U.S. patent application number 14/116405 was filed with the patent office on 2014-10-30 for coke gasification on catalytically active surfaces.
The applicant listed for this patent is ExxonMobil Chemical Patents Inc.. Invention is credited to S. Mark Davis, Larry Lee Iaccino, Paul F. Keusenkothen, Ronald G. Searle.
Application Number | 20140323783 14/116405 |
Document ID | / |
Family ID | 47217590 |
Filed Date | 2014-10-30 |
United States Patent
Application |
20140323783 |
Kind Code |
A1 |
Keusenkothen; Paul F. ; et
al. |
October 30, 2014 |
Coke Gasification on Catalytically Active Surfaces
Abstract
A method and system for converting hydrocarbons into C.sub.2+
unsaturates is described. The method includes providing a
structural member upstream of a reaction zone having a surface of a
catalytic material, wherein the catalytic material is rendered
catalytically active to promote the reaction of coke and/or coke
precursors with hydrogen (H.sub.2) and/or an oxidant. Then, the
method involves exposing a hydrocarbon stream to the catalytic
material, wherein the hydrocarbon stream comprising coke and/or
coke precursors react in the presence of the catalytic material to
convert at least a portion of the coke and/or coke precursors to
vapor products. Finally, the hydrocarbons in the hydrocarbon stream
containing vapor products and hydrocarbons are converted in the
reaction zone to produce a reactor product having C.sub.2+
unsaturates.
Inventors: |
Keusenkothen; Paul F.;
(Houston, TX) ; Iaccino; Larry Lee; (Seabrook,
TX) ; Searle; Ronald G.; (Doha, QA) ; Davis;
S. Mark; (Dawsonville, GA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
ExxonMobil Chemical Patents Inc. |
Baytown |
TX |
US |
|
|
Family ID: |
47217590 |
Appl. No.: |
14/116405 |
Filed: |
April 9, 2012 |
PCT Filed: |
April 9, 2012 |
PCT NO: |
PCT/US2012/032735 |
371 Date: |
January 17, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61488462 |
May 20, 2011 |
|
|
|
Current U.S.
Class: |
585/324 ;
422/620 |
Current CPC
Class: |
C10G 9/20 20130101; C10B
1/02 20130101; C10G 2300/708 20130101; C10G 1/06 20130101; C10G
9/16 20130101 |
Class at
Publication: |
585/324 ;
422/620 |
International
Class: |
C10G 1/06 20060101
C10G001/06; C10B 1/02 20060101 C10B001/02 |
Foreign Application Data
Date |
Code |
Application Number |
Aug 9, 2011 |
EP |
11177020.2 |
Claims
1. A method of converting hydrocarbons into C.sub.2+ unsaturates
comprising: providing at least one regenerative reverse flow
reactor, the regenerative reverse flow reactor having a reactor
zone and at least one structural member upstream of the reaction
zone; at least a portion of the inner surface of such member
comprising a catalytic material that promotes the reaction of coke
and/or coke precursors with hydrogen (H.sub.2) and/or an oxidant to
form vapor products; exposing a hydrocarbon stream that contains
coke and/or coke precursors to the catalytic material in the
presence of hydrogen and/or an oxidant and reacting at least a
portion of the coke and/or coke precursors to form vapor products;
and converting at least a portion of the hydrocarbon stream
containing the hydrocarbons and the vapor products in the reaction
zone to produce a reactor product having C.sub.2+ unsaturates.
2. The method of claim 1, further comprising exposing at least a
portion of the reactor product that contains coke and/or coke
precursors to at least one structural member downstream of the
reaction zone, wherein at least a portion of the surface of such
structural member comprises a downstream catalytic material thereon
that promotes the reaction of the coke and/or coke precursors with
hydrogen and/or an oxidant to form vapor products.
3. A method of converting hydrocarbons into C.sub.2+ unsaturates
comprising: converting a hydrocarbon stream in a reaction zone of a
regenerative reverse flow reactor to produce a reactor product
comprising C.sub.2+ unsaturates and hydrogen (H.sub.2); exposing at
least a portion of the reactor product to at least a portion of a
surface of at least one structural member having the catalytic
material thereon that promotes the reaction of coke and/or coke
precursors with hydrogen (H.sub.2) and/or an oxidant at
temperatures greater than 150.degree. C.; and reacting in the
presence of the catalytic material at least a portion of the coke
and/or coke precursors with the hydrogen (H.sub.2) and/or oxidant
to convert the coke and/or coke precursors to vapor products.
4. The method of claim 3, wherein the at least one structural
member further comprises a separator vessel upstream of the
regenerative reverse flow reactor.
5. The method of claim 3, further comprising exposing at least a
portion of the reactor product that contains coke and/or coke
precursors to at least one structural member downstream of the
reaction zone, wherein at least a portion of the surface of the
structural member comprises a downstream catalytic material that
promotes the reaction of the coke and/or coke precursors with
hydrogen and/or an oxidant to form vapor products.
6. The method of claim 3, wherein hydrogen (H.sub.2) is added in a
ratio of hydrogen to carbon (H.sub.2/C) in the range of 0.1 to 5.0
in the hydrocarbon stream.
7. The method of claim 6, wherein the at least one structural
member is one of a process tube downstream of the reaction zone, a
removal component, a portion of the reactor bed adjacent the
removal component, a process tube in a transfer line exchanger, and
any combination thereof.
8. A method of converting hydrocarbons into C.sub.2+ unsaturates
comprising: converting a first hydrocarbon stream into a reactor
product comprising C.sub.2+ unsaturates and coke in a reaction zone
of a regenerative reverse flow reactor having a reactor bed and at
least one structural member adjacent to an end of the reactor bed,
wherein such structural member comprises one or more of a removal
component and an injection component, and wherein at least a
portion of the inner surface of such structural member comprises a
catalytic material that promotes the reaction of coke with an
oxidant; removing a first portion of the reactor product from the
reaction zone; exposing a second portion of the of the reactor
product to (i) the catalytic material and (ii) an oxidant in a
stoichiometric excess amount required to react with the coke;
reacting the coke and the oxidant in the presence of the catalytic
material to convert at least a portion of the coke to vapor
products; exothermically reacting the remaining oxidant with a fuel
stream in the reaction zone to produce a combustion product; and
removing at least a portion of the combustion product prior to the
providing a second hydrocarbon stream to the reaction zone.
9. The method of claim 8, further comprising disposing a catalytic
material on at least a portion of a surface of the reactor bed
adjacent the at least one structural member, wherein the catalytic
material promotes the reaction of coke with the oxidant stream at
temperatures less than 600.degree. C.
10. The method of claim 8, wherein the at least one structural
member comprises a heat exchanger downstream of the regenerative
reverse flow reactor for the combustion products.
11. The method of claim 8, wherein the converting step comprises
thermally cracking the hydrocarbon stream by exposure to
temperatures in the range of 1200.degree. C. to 2200.degree. C. in
the reaction zone.
12. The method of claim 8, wherein the at least one structural
member comprises a poppet valve, wherein the surface is the portion
of the poppet valve continuously exposed to an interior region of
the regenerative reverse flow reactor.
13. The method of claim 8, wherein the catalytic material comprises
one or more of the elements from Group IVB-VIIIB and Group IA-IVA
and oxides, sulfides, nitrides, carbides intermetallic and/or
reduced metal species.
14. The method of claim 8, wherein the catalytic material is
selected to provide a surface net coke deposition rate of less than
0.1 g/m.sup.2/hr.
15. A pyrolysis system comprising: a pyrolysis unit having a
reaction zone, wherein the pyrolysis unit is configured to convert
hydrocarbons into C.sub.2+ unsaturates; and at least a portion of a
surface of at least one structural member upstream of the reaction
zone having a catalytic material thereon that promotes the reaction
of coke and/or coke precursors with hydrogen (H.sub.2) and/or an
oxidant, wherein the pyrolysis unit is a regenerative reverse flow
reactor, and wherein the at least one structural member comprises
one or more of a feed injection component upstream of the
regenerative reverse flow reactor, a process tube upstream of the
regenerative reverse flow reactor, a poppet valve, wherein the
surface is the portion of the poppet valve continuously exposed to
the interior region of the regenerative reverse flow reactor, a
separator vessel upstream of the regenerative reverse flow reactor,
a process tube coupled between the separator vessel and the
regenerative reverse flow reactor, and a heat exchanger upstream or
downstream of the regenerative reverse flow reactor.
16. The pyrolysis system of claim 15, wherein the at least one
structural member is one or more of a process tube downstream of
the reaction zone, a removal component, a portion of the reactor
bed adjacent the removal component, a process tube in a transfer
line exchanger, a poppet valve, wherein the surface is the portion
of the poppet valve continuously exposed to the interior region of
the regenerative reverse flow reactor.
17. The pyrolysis system of claim 15, wherein the catalytic
material comprise one or more elements from Group IVB-VIIIB and
Group IA-IVA and oxides, sulfides, nitrides, carbides intermetallic
and/or reduced metal species.
Description
PRIORITY CLAIM
[0001] This application claims priority to and the benefit of U.S.
Ser. No. 61/488,462, filed May 20, 2011 and European Application
No. 11177020.2, filed on Aug. 9, 2011.
FIELD
[0002] This invention relates to processes and apparatuses for
inhibiting coke deposition within hydrocarbon processing system
which is subject to fouling.
BACKGROUND
[0003] Many apparatus used in the processing of petroleum have a
tendency to become fouled by deposits of coke necessitating
occasional removal from service for cleaning. Coke includes
carbonaceous material with low hydrogen content present as a solid,
semi-solid and/or viscous liquid. Different mechanisms may lead to
coking in the vapor phase and/or in the liquid phase. For the vapor
phase, coking may form from deposits of low volatility materials
and/or from chemical reactions, which may be on a surface of
equipment exposed to the hydrocarbon streams and may include
Diels-Alder and free radical condensation/oligomerization
reactions. For the liquid phase, coking may occur from chemical
reactions and from the deposition of insoluble materials.
