
Class: |
C10G 9/00 20130101; C10G
69/06 20130101; C10G 47/00 20130101 |
Class at
Publication: |
208/68 |
International
Class: |
C10G 69/04 20060101
C10G069/04 |
Claims
1. In a method for operating an olefin production plant that
employs a pyrolysis furnace to severely thermally crack hydrocarbon
containing material for subsequent processing of the thus cracked
product in said plant which method of plant operation includes 1)
providing at least one of whole crude oil and natural gas
condensate as said hydrocarbon containing material, 2) submitting
said whole crude/condensate feed to a vaporization step wherein
said feed is substantially vaporized, and 3) feeding said
substantially vaporized feed to said pyrolysis furnace, said plant
further employing an oil quench step on said cracked material
product to form a pyrolysis gas oil stream, the improvement
comprising passing at least part of said pyrolysis gas oil stream
to a hydrocracking step, hydrocracking said pyrolysis gas oil to
form a hydrocracked product, and returning at least part of said
hydrocracked product as feed to said vaporization step.
2. The method of claim 1 wherein a liquid stream is removed from
said vaporization step and passed as feed to said hydrocracking
step.
3. The method of claim 1 wherein said pyrolysis gas oil stream
boils in the range of from about 380 to about 700 F.
4. The method of claim 1 wherein said hydrocracking step is carried
out at a temperature of from about 640 to about 840 F, pressure of
from about 1,200 to about 5,000 psig, weight hourly space velocity
of from about 0.1 to about 5, and hydrogen flow of from about 100
to about 200 cubic meters per ton of hydrocarbon feed.
Description
BACKGROUND OF INVENTION
[0001] 1. Field of Invention
[0002] This invention relates to the formation of olefins by
thermal cracking of liquid whole crude oil and/or condensate
derived from natural gas in a manner that is integrated with a
hydrocracking operation. More particularly, this invention relates
to utilizing whole crude oil and/or natural gas condensate as a
feedstock for an olefin production plant that employs hydrocarbon
thermal cracking in a pyrolysis furnace in combination with a
hydrocracking operation in a manner that reduces the sulfur content
of the products of that plant.
[0003] 2. Description of the Prior Art
[0004] Thermal (pyrolysis) cracking of hydrocarbons is a
non-catalytic petrochemical process that is widely used to produce
olefins such as ethylene, propylene, butenes, butadiene, and
aromatics such as benzene, toluene, and xylenes.
[0005] Basically, a hydrocarbon feedstock, such as naphtha, gas oil
or other fractions of whole crude oil that are produced by
distilling or otherwise fractionating whole crude oil, is mixed
with steam which serves as a diluent to keep the hydrocarbon
molecules separated. The steam/hydrocarbon mixture is preheated to
from about 900 to about 1,000 degrees Fahrenheit (F), and then
enters the reaction zone where it is very quickly heated to a
severe hydrocarbon thermal cracking temperature in the range of
from about 1,450 to about 1,550 F. Thermal cracking is accomplished
without the aid of any catalyst.
[0006] This process is carried out in a pyrolysis furnace (steam
cracker) at pressures in the reaction zone ranging from about 10 to
about 30 psig. Pyrolysis furnaces have internally thereof a
convection section and a radiant section. Preheating is
accomplished in the convection section, while severe cracking
occurs in the radiant section.
[0007] After severe thermal cracking, the effluent from the
pyrolysis furnace contains gaseous hydrocarbons of great variety,
e.g., from one to thirty-five carbon atoms per molecule. These
gaseous hydrocarbons can be saturated, monounsaturated, and
polyunsaturated, and can be aliphatic, alicyclics, and/or aromatic.
The cracked gas also contains significant amounts of molecular
hydrogen (hydrogen).
[0008] Thus, conventional steam (thermal) cracking, as carried out
in a commercial olefin production plant, employs a fraction of
whole crude and totally vaporizes that fraction while thermally
cracking same.
[0009] The cracked product is then further processed in the olefin
production plant to produce, as products of the plant, various
separate individual streams of high purity such as hydrogen,
ethylene, propylene, mixed hydrocarbons having four carbon atoms
per molecule, fuel oil, and pyrolysis gasoline. Each separate
individual stream aforesaid is a valuable commercial product in its
own right. Thus, an olefin production plant currently takes a part
(fraction) of a whole crude stream and generates therefrom a
plurality of separate, valuable products.
[0010] Natural gas and whole crude oil(s) were formed naturally in
a number of subterranean geologic formations (formations) of widely
varying porosities. Many of these formations were capped by
impervious layers of rock. Natural gas and whole crude oil (crude
oil) also accumulated in various stratigraphic traps below the
earth's surface. Vast amounts of both natural gas and/or crude oil
were thus collected to form hydrocarbon bearing formations at
varying depths below the earth's surface. Much of this natural gas
was in close physical contact with crude oil, and, therefore,
absorbed a number of lighter molecules from the crude oil.
[0011] When a well bore is drilled into the earth and pierces one
or more of such hydrocarbon bearing formations, natural gas and/or
crude oil can be recovered through that well bore to the earth's
surface.
[0012] The terms "whole crude oil" and "crude oil" as used herein
means liquid (at normally prevailing conditions of temperature and
pressure at the earth's surface) crude oil as it issues from a
wellhead separate from any natural gas that may be present, and
excepting any treatment such crude oil may receive to render it
acceptable for transport to a crude oil refinery and/or
conventional distillation in such a refinery. This treatment would
include such steps as desalting. Thus, it is crude oil that is
suitable for distillation or other fractionation in a refinery, but
which has not undergone any such distillation or fractionation. It
could include, but does not necessarily always include, non-boiling
entities such as asphaltenes or tar. As such, it is difficult if
not impossible to provide a boiling range for whole crude oil.
Accordingly, whole crude oil could be one or more crude oils
straight from an oil field pipeline and/or conventional crude oil
storage facility, as availability dictates, without any prior
fractionation thereof.
[0013] Natural gas, like crude oil, can vary widely in its
composition as produced to the earth's surface, but generally
contains a significant amount, most often a major amount, i.e.,
greater than about 50 weight percent (wt. %), methane. Natural gas
often also carries minor amounts (less than about 50 wt. %), often
less than about 20 wt. %, of one or more of ethane, propane,
butane, nitrogen, carbon dioxide, hydrogen sulfide, and the like.
Many, but not all, natural gas streams as produced from the earth
can contain minor amounts (less than about 50 wt. %), often less
than about 20 wt. %, of hydrocarbons having from 5 to 12,
inclusive, carbon atoms per molecule (C5 to C12) that are not
normally gaseous at generally prevailing ambient atmospheric
conditions of temperature and pressure at the earth's surface, and
that can condense out of the natural gas once it is produced to the
earth's surface. All wt. % are based on the total weight of the
natural gas stream in question.
[0014] When various natural gas streams are produced to the earth's
surface, a hydrocarbon composition often naturally condenses out of
the thus produced natural gas stream under the then prevailing
conditions of temperature and pressure at the earth's surface where
that stream is collected. There is thus produced a normally liquid
hydrocarbonaceous condensate separate from the normally gaseous
natural gas under the same prevailing conditions. The normally
gaseous natural gas can contain methane, ethane, propane, and
butane. The normally liquid hydrocarbon fraction that condenses
from the produced natural gas stream is generally referred to as
"condensate," and generally contains molecules heavier than butane
(C5 to about C20 or slightly higher). After separation from the
produced natural gas, this liquid condensate fraction is processed
separately from the remaining gaseous fraction that is normally
referred to as natural gas.
[0015] Thus, condensate recovered from a natural gas stream as
first produced to the earth's surface is not the exact same
material, composition wise, as natural gas (primarily methane).
Neither is it the same material, composition wise, as crude oil.
Condensate occupies a niche between normally gaseous natural gas
and normally liquid whole crude oil. Condensate contains
hydrocarbons heavier than normally gaseous natural gas, and a range
of hydrocarbons that are at the lightest end of whole crude
oil.
[0016] Condensate, unlike crude oil, can be characterized by way of
its boiling point range. Condensates normally boil in the range of
from about 100 to about 650F. With this boiling range, condensates
contain a wide variety of hydrocarbonaceous materials. These
materials can include compounds that make up fractions that are
commonly referred to as naphtha, kerosene, diesel fuel(s), and gas
oil (fuel oil, furnace oil, heating oil, and the like). Naphtha and
associated lighter boiling materials (naphtha) are in the C5 to
C10, inclusive, range, and are the lightest boiling range fractions
in condensate, boiling in the range of from about 100 to about 400
F. Petroleum middle distillates (kerosene, diesel, atmospheric gas
oil) are generally in the C10 to about C20 or slightly higher
range, and generally boil, in their majority, in the range of from
about 350 to about 650 F. They are, individually and collectively,
referred to herein as "distillate" or "distillates." It should be
noted that various distillate compositions can have a boiling point
lower than 350 F and/or higher than 650 F, and such distillates are
included in the 350-650 F range aforesaid, and in this
invention.
[0017] The starting feedstock for a conventional olefin production
plant, as described above, has first been subjected to substantial,
expensive processing before it reaches that plant. Normally,
condensate and whole crude oil is distilled or otherwise
fractionated in a crude oil refinery into a plurality of fractions
such as gasoline, naphtha, kerosene, gas oil (vacuum or
atmospheric) and the like, including, in the case of crude oil and
not natural gas, a high boiling residuum. Thereafter any of these
fractions, other than the residuum, are normally passed to an
olefin production plant as the starting feedstock for that
plant.