[0004] As an example, deposition of low volatility materials may
occur at locations where a hydrocarbon stream is being heated and
the majority of the stream vaporizes (e.g., the "dry point"), may
occur when high molecular weight species form in the vapor phase,
and/or may occur when the stream is being cooled and some molecules
begin to condense (e.g., the "dew point"). If this deposition
occurs on the internal surface of equipment, such as a heat
exchanger or reactor components, the walls of the equipment are
coated with deposits that result in operational difficulties. These
difficulties include: (i) diminished heat transfer rate between the
wall and the material in the tube; (ii) deterioration of
temperature regulation, (iii) development of flow restrictions that
may cause increased pressure drop and/or maldistribution; (iv)
increase in shut-downs and cleaning cycles, which may be
challenging for long or complex components (e.g., the more
expensive and difficult is the cleaning job); and/or (v) damage to
the equipment result. As such, coking for hydrocarbon processing
facilities results in reduced operation inefficiencies, such as
downtime for cleaning, reduced throughput, and increased energy
inefficiencies, along with the expense of decoking operations.
[0005] The periodic cleaning involves interrupting normal
operations (e.g., hydrocarbon processing operations), taking the
equipment out of service for decoking operations, and restarting
the normal operations once the cleaning is complete. The decoking
or cleaning operation includes various chemical or mechanical
methods, which are typically labor intensive, add significantly to
the maintenance cost of the equipment and often requires
replacement of the major components. The most common means of
cleaning coked equipment is to combust the coke with air that may
be diluted with steam, nitrogen, or other material to reduce the
oxygen content thereby lowering and/or controlling the temperature
of decoking operations.
[0006] To minimize the difficulties with coking, certain references
describe using certain materials for the components in the reaction
zone to make surfaces more chemically inert, reduce adhesion in the
reaction zone or downstream of the reaction zone, and/or provide
additives to the hydrocarbon stream to mitigate coking. For
example, using stainless steel in the radiant section of a reactor
has been described to have a lower tendency to form coke during
use. Specifically, U.S. Pat. Nos. 5,630,887 and 6,436,202 describe
the use of stainless steel for furnace tubes.
[0007] Similar to the use of stainless steel for furnace tubes,
other references describe the use of various surface coatings in
the reaction zone, such as U.S. Pat. Nos. 6,824,883; 7,056,399 and
7,488,392 and U.S. Published Patent Application Nos. 2007/0105060;
2008/0073063 and 2009/0011925. As a specific example, one such
coating involves forming a protective surface film by depositing a
layer of silica resulting from oxidative decomposition of an alkoxy
silane in the vapor phase on the metal surface. U.S. Pat. No.
6,899,966 describes a composite surface having a thickness from 10
to 5,000 microns comprising a spinel of the formula
Mn.sub.xCr.sub.3-xO.sub.4 wherein x is from 0.5 to 2 and oxides of
Mn, Si selected from the group consisting of MnO, MnSiO.sub.3,
Mn.sub.2SiO.sub.4 and mixtures thereof which are not prone to
coking and are suitable for hydrocarbyl reactions, such as furnace
tubes for cracking. Another coating involves a layer that is from
several microns to several millimeters thick of a ceramic material
deposited by thermal decomposition of a silicon containing
precursor in the vapor phase. This coating is used to passivate a
reactor surface subject to coking. Further, surface coatings of
alumina have also been explored to reduce coking by making the
surface less catalytically active. The alumina surface coating may
be formed by deposition and/or aluminum incorporation into the
metallurgy so that aluminum can migrate to the surface and oxidize
to form an alumina layer. These approaches result in a surface
oxide, which is less likely to catalyze the production of some
coke, but the surfaces have relatively high surface energy that
attracts unwanted deposits (already present and/or formed in the
vapor phase) to the surface. Other coatings may be based on
polymeric materials, such as polyethylene and polyvinylfluoride,
with low surface energy, such as the coatings used to perform at
lower temperatures. However, these polymeric coatings generally can
not withstand higher temperatures typically involved with
hydrocarbon processing and are not effective to reduce coking.
[0008] These surface coating approaches, such as silica and alumina
oxide, generally involve forming a layer on the surface of conduits
in the micron to millimeter range in thickness. This is usually to
ensure good surface coverage as well as provide a protective layer
of sufficient thickness to be robust during operating conditions.
Coatings of such thickness may, however, limit heat transfer.
Treatments with silicate sols, or paints rich in silicon or
aluminum typically produce relatively thick surfaces (micron to
millimeter) that can provide a physical boundary that protects the
underlying metal from corrosion. However, such treatments do not
have low surface energies if the surface terminates in an
oxide/hydroxide surface layer. The use of silanes for chemical
vapor deposition is also known, but with the intent to diffuse Si,
C, H and other elements into the metal surface using high
temperatures (e.g. 600.degree. C.); the result is that the surface,
though non-metallic, can still have a high surface energy and does
not reject coke. Thus, conventional treatments tend to be
inadequate either because they are too thick for good heat transfer
or, alternatively, do not adequately resist coke.
[0009] With regard to the additives in the hydrocarbon stream,
various on-stream additives have also been explored to reduce coke
production. For example, sulfur (typically added as H.sub.2S) is
described as reducing coking in steam cracking and aromatics
reforming Phosphorous has been also utilized to reduce coking.
While only partially effective, these additives require ongoing
addition and may result in product clean-up requirements.
Accordingly, other approaches may be preferred to the additive
operations.
[0010] There is a need to reduce and/or eliminate fouling in
petroleum refining apparatuses, which is presently not adequately
addressed by the prior art.
SUMMARY
[0011] In one embodiment of the present techniques, a method of
converting hydrocarbons into C.sub.2+ unsaturates is described. The
method of converting hydrocarbons into C.sub.2+ unsaturates
comprising: providing at least one structural member upstream of a
reaction zone at least a portion of the inner surface of such
member comprising a catalytic material that promotes the reaction
of coke and/or coke precursors with hydrogen (H.sub.2) and/or an
oxidant to form vapor products; exposing a hydrocarbon stream that
contains coke and/or coke precursors to the catalytic material in
the presence of hydrogen and/or an oxidant and reacting at least a
portion of the coke and/or coke precursors to form vapor products;
and converting at least a portion of the hydrocarbon stream
containing the hydrocarbons and the vapor products in the reaction
zone to produce a reactor product having C.sub.2+ unsaturates.
[0012] In another embodiment, a pyrolysis system is described. The
pyrolysis system comprising a pyrolysis unit having a reaction
zone, wherein the pyrolysis unit is configured to convert
hydrocarbons into C.sub.2+ unsaturates; and at least a portion of a
surface of at least one structural member upstream of the reaction
zone having a catalytic material thereon that promotes the reaction
of coke and/or coke precursors with hydrogen (H.sub.2) and/or an
oxidant. The pyrolysis (e.g., thermal cracking) may comprise
exposing the hydrocarbon stream to temperatures in the range of
1200.degree. C. to 2200.degree. C., where greater than 75% of heat
for the converting may be provided via indirect heat transfer.
[0013] In yet another embodiment, another method of converting
hydrocarbons into C.sub.2+ unsaturates is described. The method
comprising: converting a hydrocarbon stream in a reaction zone of a
regenerative reverse flow reactor to produce a reactor product
comprising C.sub.2+ unsaturates and hydrogen (H.sub.2); exposing at
least a portion of the reactor product to at least a portion of a
surface of at least one structural member having the catalytic
material thereon that promotes the reaction of coke and/or coke
precursors with hydrogen (H.sub.2) and/or an oxidant at
temperatures greater than 150.degree. C.; and reacting in the
presence of the catalytic material at least a portion of the coke
and/or coke precursors with the hydrogen (H.sub.2) and/or oxidant
to convert the coke and/or coke precursors to vapor products.
[0014] Further still, in other embodiments, another pyrolysis
system is described. The pyrolysis system may include a
regenerative reverse flow reactor having a reaction zone, wherein
the regenerative reverse flow reactor is configured to convert
hydrocarbons into C.sub.2+ unsaturates; and at least one structural
member downstream of the reaction zone having at least one surface
of a catalytic material, wherein the catalytic material promotes
the reaction of coke and/or coke precursors with hydrogen (H.sub.2)
and/or an oxidant to form vapor products.
[0015] In yet another embodiment, a method of converting
hydrocarbons into C.sub.2+ unsaturates is described. The method
comprising converting a first hydrocarbon stream into a reactor
product comprising C.sub.2+ unsaturates and coke in a reaction zone
of a regenerative reverse flow reactor having a reactor bed and at
least one structural member adjacent to an end of the reactor bed,
wherein such structural member comprises one or more of a removal
component and a injection component, and wherein at least a portion
of the inner surface of such structural member comprises a
catalytic material that promotes the reaction of coke with an
oxidant; removing a first portion of the reactor product from the
reaction zone; exposing a second portion of the of the reactor
product to (i) the catalytic material and (ii) an oxidant in a
stoichiometric excess amount required to react with the coke;
reacting the coke and the oxidant in the presence of the catalytic
material to convert at least a portion of the coke to vapor
products; exothermically reacting the remaining oxidant with a fuel
stream in the reaction zone to produce a combustion product; and
removing at least a portion of the combustion product prior to the
providing a second hydrocarbon stream to the reaction zone.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] FIG. 1 illustrates a diagram of partial O.sub.2 pressure in
equilibrium with steam with various amounts of hydrogen
(H.sub.2).
[0017] FIG. 2 illustrates a schematic flow diagram of an exemplary
embodiment with a steam cracker system in accordance with an
embodiment of the present techniques.
[0018] FIG. 3 is a diagrammatic illustration of an exemplary
regenerating reverse flow reactor system in accordance with another
embodiment of the present techniques.
[0019] FIG. 4 is a diagrammatic illustration of an exemplary
pyrolysis reactor system having a pulsed compression reactor in
accordance with yet another embodiment of the present
techniques.
DETAILED DESCRIPTION
[0020] In the processing of hydrocarbons, the coking mechanisms
that are associated with inefficiencies in hydrocarbon processing
involve chemical reactions and the deposition of insoluble
materials. In these mechanisms, the reduction of the viscous
sub-layer (or boundary layer) close to the surface (e.g., inner
wall or surface of a piece of equipment) may mitigate the coking
rate. The inner surface may be a surface that is within the reactor
or exposed to one or more streams in the process. In chemical
reactions, certain temperatures at the surface of a heat transfer
surface may activate molecules to form precursors for the fouling
residue (e.g. coke). If these coke precursors are not swept out of
the relatively stagnant surface region, the coke precursors may
associate together and deposit on the surface. A reduction of the
boundary layer reduces the thickness of the stagnant region and
hence the amount of precursors available to form coke deposits. For
the deposition of insoluble materials, a reduction in the boundary
layer increases the shear near the surface and hence exerts a
greater force on the insoluble particle near the surface to
overcome the particle's attractive forces to the surface, which
reduces the probability of deposition and incorporation into any
residue.
[0021] Coke is a carbonaceous material that may be a tar, semisolid
or solid at process conditions (e.g., certain temperatures,
pressures and environments), which is typically formed by chemical
reactions, such as condensation, oligomerization or polymerization
of unsaturated hydrocarbons formed by the process, and/or the
deposition of insoluble materials, such as non-volatile (e.g.,
asphaltenes) or multi-ring aromatic species. In numerous processes,
coke formation occurs even though coke is not a thermodynamically
stable species at the process conditions. For example, coke
includes solid materials that are predominately carbon (C), but may
contain some hydrogen (H) and other atomic species (e.g., sulfur
(S), nitrogen (N), oxygen (O), halogens, etc). Structurally, the
coke may be well ordered graphitic type materials to amorphous
materials and also include viscous liquid materials that are
precursors to solid coke (coke precursors). Accordingly, various
factors contribute to the formation of coke on the surfaces within
a system, such as process conditions, process environment, and feed
composition, for example.
[0022] Formation of coke is especially troublesome in processes
used to produce C.sub.2+ unsaturates (e.g., ethylene, acetylene,
propylene, benzene along with other olefins and aromatics) from
hydrocarbons. These processes include various heating and
separating units for feed pretreatment, a pyrolysis unit (e.g.,
reactor or furnace) for converting the hydrocarbons in the feed
into C.sub.2+ unsaturates in a reaction zone and recovery units to
process the resulting products. The term "reaction zone" means a
location in the pyrolysis system where greater than 50%, greater
than 75% and/or greater than 90% of the conversion of hydrocarbons
into C.sub.2 unsaturates in the pyrolysis system is performed. That
is, while some thermal cracking may occur upstream of reaction
zone, the reaction zone is the location where a substantial amount
of the smaller molecules are produced from the initial hydrocarbons
to the system. For example, the reaction zone for a steam cracking
system is in the radiant tubes of the steam cracking furnace. The
reaction zone for a regenerative reverse flow reactor is the
central location, which may include a portion of the reactor beds
near the central location.
[0023] Regardless of the specific process, cracking of hydrocarbons
entails heating hydrocarbons in the presence of optional fluids
(e.g., steam or other fluids, such as hydrogen) to various
temperatures that convert the hydrocarbons in the reactor feed into
C.sub.2+ unsaturates. For certain pyrolysis processes, such as
indirect heat transfer, the process involves heating a solid
material (e.g., by combustion) and using the heated solid material
to crack the hydrocarbons. For indirect heat transfer processes,
the combustion products are maintained separate from the
hydrocarbon stream. This technique involves various different types
of reactors, such as a regenerative reverse flow reactor and/or
steam cracking. Typically, steam cracking may heat the hydrocarbons
in the reactor feed to process conditions that include a
temperature in excess of about 370.degree. C. and at pressures
greater than 25 psia, as disclosed in U.S. Pat. No. 7,138,047. A\
regenerative reverse flow reactor may heat the hydrocarbons in the
reactor feed to process conditions that include temperatures in
excess of 1200.degree. C., in excess of 1500.degree. C., in excess
of 1700.degree. C., and even in excess of 2000.degree. C., and at a
variety of pressures, such as at pressures in the range of 3 psig
(21 kPa) to 162 psig (1117 kPa) and/or in the range of 15 psig (103
kPa) to 103 psig (710 kPa). At such process conditions, many of the
hydrocarbon molecules undergo cracking, that is, the breaking of
carbon-carbon bonds and/or releasing hydrogen from saturates to
form ethylene, acetylene and propylene, among other olefinic and
aromatic products. Through undesirable side reactions, equipment
surfaces (e.g., surfaces or walls of furnace tubes, other process
tubes and/or components) gradually accumulate carbonaceous deposits
(e.g., coke), which eventually may cause an unacceptable increase
in pressure drop and loss of heat transfer in the process.
[0024] The process conditions may also include a process
environment that may be net-reducing or net-oxidizing, but may also
include an environment that both oxidation and reduction reactions
are possible. Oxidation-reduction reactions, which may be referred
to as redox reactions, describe chemical reactions in which atoms
have their oxidation number (oxidation state) changed. That is,
redox reactions include oxidation reactions, which is the loss of
electrons or an increase in oxidation state by a molecule, atom, or
ion; and reduction reactions, which involves the gain of electrons
or a decrease in oxidation state by a molecule, atom, or ion. These
reactions may be either a simple redox process, such as the
oxidation of carbon to yield carbon dioxide (CO.sub.2) or the
reduction of carbon by hydrogen to yield methane (CH.sub.4).
[0025] Another factor in the coke formation is the composition of
the stream at the respective location along the flow path within
the system (e.g., present within the equipment). As an example, the
pyrolysis unit may involve a hydrocarbon feed that includes various
hydrocarbons and have a hydrogen content of in the range of 8 wt %
to 25 wt % of the hydrocarbons of the hydrocarbon feed, in the
range of 12 wt % to 25 wt % of the hydrocarbons of the hydrocarbon
feed, in the range of 12 wt % to 20 wt % of the hydrocarbons of the
hydrocarbon feed and/or in the range of 20 wt % to 25 wt % of the
hydrocarbons of the hydrocarbon feed.
[0026] The present techniques utilize catalytically active surfaces
to enable a kinetic pathway at steady state and/or transient
reaction conditions so that coke and/or coke precursors can be
removed and/or the formation can be prevented. The catalytically
active surface may be bulk metallurgy; addition of active species
to surface of bulk metallurgy; or coatings added to and/or bonded
to the bulk metallurgy. The bulk metallurgy is the process
equipment (e.g., tube or vessel). As an example, the catalytic
species (for H.sub.2 gasification or oxidation of coke) may be
incorporated into a glass-like, catalytically active coating for
the interior (e.g., in contact with the process streams) of process
equipment to prevent coke fouling of the equipment. For H.sub.2
gasification of the coke and/or coke precursors, this catalytic
route approach may be applicable to process equipment and process
conditions where H.sub.2 is sufficient at the partial pressure so
that the thermodynamically favored route is for H.sub.2 to react
with coke or coke precursor to produce methane or other light
hydrocarbons and not in a thermodynamic regime so that instead
hydrocarbon decomposition to coke and H.sub.2 occurs. The process
conditions may be adjusted (e.g., amount of H.sub.2 added to the
stream, total pressure, and/or temperature) to be in the proper
regime. Choice of catalytic material and process conditions may
also be such that an extensive amount of hydrogenation of desired
feeds and products does not occur. Some of the potential
applications for this aspect are steam cracking radiant section
tubes; heat exchangers (e.g., transfer line exchangers (TLE's));
cokers; hydrotreater preheat furnaces; separators or other
equipment, as discussed further below.
[0027] To reduce the potential for coking at various locations,
coke deposition may be inhibited by depositing a catalytically
active species onto the internal surfaces of hydrocarbon processing
equipment to provide kinetic pathways for the reactions involving
coke and/or coke precursors based on the process environment (e.g.,
oxidizing environment or reducing environment) and other process
conditions. The catalytic material may be an active material or
capable of becoming active at process conditions. Various different
pyrolysis systems (e.g., steam cracking systems or regenerative
reverse flow reactors) may benefit from having surfaces of
structural members or components coated with the catalytic
material. These pyrolysis systems may include pyrolysis units
(e.g., thermal reactors, such as a steam cracking reactor and a
regenerative reverse flow reactor, and/or other reactors) to
perform the conversion in a reaction zone. Further, associated
equipment may also benefit from having various surfaces of
structural members coated with the catalytic material (e.g., a
catalytically active species). The associated equipment may include
heat exchangers, separators, and different tubes (e.g., piping or
conduits) connecting the equipment or other suitable equipment that
may be subject to coking. The catalytic material may provide a
surface net coke deposition rate is less than 1.0 g/m.sup.2/hr,
less than 0.1 g/m.sup.2/hr, less than 0.01 g/m.sup.2/hr or less
than 0.001 g/m.sup.2/hr.
[0028] Internal surfaces of process equipment (e.g., surfaces of
reactor components or other structural members) subject to coking
may have a catalytic material containing or consisting of an
oxidation catalyst and/or hydrogenation catalyst. As an example,
the catalyst may include Group IB, IIB, IIIA, IVA, IVB, VB, VIIB,
VIIB and/or VIIIB metal oxides or sulfides of The Periodic Table of
Elements. The "Periodic Table of the Elements" means the Periodic
Chart of the Elements as tabulated on the inside cover of The Merck
Index, 10th Edition, Merck & Co., Inc., 1983. The catalyst may
preferably be selected from the group consisting of Al, Ag, Au, Co,
Cr, Cu, Fe, Ir, Mo, Mn, Nb, Ni, Pd, Pt, Re, Ru, Rh, Sn, W, Zn, and
alloys and mixtures thereof. Specifically, the catalyst may include
sulfides and oxides from Group VIIIB, such as Co, Ni, Pt and
Pd.