[0018] It would be desirable to be able to forego the capital and
operating cost of a refinery distillation unit (whole crude
processing unit) that processes condensate and/or crude oil to
generate a hydrocarbonaceous fraction that serves as the starting
feedstock for conventional olefin producing plants. However, the
prior art, until recently, taught away from even hydrocarbon cuts
(fractions) that have too broad a boiling range distribution. For
example, see U.S. Pat. No. 5,817,226 to Lenglet.
[0019] Recently, U.S. Pat. No. 6,743,961 (hereafter "USP '961")
issued to Donald H. Powers. This patent relates to cracking whole
crude oil by employing a vaporization/mild cracking zone that
contains packing. This zone is operated in a manner such that the
liquid phase of the whole crude that has not already been vaporized
is held in that zone until cracking/vaporization of the more
tenacious hydrocarbon liquid components is maximized. This allows
only a minimum of solid residue formation which residue remains
behind as a deposit on the packing. This residue is later burned
off the packing by conventional steam air decoking, ideally during
the normal furnace decoking cycle, see column 7, lines 50-58 of
that patent. Thus, the second zone 9 of that patent serves as a
trap for components, including hydrocarbonaceous materials, of the
crude oil feed that cannot be cracked or vaporized under the
conditions employed in the process, see column 8, lines 60-64 of
that patent.
[0020] Still more recently, U.S. Pat. No. 7,019,187 issued to
Donald H. Powers. This patent is directed to the process disclosed
in USP '961, but employs a mildly acidic cracking catalyst to drive
the overall function of the vaporization/mild cracking unit more
toward the mild cracking end of the vaporization (without prior
mild cracking)-mild cracking (followed by vaporization)
spectrum.
[0021] The disclosures of the foregoing patents, in their entirety,
are incorporated herein by reference.
[0022] One skilled in the art would first subject the feed to be
cracked to a conventional distillation column to distill the
distillate from the cracking feed. This approach would require a
substantial amount of capital to build the column and outfit it
with the normal reboiler and overhead condensation equipment that
goes with such a column. In this invention, a splitter is employed
in a manner such that much greater energy efficiency at lower
capital cost is realized over a distillation column. By use of this
splitter, reboilers, overhead condensers, and related distillation
column equipment are eliminated without eliminating the functions
thereof, thus saving considerably in capital costs. Further, this
invention exhibits much greater energy efficiency in operation than
a distillation column because the extra energy that would be
required by a distillation column is not required by this invention
since this invention instead utilizes for its splitting function
the energy that is already going to be expended in the operation of
the cracking furnace (as opposed to energy expended to operate a
standalone distillation column upstream of the cracking furnace),
and the vapor product of the splitter goes directly to the cracking
section of the furnace.
[0023] Finally, this invention integrates the foregoing splitter
process with conventional hydrocracking.
SUMMARY OF THE INVENTION
[0024] In accordance with this invention, there is provided a
process for utilizing whole crude oil and/or natural gas condensate
as the feedstock for an olefin plant, as defined above, in
combination with a selective hydrocracking process in a manner
which increases the productivity of the cracking process and at the
same time reduces the sulfur content of various products recovered
from that olefin plant.
DESCRIPTION OF THE DRAWING
[0025] FIG. 1 shows a simplified flow sheet for a process within
this invention.
DETAILED DESCRIPTION OF THE INVENTION
[0026] The terms "hydrocarbon," "hydrocarbons," and
"hydrocarbonaceous" as used herein do not mean materials strictly
or only containing hydrogen atoms and carbon atoms. Such terms
include materials that are hydrocarbonaceous in nature in that they
primarily or essentially are composed of hydrogen and carbon atoms,
but can contain other elements such as oxygen, sulfur, nitrogen,
metals, inorganic salts, and the like, even in significant
amounts.
[0027] An olefin producing plant useful with this invention would
include a pyrolysis (thermal cracking) furnace for initially
receiving and cracking the feed. Pyrolysis furnaces for steam
cracking of hydrocarbons heat by means of convection and radiation,
and comprise a series of preheating, circulation, and cracking
tubes, usually bundles of such tubes, for preheating, transporting,
and cracking the hydrocarbon feed. The high cracking heat is
supplied by burners disposed in the radiant section (sometimes
called "radiation section") of the furnace. The waste gas from
these burners is circulated through the convection section of the
furnace to provide the heat necessary for preheating the incoming
hydrocarbon feed. The convection and radiant sections of the
furnace are joined at the "cross-over," and the tubes referred to
hereinabove carry the hydrocarbon feed from the interior of one
section to the interior of the next.
[0028] Cracking furnaces are designed for rapid heating in the
radiant section starting at the radiant tube (coil) inlet where
reaction velocity constants are low because of low temperature.
Most of the heat transferred simply raises the hydrocarbons from
the inlet temperature to the reaction temperature. In the middle of
the coil, the rate of temperature rise is lower but the cracking
rates are appreciable.
[0029] At the coil outlet, the rate of temperature rise increases
somewhat but not as rapidly as at the inlet.
[0030] Steam dilution of the feed hydrocarbon lowers the
hydrocarbon partial pressure, enhances olefin formation, and
reduces any tendency toward coke formation in the radiant
tubes.
[0031] Radiant coils in the furnace heat the hydrocarbons to from
about 1,450.degree. F. to about 1,550.degree. F. and thereby
subject the hydrocarbons to severe cracking.
[0032] Hydrocarbon feed to the furnace is preheated to from about
900.degree. F. to about 1,000.degree. F. in the convection section
by convectional heating from the flue gas from the radiant section,
steam dilution of the feed in the convection section, or the like.
After preheating in a conventional commercial furnace, the feed is
ready for entry into the radiant section.
[0033] The cracked gaseous hydrocarbons leaving the radiant section
are rapidly reduced in temperature to prevent destruction of the
cracking pattern. Cooling of the cracked gases before further
processing of same downstream in the olefin production plant
recovers a large amount of energy as high pressure steam for re-use
in the furnace and/or olefin plant. This is often accomplished with
the use of transfer-line exchangers that are well known in the
art.
[0034] Downstream processing of the cracked hydrocarbons issuing
from the furnace varies considerably, and particularly based on
whether the initial hydrocarbon feed was a gas or a liquid. Since
this invention uses whole crude oil and/or liquid natural gas
condensate as a feed, downstream processing herein will be
described for a liquid fed olefin plant. Downstream processing of
cracked gaseous hydrocarbons from liquid feedstock, naphtha through
gas oil for the prior art, and crude oil and/or condensate for this
invention, is more complex than for gaseous feedstock because of
the heavier hydrocarbon components present in the liquid
feedstocks.
[0035] With a liquid hydrocarbon feedstock downstream processing,
although it can vary from plant to plant, typically employs
termination of the cracking function by a transfer-line exchanger
followed by oil and water quenches of the furnace effluent.
Thereafter, the cracked hydrocarbon stream is subjected to
fractionation to remove heavy liquids, followed by compression of
uncondensed hydrocarbons, and acid gas and water removal therefrom.
Various desired products are then individually separated, e.g.,
ethylene, propylene, a mixture of hydrocarbons having four carbon
atoms per molecule, fuel oil, pyrolysis gasoline, and a high purity
hydrogen stream.
[0036] In accordance with this invention, a process is provided
which utilizes crude oil and/or condensate liquid that has not been
subjected to fractionation, distillation, and the like, as the
primary (initial) feedstock for the olefin plant pyrolysis furnace
in whole or in substantial part. By so doing, this invention
eliminates the need for costly distillation of the condensate into
various fractions, e.g., from naphtha, kerosene, gas oil, and the
like, to serve as the primary feedstock for a furnace as is done by
the prior art as first described hereinabove.
[0037] This invention can be carried out using, for example, the
apparatus disclosed in USP '961. Thus, this invention is carried
out using a self-contained vaporization facility that operates
separately from and independently of the convection and radiant
sections of the furnace. When employed outside the furnace, crude
oil and/or condensate primary feed is preheated in the convection
section of the furnace, passed out of the convection section and
the furnace to a standalone vaporization facility. The vaporous
hydrocarbon product of this standalone facility is then passed back
into the furnace to enter the radiant section thereof. Preheating
can be carried out other than in the convection section of the
furnace if desired or in any combination inside and/or outside the
furnace and still be within the scope of this invention.
[0038] The vaporization unit of this invention (for example section
3 of USP '961) receives the condensate feed that may or may not
have been preheated, for example, from about ambient to about 350F,
preferably from about 200 to about 350F. This is a lower
temperature range than what is required for complete vaporization
of the feed. Any preheating preferably, though not necessarily,
takes place in the convection section of the same furnace for which
such condensate is the primary feed.
[0039] Thus, the first zone in the vaporization operation step of
this invention (zone 4 in USP '961) employs vapor/liquid separation
wherein vaporous hydrocarbons and other gases, if any, in the
preheated feed stream are separated from those distillate
components that remain liquid after preheating. The aforesaid gases
are removed from the vapor/liquid separation section and passed on
to the radiant section of the furnace.
[0040] Vapor/liquid separation in this first, e.g., upper, zone
knocks out distillate liquid in any conventional manner, numerous
ways and means of which are well known and obvious in the art.
[0041] Liquid thus separated from the aforesaid vapors moves into a
second, e.g., lower, zone (zone 9 in USP '961). This can be
accomplished by external piping. Alternatively this can be
accomplished internally of the vaporization unit. The liquid
entering and traveling along the length of this second zone meets
oncoming, e.g., rising, steam. This liquid, absent the removed
gases, receives the full impact of the oncoming steam's thermal
energy and diluting effect.
[0042] This second zone can carry at least one liquid distribution
device such as a perforated plate(s), trough distributor, dual flow
tray(s), chimney tray(s), spray nozzle(s), and the like.