[0029] As another example, the catalyst may include MAX phase
catalytic materials, which are ternary carbides and nitrides with
the general formula M.sub.n+1AX.sub.n, where n=1 to 3, M is an
early transition metal (e.g., Group IIIB-VIB), A is an A-group
element (e.g., Group IIIA-VIA), and X is carbon (C) and/or nitrogen
(N). The catalyst may preferably be selected from the Group
consisting of Sc, Ti, V, Cr, Zr, Nb, Mo, Hf, Ta and mixtures
thereof. Specifically, the catalyst may include Ti.sub.2AlC,
Ti.sub.2AlN, Hf.sub.2PbC, Cr.sub.2GaC, V.sub.2AsC, Ti.sub.2InN,
Nb.sub.2AlC, (Nb,Ti).sub.2AlC, Ti.sub.2AlN.sub.0.5C.sub.0.5,
Nb.sub.2GaC, Nb.sub.2AsC, Zr.sub.2InN, Ti.sub.2GeC, Cr.sub.2AlC,
Ta.sub.2AlC, V.sub.2AlC, V.sub.2PC, Nb.sub.2PC, Ti.sub.2PbC,
Zr.sub.2SnC, Hf.sub.2SnC, Ti.sub.2SnC, Nb.sub.2SnC, Zr.sub.2PbC,
Zr.sub.2SC, Ti.sub.2SC, Nb.sub.2SC, Hf.sub.2SC, Ti.sub.2GaC,
V.sub.2GaC, Mo.sub.2GaC, Ta.sub.2GaC, Ti.sub.2GaN, Cr.sub.2GaN,
V.sub.2GaN, V.sub.2GeC, Sc.sub.2InC, Ti.sub.2InC, Zr.sub.2InC,
Nb.sub.2InC, Hf.sub.2InC, Hf.sub.2InN and/or Hf.sub.2SnN.
[0030] As yet another example, the catalyst may include a
catalytically active multi-phase glass-ceramic precursor, which
when melted and devitrified forms a catalytically active
polycrystalline ceramic; or the catalytic material may be created
by bulk metallurgy, such as by the addition of catalytically active
species to surface of bulk metallurgy; or coatings added to and/or
bonded to the bulk metallurgy. The term "primary crystalline phase"
refers to that portion of a catalytically active glass-ceramic
comprising greater than 50% by volume of the glass-ceramic. As used
herein, the term "secondary crystalline phase" refers to a
crystalline portion of a catalytically active glass-ceramic
comprising less than 50% by volume of the glass-ceramic. The term
"secondary noncrystalline phase" refers to a noncrystalline portion
of a catalytically active glass-ceramic comprising less than 50% by
volume of the glass-ceramic, and the term "catalyst precursor"
refers to a material which is converted into a catalyst material
after processing. For example, metal oxides are catalyst precursors
which are converted into catalysts upon exposure to a reducing
atmosphere, or the catalyst precursors may be metal silicates. As
used herein, the term "glass-ceramic precursor formulation" refers
to a combination of materials (raw glass batch) suitable for
melting to form amorphous glass, and the term "glass-ceramic
precursor material" refers to the amorphous glass produced by
melting the raw glass batch. The glass-ceramic precursor material
can comprise silicates (e.g., lithium silicate and
aluminosilicates, such as lithium aluminosilicate).
[0031] Coke deposition may be inhibited by a reduction of the
hydrocarbon coke in the presence of hydrogen and these
catalytically active surfaces. The catalyst materials may be
incorporated into polycrystalline ceramic materials. For example,
U.S. Published Patent Application No. 2009/0011925 describes
materials that are catalytically active glass-ceramic materials.
These materials comprise a primary crystalline matrix which may
contain a relatively small amount of catalytically active metal, at
a secondary crystalline phase and a secondary noncrystalline phase
located at a boundary of the primary crystalline phase, and at
least one catalytically active metal disposed in at least one of
the secondary crystalline phase and the secondary noncrystalline
phase.
[0032] The catalytic material may be a layer formed in a structural
member or applied to the structural member. That is, the catalyst
material may be formed into the bulk metallurgy of the structural
member, such as on the interior of tubes (e.g., piping or conduits)
for use in the various hydrocarbon processing systems which are
subject to coking. The catalytic material may be formed via
absorption, implantation, chemical deposition and/or other
processes. As another approach, the catalytic material may be a
coating of catalytic material along with other materials, such as
binding materials, which are disposed on a portion of the equipment
that provides physical form or shape for the surface. The
structural member may be at least a portion of a tube, at least a
portion of equipment (e.g., reactor housing, manifold, reactor
tiles, heat exchanger and/or separator) and/or at least a portion
of a component (e.g., honeycomb monolith, mixer, valve and piston).
The catalytic material may be applied to the structural member
through any known technique, such as sponging, painting, deposition
and/or spraying, for example. The thickness of the catalytic
material may be in the range of 5 microns to 1500 microns, 20
microns to 1200 microns, 30 microns to 1100 microns.
[0033] The composition of the catalytic material may include an
active catalytic component concentration ranging between 100 ppm to
10 wt %. Glass-ceramic has a crystal content of at least about 10%
by volume and the majority of the crystals forming the
glass-ceramic preferably have a crystal size less than about 10
microns. In one preferred embodiment, the glass-ceramic is an
aluminosilicate having a composition comprising a range of about 35
wt % to 75 wt % SiO.sub.2, 12 wt % to 25 wt % Al.sub.2O.sub.3, 5 wt
% to 30 wt % of at least one of NiO, CoO, and FeO, 0 wt % to 10 wt
% Li.sub.2O, 0 wt % to 10 wt % MgO, 0 wt % to 5 wt % CaO, 0 wt % to
3 wt % B.sub.2O.sub.3, 0 wt % to 3 wt % ZnO, 0 wt % to 15 wt %
CeO.sub.2, and 0 wt % to 5 wt % of at least one of TiO.sub.2 and
ZrO.sub.2.
[0034] Catalytic surface activity should be such that at the
process conditions (e.g., temperature and O.sub.2 or H.sub.2
partial pressure present at the surface), reaction of coke and or
coke precursors occurs, but minimal amount of valuable feed or
product hydrocarbons are converted by the active catalytic decoking
material. That is, the catalytic material may preferably be a
weakly active material.
[0035] Accordingly, the process environment may be a reducing
environment (e.g., net-reducing) or an oxidation environment (e.g.,
net-oxidizing). As noted above, process environments with an excess
of hydrogen (H.sub.2) are reducing environments. While coke may
still form as a kinetic product even when it is not
thermodynamically stable, the addition of a suitable catalyst may
enable the increase in the kinetic rate for coke reduction to
methane. Similarly, process environments with an excess of oxygen
(O.sub.2) relative to hydrogen H.sub.2 are oxidizing environments.
As with reducing environments, coke may be present as a kinetic
product even when it is not thermodynamically stable. The addition
of a suitable catalyst may increase the kinetic rate for coke
oxidation to carbon monoxide (CO) and/or carbon dioxide (CO.sub.2)
in the oxidizing environment. Oxygen (O.sub.2) may be supplied to
the process as molecular O.sub.2 or may be supplied as an oxidized
species, such as H.sub.2O or CO.sub.2, which may act as sources of
oxidant (e.g., H.sub.2O.dbd.H.sub.2+1/2O.sub.2 and
CO.sub.2.dbd.CO+1/2O.sub.2). Regardless, it may be referred to as
an oxidant.
[0036] In addition, a hydrogen (H.sub.2) containing stream may be
combined with the hydrocarbon stream (e.g., hydrocarbon feed) to
form a reactor feed. The hydrogen (H.sub.2) containing stream may
include hydrogen gas (H.sub.2) in an amount that provides a
preferred ratio of hydrogen gas (H.sub.2) moles to the total moles
of carbon (C) in the hydrocarbon components of the reactor feed.
Hydrogen gas can be added in pure form, or in the form of gas
mixtures which are produced in various refinery processes. The
ratio of hydrogen to carbon (H.sub.2/C) may be from 0.0 or 0.1 to
5.0, such as 0.0, 0.1, 1.0, 2.0, 3.0, 4.0, 5.0, or values in
between for the reactor feed. Combining the hydrogen content of the
hydrogen gas to the hydrogen and carbon contents of the hydrocarbon
components of the hydrocarbon feed may result in a total atomic
ratio of hydrogen (H) to carbon (C) in the reactor feed that is
from 3 to 15. The weight percent of total hydrogen in the reactor
feed may be greater than that in the hydrocarbon feed. For example,
the weight percent of total hydrogen in the reactor feed may be
between 8 wt % and 54 wt %. In certain embodiments of the process,
H.sub.2 should be added or maintained at levels of greater than
about 0.1 mole %, greater than 1.0 mole %, or even greater than 2.0
mole %, but less than 5.0 mole %, 4.0 mole %, or even less than 3.0
mole %.
[0037] As an example, FIG. 1 illustrates a diagram of partial
O.sub.2 pressure in equilibrium with steam with various amounts of
H.sub.2. In diagram 100, various response curves 108-114 of partial
O.sub.2 pressure for a given temperature are shown based on the
values for O.sub.2 partial pressure (in psia) along the Y1-axis
104, different temperatures (in .degree. C.) along the x-axis 102,
and different H.sub.2 pressures (in psia) along the Y2-axis 106.
The response curve 108 is associated with 0 psia of H.sub.2 being
added to 40 psia of steam, the response curve 110 is associated
with 0.1 psia of H.sub.2 being added to 39.9 psia of steam, the
response curve 112 is associated with 1 psia of H.sub.2 being added
to 39 psia of steam, and the response curve 114 is associated with
10 psia of H.sub.2 being added to 30 psia of steam. The addition of
hydrogen (H.sub.2) in these response curves 110-114 indicates that
partial O.sub.2 pressure may be dramatically reduced for lower
temperatures. This effect is specifically present at temperatures
below 850.degree. C., even more at temperatures below 550.degree.