[0043] This second zone can also carry in a portion thereof one or
more conventional tower packing materials and/or trays for
promoting intimate mixing of liquid and vapor in the second
zone.
[0044] As the remaining liquid hydrocarbon travels (falls) through
this second zone, lighter materials such as gasoline or naphtha
that may be present can be vaporized in substantial part by the
high energy steam with which it comes into contact. This enables
the hydrocarbon components that are more difficult to vaporize to
continue to fall and be subjected to higher and higher steam to
liquid hydrocarbon ratios and temperatures to enable them to be
vaporized by both the energy of the steam and the decreased liquid
hydrocarbon partial pressure with increased steam partial
pressure.
[0045] FIG. 1 shows one embodiment of the process of this invention
in diagrammatic form for sake of simplicity and brevity.
[0046] FIG. 1 shows a conventional cracking furnace 1 wherein a
crude oil and/or condensate primary feed 2 is passed in to the
preheat section 3 of the convection section of furnace 1. Steam 6
is also superheated in this section of the furnace for use in the
process of this invention.
[0047] The pre-heated cracking feed is then passed by way of pipe
(line) 10 to the aforesaid vaporization unit 11, which unit is
separated into an upper vaporization zone 12 and a lower zone 13.
This unit 11 achieves primarily (predominately) vaporization with
or without mild cracking of at least a significant portion of the
naphtha and gasoline boiling range and lighter materials that
remain in the liquid state after the pre-heating step. Gaseous
materials that are associated with the preheated feed as received
by unit 11, and additional gaseous materials formed in zone 12, are
removed from zone 12 by way of line 14. Thus, line 14 carries away
essentially all the lighter hydrocarbon vapors, e.g., naphtha and
gasoline boiling range and lighter, that are present in zone 12.
Liquid distillate present in zone 12, with or without some liquid
gasoline and/or naphtha, is removed therefrom via line 15 and
passed into the upper interior of lower zone 13. Zones 12 and 13,
in this embodiment, are separated from fluid communication with one
another by an impermeable wall 16, which can be a solid tray. Line
15 represents external fluid down flow communication between zones
12 and 13. In lieu thereof, or in addition thereto, zones 12 and 13
can have internal fluid communication there between by modifying
wall 16 to be at least in part liquid permeable by use of one or
more trays designed to allow liquid to pass down into the interior
of zone 13 and vapor up into the interior of zone 12. For example,
instead of an impermeable wall 16, a chimney tray could be used in
which case vapor carried by line 17 would pass internally within
unit 11 down into section 13 instead of externally of unit 11 via
line 15. In this internal down flow case, distributor 18 becomes
optional.
[0048] By whatever way liquid is removed from zone 12 to zone 13,
that liquid moves downwardly into zone 13, and thus can encounter
at least one liquid distribution device 18. Device 18 evenly
distributes liquid across the transverse cross section of unit 11
so that the liquid will flow uniformly across the width of the
tower into contact with packing 19.
[0049] Dilution steam 6 passes through superheat zone 20, and then,
via line 21 into a lower portion 22 of zone 13 below packing 19. In
packing 19 liquid and steam from line 21 intimately mix with one
another thus vaporizing some of liquid 15. This newly formed vapor,
along with dilution steam 21, is removed from zone 13 via line 17
and added to the vapor in line 14 to form a combined hydrocarbon
vapor product in line 25. Stream 25 can contain essentially
hydrocarbon vapor from feed 2, e.g., gasoline and naphtha, and
steam.
[0050] Stream 17 thus represents a part of feed stream 2 plus
dilution steam 21 less liquid distillate(s) and heavier from feed 2
that are present in bottoms stream 44. Stream 25 is passed through
a mixed feed preheat zone 27 in a hotter (lower) section of the
convection zone of furnace 1 to further increase the temperature of
all materials present, and then via cross over line 28 into the
radiant coils (tubes) 29 in the radiant firebox of furnace 1. Line
28 can be internal or external of furnace cross over conduit 30.
Line 44 removes from stripper 11 the residuum, if any, from feed
2.
[0051] Steam 6 can be employed entirely in zone 13, or a part
thereof can be employed in either line 14 and/or line 25 to aid in
the prevention of the formation of liquid in lines 14 or 25.
[0052] In the radiant firebox section of furnace 1, feed from line
28 which contains numerous varying hydrocarbon components is
subjected to severe thermal cracking conditions as aforesaid.
[0053] The cracked product leaves the radiant fire box section of
furnace 1 by way of line 31 for further processing in the remainder
of the olefin plant downstream of furnace 1 as shown in USP
'961.
[0054] In a conventional olefin production plant, the preheated
feed 10 would be mixed with dilution steam 21, and this mixture
would then be passed directly from preheat zone 3 into the radiant
section 29 of furnace 1, and subjected to severe thermal cracking
conditions. In contrast, this invention instead passes the
preheated feed at, for example, a temperature of from about 200 to
about 350F, into standalone unit 11 which is physically located
outside of furnace 1.
[0055] In the embodiment of FIG. 1, cracked furnace product 31 is
passed to at least one transfer line exchanger 32 (TLE in FIG. 1)
wherein it is cooled sufficiently to terminate the thermal cracking
function. The cracked gas product is removed by way of line 33 and
further cooled by injection of recycled quench oil 34 immediately
downstream of TLE 32. The quench oil/cracked gas mixture passes via
line 33 to oil quench tower 35. In tower 35 this mixture is
contacted with a hydrocarbonaceous liquid quench material such as
pyrolysis gasoline which boils in the range of from about 100 to
about 420F. Pyrolysis gasoline is provided from line 36 to further
cool the cracked gas furnace product as well as condense and
recover additional fuel oil product for line 34. Cracked gas
product is removed from tower 35 via line 37 and passed to water
quench tower 38 wherein it is contacted with recycled and cooled
water 39 that is recovered from a lower portion of tower 38. Water
39 condenses liquid pyrolysis gasoline in tower 38 which is, in
part, employed as liquid quench material 36, and, in part, removed
via line 40 for other processing elsewhere.
[0056] The thus processed cracked gas product is removed from tower
38 via line 41 and passed to compression and fractionation facility
42 wherein individual product streams aforesaid are recovered as
products of the cracking plant, such individual product streams
being collectively represented by way of line 43.
[0057] In tower 35 there is present a hydrocarbonaceous fraction
known as pyrolysis gas oil. Pyrolysis gas oil boils in a
temperature range of from about 380 to about 700F. Normally
pyrolysis gas oil is separated from the process and used or sold as
fuel oil. However, with this invention pyrolysis gas oil is used to
provide additional feed for the cracking process. Since the process
of this invention uses whole crude oil and/or natural gas
condensate as its primary feed material, significantly more
quantities of pyrolysis gas oil are produced, and this invention
takes advantage of this result.
[0058] Pursuant to this invention, a side draw stream 50 is taken
from tower 35 which stream is essentially pyrolysis gas oil. Stream
50 is then fed to a conventional selective hydrocracking operation
51, and the hydrocracked product, at least in part, recycled via
line 52 to stream 2 to provide more feed to be subjected to thermal
cracking, thereby improving the overall product yield per unit of
feed 2 of the thermal cracking process represented in FIG. 1. In
addition, the hydrocracked product in line 52 has, by virtue of the
hydrocracking process, been substantially reduced in sulfur content
thereby reducing the overall sulfur content of the various products
40 and 43 of the plant. The hydrocracked product in line 52 can, in
part, be removed from the process and sent to a refinery as feed to
one or more of a distillation tower, a conversion process such as a
fluid catalytic cracker or reformer, distillation blending
operations, gasoline blending operations, kerosene blending
operations, diesel blending operations, and the like.
[0059] Optionally, pursuant to this invention, a side draw stream
53 can be taken from stripper 11 and passed to hydrocracking
operation 51 thereby additionally enhancing the overall
productivity and sulfur reduction advantages of this invention for
the steam cracking process. Stream 53 can be gaseous, liquid or a
combination thereof. Stream 53 can be subjected to a distillation
step, if desired, to remove material that is undesirable in a
hydrocracking process.
[0060] Feed 2 can enter furnace 1 at a temperature of from about
ambient up to about 300 F at a pressure from slightly above
atmospheric up to about 100 psig (hereafter "atmospheric to 100
psig"). Feed 2 can enter zone 12 via line 10 at a temperature of
from about ambient to about 500 F at a pressure of from atmospheric
to 100 psig.
[0061] Stream 14 can be essentially all hydrocarbon vapor formed
from feed 2 and is at a temperature of from about 500 to about 750
F at a pressure of from atmospheric to 100 psig.
[0062] Stream 15 can be essentially all the remaining liquid from
feed 2 less that which was vaporized in pre-heater 3 and is at a
temperature of from about 500 to about 750 F at a pressure of from
atmospheric to 100 psig.
[0063] The combination of streams 14 and 17, as represented by
stream 25, can be at a temperature of from about 650 to about 800 F
at a pressure of from atmospheric to 100 psig, and contain, for
example, an overall steam/hydrocarbon ratio of from about 0.1 to
about 2.
[0064] Stream 28 can be at a temperature of from about 900 to about
1,100 F at a pressure of from atmospheric to 100 psig.
[0065] In zone 13, dilution ratios (hot gas/liquid droplets) will
vary widely because the composition of condensate varies widely.
Generally, the hot gas 21, e.g., steam, to hydrocarbon ratio at the
top of zone 13 can be from about 0.1/1 to about 5/1, preferably
from about 0.1/1 to about 1.2/1, more preferably from about 0.1/1
to about 1/1.
[0066] Steam is an example of a suitable hot gas introduced by way
of line 21. Other materials can be present in the steam employed.