C. In addition, the response curves 110-114 indicate that a
reducing environment may be provided with between 0 psia and 0.1
psia of hydrogen (H.sub.2) being added to the steam. As such, the
process environment may be adjusted by the addition of H.sub.2 to
further inhibit coking on surfaces at certain locations.
[0038] Further, in certain embodiments of the present techniques,
it is possible that the hydrogen (H.sub.2) containing stream is
from a relatively low purity hydrogen sources, such as synthesis
gas and/or refinery fuel gas. The synthesis gas (i.e. syngas)
includes H.sub.2 and carbon monoxide (CO) and may also include
various levels of carbon dioxide (CO.sub.2), nitrogen (N.sub.2),
water (H.sub.2O), light hydrocarbons, and/or hydrogen sulfide
(H.sub.2S) as well as other contaminants. The refinery fuel gas may
include H.sub.2 and methane (CH.sub.4) and may also include various
levels of CO, CO.sub.2, N.sub.2, H.sub.2O, light hydrocarbon,
and/or H.sub.2S as well as other contaminants. The hydrogen
(H.sub.2) containing stream may be added to the hydrocarbon stream
at any suitable point in the systems upstream of or into locations
where coking may occur.
[0039] Another addition to the hydrocarbon stream may include an
oxidant stream. As noted above, the oxidant stream may include
oxygen gas in pure form, or more preferably in the form oxidants,
such as H.sub.2O and/or CO.sub.2. The oxidant may be provided in an
amount that provides a preferred ratio of oxygen (O) moles to the
total moles of carbon (C) in the hydrocarbon components of the
reactor feed. The ratio of oxygen to carbon (0/C) may be from 0.0
or 0.01 to 0.6, such as 0.0, 0.01, 0.1, 0.15, 0.2, 0.4, 0.6, or
values in between.
[0040] According to certain embodiments of the present techniques,
the catalyst (e.g., hydrogenation catalyst and/or oxidation
catalyst) may be utilized in a process environment (e.g., reducing
environment or oxidizing environment) upstream of the reaction zone
for a reactor system. That is, the catalyst may be applied at
locations upstream of the reaction zone (e.g., radiant tubes for a
steam cracker or central location within a regenerative reverse
flow reactor) to enhance the process under certain process
conditions and process environments. In particular, the catalyst
may form a layer on the surface of at least a portion of a tube or
equipment upstream of the reaction zone to reduce coking in these
regions.
[0041] By providing a catalytically active material upstream of the
reaction zone, the hydrocarbon stream being provided to the
reaction zone may be subjected to partial cracking conditions
(e.g., higher temperatures and/or pressures, which may include
visbreaking conditions) upstream of the reaction zone. This may
enhance the process by maximizing the amount of hydrocarbons being
separated from an initial feed prior to the reaction zone, while
minimizing the coking problems at the upstream locations.
[0042] The term "visbreaking" as used herein is a well-known,
non-catalytic, mild thermal cracking process that uses heat to
convert or crack heavy hydrocarbonaceous oils and resids into
lighter, sometimes more valuable products, such a naphtha,
distillates, and tar, but not so much heat as to cause
carbonization. The hydrocarbon stream may be heated, such as in a
furnace or soaker vessel to a desired temperature, as a desired
pressure. The process used may be, for example, the coil type,
which provide for high temperature-short residence time, or the
soaker process, which provides for lower temperature--longer
residence time processing, as appropriate to obtain the desired
broken product mix. The hydrocarbon feed stream may be heat soaked
to reduce the viscosity and chain length of the hydrocarbon
molecules, by cracking the molecules in the liquid phase. See, for
example, Hydrocarbon Processing, September 1978, page 106.
Visbreaking occurs when a heavy hydrocarbon, or resid, is heat
soaked at high temperature, generally from about 700.degree. F.
(371.degree. C.) to about 900.degree. F. (371.degree. C. to about
482.degree. C.) for several minutes before being quenched to stop
the reaction. Some of the resid molecules crack or break producing
components that can be removed by standard atmospheric and vacuum
distillation. Resid conversion in a visbreaker increases with
increasing temperature and increasing residence time. High severity
visbreaking maximizes conversion of 1050.degree. F.+ resid and is
accomplished by soaking the visbreaker feedstock at greater than
about 840.degree. F. (450.degree. C.) for the longest time
reasonably possible, without forming substantial coke or
carbonization.
[0043] As an example, at least a portion of the hydrocarbon feed
containing non-volatile components (e.g., resid) is vaporized, such
as during (i) hydroprocessing, (ii) when combined with steam,
and/or (iii) when the pressure is reduced or flashed between a
hydroprocessing unit and a pyrolysis unit (e.g., a steam cracking
furnace). The term "hydroprocessing" as used herein is defined to
include those processes comprising processing a hydrocarbon feed in
the presence of hydrogen and a catalyst to hydrogenate or otherwise
cause hydrogen to react with at least a portion of the feed. This
includes, but is not limited to, a process comprising the step of
heating a resid-containing hydrocarbon feed stream in a
hydroprocessing step in the presence of hydrogen, preferably also
under pressure. The catalytically active material may be applied to
surfaces within the equipment and tubes upstream of the reaction
zone, within the reaction zone and/or within the equipment and
tubes downstream of the reaction zone.
[0044] As one embodiment, the present techniques may involve a
process environment that is a reducing environment. That is, the
hydrocarbon processing system is operated in the presence of
H.sub.2, which is either added or formed in situ, such as by a
hydrotreater preheat furnace or other unit, for example. Other
hydrocarbon processing systems are conventionally operated in the
absence of H.sub.2, such as steam cracking furnaces, cokers and
their associated tubes and subsystems. By adding H.sub.2 to the
process streams in these systems and/or subsystems, coking can be
inhibited through catalytic hydrogenation of coke in the presence
of various well-known hydrogenation catalyst materials. The
hydrogen (H.sub.2) containing stream may include the compositions
noted above.
[0045] For catalytic reaction that involves hydrogen (H.sub.2)
gasification of coke, the process conditions, such as the
environment, should include H.sub.2 containing stream that is
present at sufficient partial pressure so that it is the
thermodynamically favored route for H.sub.2 to react with the coke
to produce methane or other light hydrocarbons rather than in a
thermodynamic regime which favors hydrocarbon decomposition to coke
and H.sub.2. That is, the present techniques should optimize the
amount of excess hydrogen to provide a reducing environment to
react with coke and does not involve the addition of excessive
hydrogen. Process environment may be adjusted (e.g., the
concentration of H.sub.2) along with the other process conditions
(e.g., total pressure and/or temperature) to be in the proper
regime. The catalytic material and process conditions should also
be such that an extensive amount of hydrogenation of the desired
feeds and products does not occur.
[0046] Similar to the discussion of hydrocarbon processing
apparatuses and systems that are conventionally operated in the
presence of H.sub.2, the process environment may include an
oxidizing environment. In these embodiments, an oxidant stream may
be added to the hydrocarbon streams in these apparatuses, systems
and/or subsystems to inhibit coking through catalytic oxidation of
coke in the presence of various well-known oxidation catalyst
materials. The oxidant stream may include the compositions noted
above.
[0047] For catalytic reaction that involves oxidation of coke, the
process conditions should include an oxidant stream that is present
at sufficient partial pressure so that it is the thermodynamically
favored route for the oxidant to react with the coke to produce
carbon monoxide (CO) or carbon dioxide (CO.sub.2) rather than in a
thermodynamic regime which favors CO and CO.sub.2 decomposition to
coke and CO.sub.2 and/or H.sub.2O. Process environment may be
adjusted (e.g., the concentration of oxidant) along with the other
process conditions (e.g., total pressure and/or temperature) to be
in the proper regime. The catalytic material and process conditions
should be maintained so that sufficient oxidation of the coke
occurs, but the amount of oxidation of valuable hydrocarbon feed
and/or product hydrocarbon molecules is not significant.
Significant oxidation of valuable hydrocarbon feed and/or product
hydrocarbon molecules is undesirable both because of loss of
valuable molecules but also due to the formation of excessive
amounts of carbon oxides which are contaminants in the product. The
oxidant stream may be adjusted based on the output of contaminates
(e.g., CO and CO.sub.2) being generated for the process. Without
this optimization, the recovery equipment has to be sized for
increased capacity and contaminates have to be managed through the
process, which increases system complexity, costs, and
inefficiencies.
[0048] According to certain embodiments of the present techniques,
the oxidation catalyst may be utilized in an oxidizing environment
upstream of the reaction zone for a pyrolysis system. That is, the
oxidation catalyst may be applied on surfaces at locations upstream
of the reaction zone (e.g., the radiant tubes for a steam cracker)
to enhance the process under certain process conditions and process
environments. In particular, the oxidation catalyst may form a
layer (e.g., a coating on a structural member or formed on an outer
layer of the structural member) on at least a portion of the
surfaces within tubes or equipment upstream of the reaction zone,
within the reaction zone, and/or downstream of the reaction zone.
The oxidation catalyst may be utilized to reduce coking in this
region. Further, the stream being provided to the reaction zone may
be subjected to partial cracking conditions (e.g., higher
temperatures and/or pressures, which may include visbreaking
conditions) upstream of the reaction zone. By utilizing the
oxidation catalyst, the process conditions may be utilized to
maximize the amount of hydrocarbons being subjected to the reaction
zone, while minimizing the coking problems in the upstream
locations.
[0049] The cracking or conversion of the hydrocarbons typically is
performed within a reaction zone of a pyrolysis system. This
reaction zone may be the radiant tubes for a steam cracking system
and/or a central region within a regenerative reverse flow reactor,
which may include a portion of the reactor beds. This reaction zone
may be the primary location where heat for the chemical conversion
of the hydrocarbons is provided, which may result in the formation
of coke. This coking may again be influenced by the feed
composition, temperatures, etc. For instance, the higher the final
boiling point of the reactor feed, the higher the content of
species which increase the rate of coking on the equipment
surfaces.