Stream 6 can be that type of steam normally used in a conventional
cracking plant. Such gases are preferably at a temperature
sufficient to volatilize a substantial fraction of the liquid
hydrocarbon 15 that enters zone 13. Generally, the gas entering
zone 13 from conduit 21 will be at least about 350 F, preferably
from about 650 to about 1,000 F at from atmospheric to 100
psig.
[0067] Stream 17 can be a mixture of steam and hydrocarbon vapor
that has a boiling point lower than about 350 F. It should be noted
that there may be situations where the operator desires to allow
some distillate to enter stream 17, and such situations are within
the scope of this invention. Stream 17 can be at a temperature of
from about 600 to about 800 F at a pressure of from atmospheric to
100 psig.
[0068] It can be seen that steam from line 21 does not serve just
as a diluent for partial pressure purposes as does diluent steam
that may be introduced, for example, into conduit 2 (not shown).
Rather, steam from line 21 provides not only a diluting function,
but also additional vaporizing energy for the hydrocarbons that
remain in the liquid state. This is accomplished with just
sufficient energy to achieve vaporization of heavier hydrocarbon
components and by controlling the energy input. For example, by
using steam in line 21, substantial vaporization of feed 2 liquid
is achieved. The very high steam dilution ratio and the highest
temperature steam are thereby provided where they are needed most
as liquid hydrocarbon droplets move progressively lower in zone
13.
[0069] The term "selective hydrocracking" (hydrocracking) refers to
a process of treating a feed with hydrogen for a period of time and
at a temperature sufficient to render a product wherein less than
or equal to 5 wt. % of the product has a boiling point less than
380 F. It typically consists of four operations. First, metals such
as vanadium and nickel are removed from the feed using separate or
mixed catalyst beds. Second, sulfur, oxygen, and/or nitrogen are
removed from or minimized in the feed. Third, polynuclear aromatic
compounds are saturated to naphthenic or cycloparaffinic rings.
Fourth, the saturated naphthenic or cycloparaffinic rings are
opened to straight chain or branched chain paraffinic hydrocarbons
without reduction of the number of carbon atoms in the reacted
hydrocarbon molecules.
[0070] Preferably, metals removal and
hydrodesulfurization/hydrodenitrification are carried out in
separate beds in series with recycled hydrogen containing
progressively higher concentrations of hydrogen sulfide and
ammonia, and the aromatics saturation process is carried out in a
second stage with hydrogen containing minimal hydrogen sulfide.
[0071] In general hydrocracking consists of first removing from the
feed metals and heterocyclic atoms, such as nitrogen, oxygen and
sulfur prior to the entry of the feed into the aromatic saturation
section. The process next includes the saturation of polynuclear
aromatics in the feed. During treatment in the aromatic saturation
section, breaking of the carbon-carbon bonds of the aromatic
compounds is not intended. It is not necessary for monoaromatic
compounds to be entirely saturated. Once the aromatic rings are
saturated further treatment will selectively hydrocrack and open
the naphthenic or cycloparaffinic rings to straight chain or
branched paraffinic hydrocarbons. It is preferred to operate the
treatment so that less than 5 wt. % of the treated product
converted from the feed has a boiling point range of less than
about 380 F.
[0072] Preferably, metals removal and
hydrodesulfurization/hydronitrification are carried out in separate
beds; and the saturation process is carried out in a third stage
with hydrogen containing minimal hydrogen sulfide in counter
current or concurrent flow. Hydrocracking is carried out in a
fourth bed with hydrogen containing minimal hydrogen sulfide in
counter current or concurrent flow.
[0073] It is desirable to minimize the amount of cracking that
occurs in the feed during treatment that produces hydrocarbon
compounds that have a lower molecular weight than the starting
material. While a limited amount of hydrodealkylation may be both
unavoidable and tolerated, severe cracking of the product requires
unnecessarily greater quantities of hydrogen and forms products
which may have a poorer overall olefin yield profile. The third
step serves to saturate the polynuclear aromatics.
[0074] Useful catalyst compositions are well known in the art, and
commercially available. Metal oxide catalysts are
cobalt-molybdenum, nickel-tungsten, and nickel-molybdenum supported
catalysts, usually on alumina.
[0075] Ring opening requires a catalyst bed with low acid
functionality such as amorphous silica alumina or a crystalline
molecular sieve or a zeolite and can carry a Group VIII noble
metal.
[0076] The same catalysts can be used for demetallization,
desulfurization/denitrification, and saturation. Any catalyst which
is capable of removing most metals and substantially all sulfur and
nitrogen content from the feed can be used. In addition, the
catalyst selected should be capable of catalyzing the hydrogenation
of compounds containing aromatic rings without substantial
structural alteration or breakdown. Suitable catalysts include
cobalt/molybdenum/alumina, nickel/cobalt/molybdenum/alumina,
cobalt/molybdenum/alumina, nickel/molybdenum/alumina, and
cobalt/tungsten/alumina. Such catalysts can also be used in their
sulfided form.
[0077] The catalysts are prepared by impregnating a catalyst
support with an aqueous solution of a salt of the metal, either
consecutively or simultaneously. Nickel can be added in the form of
nickel nitrate, tungsten as ammonium metatungstate, cobalt as
cobalt nitrate, acetate, etc., and molybdenum and ammonium
molybdate. It is convenient to impregnate the support first with
the salt of the metal that is to be present in the highest
concentration in the finished catalyst. Other methods include
precipitating the metals on the support from a solution of their
salts and co-precipitation of the metals with the hydrated
support.
[0078] For maximum effectiveness, the metal oxide catalysts used
for saturation should be converted at least in part to metal
sulfides. The metal oxide can be sulfided by contact at elevated
temperatures with hydrogen sulfide or a sulfur-containing oil.
Alternatively, a commercially available metal oxide having sulfur
incorporated therein can be used. These presulfurized catalysts can
be loaded into the treatment unit and brought up to reaction
conditions in the presence of hydrogen causing the sulfur to react
with the hydrogen. The metal oxides are thereby converted to
sulfides.
[0079] Preferably, the saturation catalysts are activated before
use in the reaction by contact with a stream of hydrogen containing
hydrogen sulfide at a temperature in the range of from about 212 to
about 1,472 F for from about 1 minute to about 24 hours. The
sulfided form of the catalyst can be prepared by passing hydrogen
through liquid tetrahydrothiophene and then over the catalyst
maintained at a temperature in the range of from about 212 to about
1,472 F for from about 1 minute to about 24 hours.
[0080] The hydrocracking catalyst containing Group VIII noble
metals must be reduced with a stream of hydrogen at a temperature
in the range of from about 212 to about 1,472 F for from about 1
minute to about 24 hours.
[0081] Hydrocracking is conducted at high temperatures and high
pressures. Typically, the temperature in the hydrogenation chamber
is in the range of from about 640 to about 840 F, and a pressure in
the range of from about 1,200 to about 5,000 psig. The hydrocarbon
Weight Hourly Space Velocity can be in the range of from about 0.1
to about 5.0. Hydrogen supply can be in the range of from about 100
to about 2,000 cubic meters per ton of the hydrocarbon feed.
[0082] Hydrogen can be passed through scrubbers to remove hydrogen
sulfide and ammonia before recycle. Hydrogenation can be carried
out in a series of two or more operations using the same or
different catalysts though single stage hydrogenation may be
acceptable. Hydrogen flow can be in the co-current or counter
current direction.
EXAMPLE
[0083] A natural gas condensate stream 5 characterized as Oso
condensate from Nigeria is removed from a storage tank and fed
directly into the convection section of a pyrolysis furnace 1 at
ambient conditions of temperature and pressure. In this convection
section, this condensate initial feed is preheated to about 350 F
at about 60 psig, and then passed into a vaporization unit 11
wherein a mixture of gasoline and naphtha gases at about 350 F and
60 psig are separated from distillate liquids in zone 12 of that
unit. The separated gases are removed from zone 12 for transfer to
the radiant section of the same furnace for severe cracking in a
temperature range of 1,450.degree. F. to 1,550.degree. F. at the
outlet of radiant coil 29.
[0084] The hydrocarbon liquid remaining from feed 2, after
separation from accompanying hydrocarbon gases aforesaid, is
transferred to lower section 13 and allowed to fall downwardly in
that section toward the bottom thereof. Preheated steam 21 at about
1,000 F is introduced near the bottom of zone 13 to give a steam to
hydrocarbon ratio in section 22 of about 0.5. The falling liquid
droplets are in counter current flow with the steam that is rising
from the bottom of zone 13 toward the top thereof. With respect to
the liquid falling downwardly in zone 13, the steam to liquid
hydrocarbon ratio increases from the top to bottom of section
19.
[0085] A mixture of steam and naphtha vapor 17 at about 340 F is
withdrawn from near the top of zone 13 and mixed with the gases
earlier removed from zone 12 via line 14 to form a composite
steam/hydrocarbon vapor stream 25 containing about 0.5 pounds of
steam per pound of hydrocarbon present. This composite stream is
preheated in zone 27 to about 1,000 F at less than about 50 psig,
and introduced into the radiant firebox section of furnace 1.
[0086] Bottoms product 44 of unit 11 is removed at a temperature of
about 460 F, and pressure of about 60 psig.
[0087] Oil quench tower 35 is operated at a bottom temperature of
about 450 F at about 10 psig. Side draw stream 50 is withdrawn and
passed to hydrocracking unit 51 which contains nickel/molybdenum
catalyst followed by a molecular sieve with platinum catalyst and
is maintained at a temperature of about 650 F and pressure of about
2,900 psig. The product of unit 51 is returned via line 52 to
cracking feed line 2.
* * * * *