[0050] To further enhance the operation of these different systems,
it may be desirable to utilize the catalytic coating to reduce or
minimize coking. In pyrolysis systems, one location where the
catalytically active species can be deposited is on the inner
surface of the process tubes or equipment upstream of the reaction
zone. As an example, the catalytic coating may be applied to
surfaces in a liquid vapor separation unit integrated with the
convection section of a steam cracker furnace, in a pulsed
compression reactor upstream of a reaction zone or upstream of
regenerative reverse flow reactor, in process tubes in the
convection section of the steam cracking furnace, and/or in inlet
and/or outlet manifolds, tubes and/or reactor components (e.g.,
valves, mixers, monoliths, pistons and the like) within a
regenerative reverse flow reactor. This catalytic coating may be
utilized at locations where the stream is exposed to the dry point
(e.g., when a mixture having liquid component and solid component
is heated to form a vapor component and a solid component). Other
advantageous locations are the inner surfaces of the process tubes
in the reaction zone, such as surfaces in radiant section of the
steam cracking furnace, and/or locations downstream of the reaction
zone, such as the inner surfaces of the process tubes downstream of
radiant section or in transfer line exchangers (TLEs).
[0051] As used herein, the "hydrocarbon stream" may include a
hydrocarbon feed provided to a pyrolysis system and as it passes
through the pyrolysis system. The hydrocarbon stream may have
various fluids added to the stream and/or have certain portions
removed from the stream as it passes through the system.
[0052] As used herein, the "hydrocarbon feed" contains hydrocarbons
(C bound to H) and may contain (i) minor components of heteroatoms
(<10 wt %) covalently bound to hydrocarbons and (ii) minor
components of heteroatoms (<10 wt %) not bound to hydrocarbons
(e.g., H.sub.2O), wherein these weight percents are based on the
weight of the hydrocarbon feed. The hydrocarbon feed may include,
by way of non-limiting examples, one or more of Fischer-Tropsch
gases, methane, methane containing streams such as coal bed
methane, biogas, associated gas, natural gas and mixtures or
components thereof, steam cracked gas oil and residues, gas oils,
heating oil, jet fuel, diesel, kerosene, gasoline, coker naphtha,
steam cracked naphtha, catalytically cracked naphtha,
hydrocrackate, reformate, raffinate reformate, Fischer-Tropsch
liquids, natural gasoline, distillate, virgin naphtha, crude oil,
atmospheric pipestill bottoms, vacuum pipestill streams including
bottoms, wide boiling range naphtha to gas oil condensates, heavy
non-virgin hydrocarbon streams from refineries, vacuum gas oils,
heavy gas oil, naphtha contaminated with crude, synthetic crudes,
shale oils, coal liquefaction products, coal tars, tars,
atmospheric resid, heavy residuum, C4's/residue admixture, naphtha
residue admixture, cracked feedstock, coker distillate streams,
hydrocarbon streams derived from plant or animal matter, and/or any
mixtures thereof. The hydrocarbon feed may also include indigenous
molecular species that also include atoms other than carbon and
hydrogen, such as sulfur containing species, nitrogen containing
species, oxygen containing species, halogen containing species, and
metal containing species.
[0053] The term "hydrogen content" means atomic hydrogen bound to
carbon and/or heteroatoms covalently bound thereto and which
excludes molecular hydrogen (H.sub.2) in the hydrocarbon feed
expressed as a weight percent based on the weight of the
hydrocarbons in the hydrocarbon feed. Hydrogen content as applied
to hydrocarbon feed or reactor feed are expressed as an ASTM weight
percent of hydrocarbons in the respective feed. The hydrogen
content of hydrocarbon feeds, reactants and products for present
purposes can be measured using any suitable protocol, (e.g., ASTM
D4808-01 (2006) Standard Test Methods for Hydrogen Content of Light
Distillates, Middle Distillates, Gas Oils, and Residua by
Low-Resolution Nuclear Magnetic Resonance Spectroscopy or ASTM
D5291-10 Standard Test Methods for Instrumental Determination of
Carbon, Hydrogen, and Nitrogen in Petroleum Products and
Lubricants).
[0054] The term "reactor feed" means the composition, which may be
a mixture, subjected to pyrolysis in the reaction zone. In one
embodiment, the reactor feed is derived from a hydrocarbon feed
and/or stream (e.g., by separation of a portion from the
hydrocarbon feed and optional addition of fluids (e.g.,
diluents)).
[0055] As used herein, "resid" refers to the complex mixture of
heavy petroleum compounds otherwise known in the art as residuum or
residual. Atmospheric resid is the bottoms product produced in
atmospheric distillation when the endpoint of the heaviest
distilled product is nominally 343.degree. C., and is referred to
as 343.degree. C.+ resid. Vacuum resid is the bottoms product from
a column under vacuum when the heaviest distilled product is
nominally 566.degree. C., and is referred to as 566.degree. C.+
(e.g., temperatures above 566.degree. C.) resid. The term
"nominally" means here that reasonable experts may disagree on the
exact cut point for these terms, but probably by no more than
+/-30.degree. C. or at most +/-75.degree. C. This 566.degree. C.+
portion contains asphaltenes, which are problematic to the steam
cracker, resulting in coking of the surfaces within the
furnace.
[0056] As used herein, the expression "non-volatiles" may be
defined broadly herein to mean substantially any metal, mineral,
ash, ash-forming, asphaltenic, tar, coke, and/or other component or
contaminant within the feedstock that does not vaporize below a
selected boiling point or temperature and which, during or after
pyrolysis, may leave an undesirable residue or ash within the
reactor system, which is difficult to remove. Distillation
fractions of a feed can be determined via testing methods American
Society of Testing and Materials (ASTM) D2887 or D1160.
[0057] The terms "heavy" and "light" in reference to a hydrocarbon
fraction refers to the hydrocarbon's boiling point, with "heavy"
referring to fractions having higher boiling point (e.g., boiling
at higher temperature) and "light" referring to fractions having
lower boiling point. Boiling points, when used to characterize
fractions (e.g., fraction heavier than 565.degree. C.) are given at
atmospheric pressure, although actual distillation may be carried
out at reduced temperature and pressure, as is known in the
art.
[0058] Non-combustible non-volatiles may include ash, for example.
Methods for determining asphaltenes and/or ash may include ASTM
methods, such as methods for asphaltenes may include ASTM D-6560
and D-7061 and methods for ash may include ASTM D-189, D-482,
D-524, and D-2415. In the context of a feed, non-volatiles are
materials that are not in the gas phase (e.g., are components that
are in the liquid or solid phase) at the temperature, pressure and
composition conditions of the inlet to the pyrolysis unit. For
certain pyrolysis units, such as a regenerative reverse flow
reactor or other thermal pyrolysis units, non-combustible
non-volatiles (e.g., ash; ASTM D-189) in the reactor feed may be
preferably limited to .ltoreq.2 parts per million weight (ppmw) on
reactor feed, more preferably .ltoreq.1 ppmw. Combustible
non-volatiles (e.g., tar, asphaltenes, ASTM D-6560) may be present
in the reactor feed for these regenerative reverse flow reactors at
concentrations below 10 wt % of the hydrocarbons in the reactor
feed, preferably at concentrations below 1 wt %, most preferably at
concentrations below 100 ppmw of the total hydrocarbons of the
reactor feed to the pyrolysis unit (or ranges in between), as long
as the presence of the combustible non-volatiles do not result in
excessive (e.g., .gtoreq.2 or .gtoreq.1 ppmw) concentrations of
non-combustible non-volatiles. Exemplary embodiments are described
further below in FIGS. 2-4.
[0059] FIG. 2 is an exemplary embodiment of a steam cracker system
that may be utilized in accordance with the present techniques. In
this configuration, a furnace 1, which may be any of a variety of
furnaces, includes a convection section 3 and a radiant section 40.
The convection section 3 includes various convection section tube
banks (e.g., first tube bank 2, second tube bank 6, third tube bank
49 and fourth tube bank 23), which may use hot flue gases from the
radiant section of the furnace to heat fluids within the respective
tube banks.
[0060] Along the flow path through the furnace 1, a hydrocarbon
feed may have other fluids added, such as steam and/or other
hydrocarbons, to the hydrocarbon stream. For instance, the mixing
can be accomplished using any mixing device known within the art,
such as a first sparger 4 or second sparger 8 of a double sparger
assembly 9. In particular, a fluid may pass through a fluid valve
14 and a primary dilution steam may be passed via primary dilution
line 17 through a primary dilution steam valve 15 to be mixed with
the heated hydrocarbon feed in the respective spargers 4 or 8 to
form a mixture stream in lines 11 and 12, which pass through
controller 7. Also, a secondary dilution steam stream 18 can be
heated in the superheater section 16 of the convection section, may
be combined with water via water line 26 through an intermediate
desuperheater 25 (e.g., control valve and water atomizer nozzle),
and mixed with the heated mixture stream. Optionally, the secondary
dilution steam stream 18 may be further split into a flash steam
stream in flash steam line 19, which is mixed with the heavy
hydrocarbon mixture, and a bypass steam stream in bypass line 21,
which is mixed with the vapor phase from the flash before the vapor
phase is cracked in the radiant section 40. The flash steam stream
may be combined with the mixture stream to form a flash stream in
flash line 20.
[0061] Along with the addition of certain fluids, certain portions
of the hydrocarbon steam may be removed from the process as well.
For example, a separator vessel 5 (e.g., flash separator vessel, as
exemplified in U.S. Pat. Nos. 7,578,929; 7,488,459; 7,247,765;
7,193,123 and 7,312,371, which are each incorporated herein) may be
utilized to separate the flash stream 20 into two phases: a vapor
phase comprising predominantly volatile hydrocarbons and steam and
a liquid phase comprising predominantly non-volatile hydrocarbons.
The vapor phase is preferably removed from the separator vessel 5
as an overhead vapor stream is further processed in a centrifugal
separator 38, which removes trace amounts of entrained and/or
condensed liquid, before being passed via overhead line 13, vapor
phase control valve 36, and crossover line 24 to the radiant
section 40 for cracking (e.g., reactor feed). The liquid phase of
the flashed mixture stream is removed from a boot or cylinder 35 on
the bottom of the separator vessel 5 as a bottoms stream 27. This
stream 27 may be further processed in a pump 37 and cooler 28 with
the cooled stream 29 being split into a recycle stream 30 and
export stream 22.
[0062] Once the stream is exposed to heat in the radiant section
40, the reactor product or effluent may be further processed. For
instance, the process may include optional cooling of the effluent
from the radiant section 40 in one or more transfer line heat
exchangers, a primary fractionator, and a water quench tower or
indirect condenser. In this configuration, the effluent may pass
via line 41 to a transfer-line exchanger 42 to provide a cooled
effluent via quench line 43 for further processing. A utility
fluid, such as boiler feed water, may also pass through the
transfer-line exchanger 42 to steam drum 47 via lines 44 and 45.
The steam drum 47 may be coupled to the third tube bank 49 to
generating high pressure steam via lines 48, 50, 52 and 53 and a
utility supply line 46. A steam control valve may be coupled
between lines 50, 51 and 52 to provide a water source that controls
the temperature of the steam.
[0063] To operate, various stages may heat the hydrocarbon stream
to different temperatures. For instance, the hydrocarbon stream may
be heated to temperatures between about 150.degree. C. and
260.degree. C. in the first tube bank 2, while the stream may be
heated in the second tube bank to temperatures between 315.degree.
C. and 540.degree. C., which is also the temperature utilized in
the separator vessel 5. The vapor phase from the separator vessel 5
is further heated in fourth or lower convection section tube bank
23 to temperatures between 425.degree. C. to 705.degree. C., while
the tubes of the radiant section 40 may further expose the vapor
phase to temperatures between 600.degree. C. and 1000.degree. C.
Further, the temperature of the recycled stream via line 30 may be
at temperatures between 260.degree. C. to 315.degree. C.
[0064] The formation of coke and/or coke precursors may be a
problem for certain within this system. For example, coking may
occur at locations upstream of the reaction zone, which is the
radiant section 40 for this system. To reduce or minimize coking, a
catalytic material may be applied upstream of the reaction zone. As
a specific example, a structural member may have at least one
surface (e.g., at least one surface within the interior (in contact
with the hydrocarbon stream) of the separator vessel 5, of the tube
banks 2, 6 and 23, of the centrifugal separator 38, of the lines
12, 13, 24 and/or 30, of the phase control valve 36 and of the
spargers 4 and 8) having a catalytic material that is disposed over
the at least a portion of its surface. This catalytic material may
promote the reaction of H.sub.2 and/or oxidant with coke and/or
coke precursors at temperatures greater than 150.degree. C.,
greater than 200.degree. C. and/or greater than 250.degree. C.
[0065] As an example, a catalytic material may be utilized in
process conditions that reduce coking within the system, extend
hydrocarbon processing operations and increase feed flexibility. As
an example, the separator vessel 5, condenser 38, lines 13 and 24
and tube bank 23 may include a catalytic material on at least a
portion of the surfaces within these structural members. By
including the catalytic material, the separator vessel 5 may be
operated at process conditions that without the catalytic material
would produce more coke (e.g., visbreaking conditions prior to
steam cracking in the reaction zone). These process conditions may
maximize conversion of resid to lower boiling fractions by
increasing the temperatures earlier in the process to promote
incipient thermal cracking, which may maximize the portion of the
hydrocarbon stream that is vaporized in the separator vessel 5. The
process conditions may involve initiating incipient thermal
cracking in the tube banks and/or separator vessel 5, and may
include temperatures greater than or equal to 371.degree. C.,
greater than or equal to 399.degree. C., greater than or equal to
415.degree. C. and at sufficient partial pressure. The pressure may
include 50 psig to 200 psig. These process conditions may maximize
conversion of resid to lower boiling fractions, such as resid
fractions having boiling points of up to and in excess of
593.degree. C. (593.degree. C..sup.+) fractions, and even a portion
of the resid fractions up to 760.degree. C.
[0066] The process conditions are performed under an oxidizing or
reducing environment as part of the process. That is, upstream of
the reaction zone, the different fluids added to the hydrocarbon
stream may be managed to control the environment that may promote
the conversion of coke and coke precursors via kinetic pathways for
removal of the coke and/or coke precursors. In the reducing
environment, catalytic material is active to gasify the coke and/or
coke precursors. This reducing environment may involve the addition
of a hydrogen (H.sub.2) containing stream. Also, for an oxidizing
environment, the catalytic material is active to oxidize the coke
and/or coke precursors. This oxidizing environment may involve the
addition of an oxidant containing stream, such as H.sub.2O,
CO.sub.2, O.sub.2, and mixtures thereof.
[0067] Accordingly, with the catalytic material, various stages of
feed pretreatment may operate at higher temperatures with reduced
coking as opposed to conventional practices, which may provide more
of the hydrocarbon feed to the reaction zone and still maintaining
or reducing the coking of the upstream equipment surfaces. For
instance, the hydrocarbon stream may be heated to temperatures
between about 260.degree. C. and 360.degree. C. in the first tube
bank 2, while the stream may be heated in the second tube bank to
temperatures between 460.degree. C. and 650.degree. C., which is
also the temperature utilized in the separator vessel 5. At the
separator vessel 5, a hydrogen (H.sub.2) containing stream may be
added to the hydrocarbon stream in a hydrogen (H.sub.2) to carbon
of greater than 0.1 mole %, 1 mole % or even 5 mole %.
Alternatively, steam may be added to the hydrocarbon stream in an
amount greater than 1.0 mole %, greater than 20.0 mole %, or even
greater than 50.0 mole %. The vapor phase from the separator vessel
5 is further heated in fourth or lower convection section tube bank
23 to temperatures between 620.degree. C. to 705.degree. C., while
the tubes of the radiant section 40 may further expose the vapor
phase to temperatures between 650.degree. C. and 1000.degree. C.
Further, the temperature of the recycled stream via line 30 may be
at temperatures between 360.degree. C. to 415.degree. C.
[0068] Further, in addition to the catalytic material upstream of
the reaction zone, a catalytic material may be utilized within the
reaction zone for certain process conditions. That is, the
catalytic material may be utilized on the interior surface of the
tubes within the radiant section 40. In the reaction zone, the
hydrogen (H.sub.2) containing stream or oxidant containing stream
may be added upstream or prior to the radiant zone to provide the
proper environment for the catalytic material. In particular, a
hydrogen containing stream may be useful to provide that the
environment is a reducing environment. The reducing environment may
be beneficial to minimize the undesirable byproducts, such as CO
and CO.sub.2, which may result in an oxidizing environment.
Regardless, the use of the catalytic material may reduce coking to
enhance operations by extending the time that the units may be
utilized for hydrocarbon processing operations without having to be
interrupted to perform decoking operations.
[0069] Moreover, the catalytic material may be used at downstream
locations from the reaction zone. As an example, the catalytic
material may be utilized on the interior surface of the lines 41
and 43 along with the interior surfaces the transfer-line exchanger
42. At these downstream locations, a hydrogen (H.sub.2) containing
stream or oxidant containing stream may also be added to the
reactor product or hydrocarbon stream downstream of the reaction
zone and upstream equipment having the catalytic material to
provide the proper environment for the catalytic material. The
catalytic material may be utilized to reduce the coking resulting
from the cooling of the stream, as some molecules begin to condense
(e.g., the "dew point"). If this deposition occurs on the internal
surface of equipment at these downstream locations, the catalytic
material may be utilized to inhibit or reduce coking. Regardless,
the use of the catalytic material may reduce coking to enhance
operations by extending the time that the equipment may be utilized
without having to be interrupted to perform decoking
operations.
[0070] Furthermore, in addition to the hydrocarbon processing
operations, the catalytic material may be used to enhance decoking
operations as well. During decoking operations, air and/or steam is
typically provided to the system to burn off any coke deposits. To
enhance this decoking operation, it may be beneficial to include a
catalytic material on the surface of structural members, similar to
those discussed above, which may have coke deposits. The catalytic
material may be an oxidation catalyst, which may be rendered
catalytically active at process conditions, to promote the reaction
of coke and/or coke precursors with the oxidants at temperatures
greater than 150.degree. C., greater than 200.degree. C. and/or
greater than 250.degree. C. The coke at or near the surface may
react in the presence of the catalytic material to convert at least
a portion of the coke to vapor products, which may be removed from
the system. Alternatively, the catalytic material may be a
hydrogenation catalyst, which may be rendered catalytically active
at process conditions, to promote the reaction of coke with
hydrogen (H.sub.2) at temperatures greater than 150.degree. C.,
greater than 200.degree. C. or greater than 250.degree. C. Again,
this may involve exposing the coke and catalytic material to a
hydrogen (H.sub.2) stream, as noted above.
[0071] Another suitable pyrolysis system, which can benefit from
the present techniques, is a regenerative reverse flow reactor
system. A regenerative reverse flow reactor system may be used for
the manufacture of acetylene from a hydrocarbon feed, such as
methane. FIG. 3 illustrates a regenerative reverse flow reactor
system 200 having a regenerative reverse flow reactor 202, a
separator vessel 223, and two heat exchangers 219 and 229. The
regenerative reverse flow reactor 202 has reactor beds 204 and 206
along with one or more injection components 213, 215 and 225, one
or more removal components 217 and 227 and one or more lines 212,
214, 218, 220, 222, 224, 228 and 230 providing fluid flow paths
through the system. These components manage the flow of various
streams (e.g., reactor feeds, combustion feeds, combustion products
and reaction products) through the system. Further, the separator
vessel 223 and heat exchangers 219 and 229, which may be similar to
the transfer line exchanger 42 and separator vessel 5 of FIG.
2.
[0072] The regenerative reverse flow reactor 202 may include any
suitable regenerative reverse flow reactor, such as U.S. Published
Patent Application No. 2007/0191664 as an example. The reactor beds
204 and 206 are effective in storing and transferring heat to
carrying out chemical reactions and to produce products, such as
C.sub.2+ unsaturates (e.g., ethylene and acetylene). These beds 204
and 206 may include glass or ceramic beads or spheres, metal beads
or spheres, ceramic (including alumina, zirconia and/or yttria) or
metal honeycomb materials, ceramic tubes, extruded monoliths, and
the like, provided they are competent to maintain integrity,
functionality, and withstand long term exposure to temperatures in
excess of 1200.degree. C., preferably in excess of 1500.degree. C.,
more preferably in excess of 1700.degree. C., and even more
preferably in excess of 2000.degree. C. within reaction zone 208.
The reactor bed(s) 204 and 206 may provide separate channels for
the combustion feeds, such as a fuel stream and a combustion
oxidant stream, to isolate the streams until they are combined
within the reaction zone 208. The combustion oxidant stream may
include stream or CO.sub.2, or may be a separate stream, which may
include air, but has to include oxygen (O.sub.2). In this manner,
the temperature within the reactor may be managed to provide a
reaction zone 208 that is the location where the highest
temperatures are present.
[0073] The injection components 213, 215 and 225 and removal
components 217 and 227 may include one or more valves, reactor
heads, manifolds, spargers, tubes and manifolds and other
components. Specifically, the injection components 213, 215 and 225
may include injection valves and an injection manifold for each of
the different feeds being provided to the reactor 202. Similarly,
the removal components 217 and 227 may include one or more removal
valves and removal manifolds. These injection and removal
components may be made of a suitable material to provide a
structural member, which may be have a catalytic material on the
surface of the structural member.
[0074] To operate, the regenerative reverse flow reactor 202 may
involve different stages that follow a specific sequence to form a
cycle. In particular, the cycle may include a pyrolysis stage and
combustion stage. The combustion stage begins with the injection
combustion streams, such as a fuel via line 212 and fuel injection
manifold 213 and an oxidant via line 214 and oxidant injection
manifold 215. The combustion streams may be provided to an end of
the second reactor bed 206, passed through the second reactor bed
206 to the reaction zone 208. The combustions streams may
exothermically react in the reaction zone 208, which may include a
portion of the reactor beds, to heat at least a portion of the
reactor bed 204 and at least a portion of reactor bed 206, and are
passed to the combustion removal line 216 via the combustion
removal component 217 at an end of the reactor bed 204. Based on
the flow of the combustion stream, the temperature gradient may
reach a peak in the reaction zone 208 near and in a portion of the
first reactor bed 204, as the combustion products move across the
reactor bed 204 in the direction toward the combustion removal
components 217. The fuel and oxidant may be maintained as separate
streams to further control the location of the exothermic reaction
to the reaction zone 208. Regardless, the combustion products that
include CO, CO.sub.2 and/or H.sub.2O may be removed via the removal
components 217.
[0075] The pyrolysis stage begins with the injection the
hydrocarbon stream, such as methane, natural gas or other suitable
reactor feed, via line 224 and feed injection components 225 at the
first end of the first reactor bed 204. The hydrocarbon stream
passes through the first reactor bed 204 and reacts endothermically
from the heat stored in the reactor bed 204. The reactor products
may include the reacted products, such as acetylene and/or
ethylene, and unreacted hydrocarbons in the stream, which are
subsequently cooled as they pass through second reactor bed 206 to
the product removal line 228 via the product removal component
227.
[0076] To manage the different streams provided to and removed from
the reactor 202, various equipment, such as heat exchangers 219 and
229 and a separator vessel 223, may be utilized as part of this
process. The combustion products that include CO, CO.sub.2 and/or
H.sub.2O may be removed via the removal components 217 and provided
to the combustion heat exchanger 219 to recovery heat from the
combustion products. That is, the combustion products may be cooled
by passing water or the hydrocarbon stream at a lower temperature
on the utility side of the heat exchanger. Similarly, the
hydrocarbon stream may be provided via line 222 to the separator
vessel 223 that separates a bottoms product from the hydrocarbon
stream (e.g., reactor feed, which may be the vapor phase from the
separator vessel 223). The bottoms product may be further processed
into fuel or other products, while the remaining hydrocarbon stream
may be provided directly to the feed injection component 225 or
pass through the heat exchanger 219 to heat the reactor feed prior
to the feed injection component 225. The remaining hydrocarbon
stream may be provided alone, combined with an oxidant stream or
hydrogen containing stream to form the reactor feed. For the
reactor product, it may include C.sub.2 unsaturates, may be removed
via the product removal components 227, and may be provided to the
product heat exchanger 229 to recovery heat from the reactor
products. That is, the reactor products may be cooled by passing
water, fuel or oxidant at a lower temperature on the utility side
of the heat exchanger 229.
[0077] To operate, the various stages for the hydrocarbon
processing operations may involve different process conditions for
the respective stream (e.g., heat the respective streams to
different temperatures). For instance, the hydrocarbon stream may
be heated prior to the separator vessel 223 to temperatures in the
range of 100.degree. C. and 500.degree. C. The initial heating may
be performed in combustion heat exchanger 219, which utilizes the
heat from the combustion products to heat the hydrocarbon stream,
or may be performed in another unit, such as a furnace or boiler.
Also, the process may involve passing the vapor product from the
separator vessel 223 through the combustion heat exchanger 219 to
further heat the vapor phase from the combustion products prior to
the reactor 202. Regardless, the heated hydrocarbon stream (e.g.,
the reactor feed) is provided to the reactor and passes through the
feed injection component 225 and first reactor bed 204. In the
reaction zone 208, the hydrocarbons are exposed to temperatures in
the range of 1200.degree. C. to 2200.degree. C., in the range of
1500.degree. C. to 2000.degree. C., or in the range of 1600.degree.
C. to 1800.degree. C., which convert hydrocarbons in the
hydrocarbon stream into the reactor product. Then, the reactor
product is passed through the second reactor bed 206 to the product
removal component 227 and the heat exchanger 229. The reactor
product may be provided to the heat exchanger 229 at temperatures
in the range of 250.degree. C. to 500.degree. C., and may be cooled
to temperatures in the range of 150.degree. C. to 400.degree.
C.
[0078] Similar to the steam cracking system above, the formation of
coke and/or coke precursors may be a problem within this system.
Further, this process has some additional aspects that should be
considered. In particular, the process conditions in the reactor
202 include both oxidizing and reducing environments, which are
subject to the different stages in the cycle. That is, at least a
portion of the components within the reactor 202 are exposed to
both environments, while outside the reactor's interior region
(e.g., within the injection and removal components and subsequent
lines and equipment), the surfaces of the components may only be
exposed to one environment during normal operations, which is
similar to the steam cracking system, and may be exposed to an
oxidizing environment during decoking operations. Accordingly, for
this system different fluids may be added to the hydrocarbon
stream, fuel stream and/or combustion oxidant stream to control the
environment in a manner that promotes the conversion of coke and
coke precursors via kinetic pathways for removal of the coke and/or
coke precursors. Further, the catalytic material may be utilized at
certain locations on the reactor beds 204 and 206, which are not
exposed to temperatures greater than 600.degree. C., greater than
750.degree. C. or even greater than 900.degree. C. That is, the
catalytic material may be utilized on the ends of the reactor beds
204 and 206 (e.g., portions of the reactor beds 204 and 206 that
are not within the reaction zone 208 or exposed to higher
temperatures that may damage the catalytic material).
[0079] Accordingly, a catalytic material may be utilized in process
conditions that reduce coking within the system, extend hydrocarbon
processing operations and increase feed flexibility. For example,
coking may occur at locations upstream of the reaction zone 208 for
the hydrocarbon stream. To reduce or minimize coking, a catalytic
material may be applied upstream of the reaction zone. As a
specific example, a structural member having at least one surface
(e.g., at least one surface within the interior (in contact with
the hydrocarbon stream) of the separator vessel 223, of the
combustion heat exchanger 219, of the feed injection components or
of portions of the combustion removal components 225, 217, or
portions thereof, such as poppet valve heads (not shown), within
the reactor 202, of the reactor bed 204 and/or of the lines 222,
224 and/or others (not shown)) having a catalytic material over the
at least one surface. This catalytic material may be rendered
catalytically active for the reaction with coke and/or coke
precursors at temperatures greater than 150.degree. C., greater
than 200.degree. C. and/or greater than 250.degree. C. The
catalytic material may be utilized on the reactor bed 204 near the
feed injection end, which is not exposed to temperatures that may
damage the catalytic material, as noted above.
[0080] Similar to the discussion above, the catalytic material may
form a layer on the surfaces within these structural members. By
including the catalytic material, the separator vessel 223 may be
operated at process conditions that produce more coke (e.g.,
visbreaking conditions). These process conditions may maximize
conversion of resid to lower boiling fractions by increasing the
temperatures earlier in the process to promote incipient thermal
cracking, which may maximize the portion of the hydrocarbon stream
that is vaporized in the separator vessel 223. The process
conditions may involve initiating incipient thermal cracking in the
heat exchanger 219 and/or separator vessel 223, and may include
temperatures greater than or equal to 371.degree. C., greater than
or equal to 399.degree. C., greater than or equal to 415.degree. C.
and at sufficient process pressure to enable flow to the next
process step.
[0081] As noted above, the process environment may be adjusted to
further enhance the process. In particular, a hydrogen (H.sub.2)
containing stream or oxidant stream may be added to the separator
223 or upstream of the separator 223 to provide a specific
environment. That is, hydrogen (H.sub.2) may be added to the
hydrocarbon stream to provide a reducing environment or
alternatively, steam may be added to the hydrocarbon stream to
provide an oxidizing environment.
[0082] While the catalytic material may not be utilized within the
reaction zone 208 because of the higher temperatures, a catalytic
material may be utilized downstream of the reaction zone 208 within
the reactor 202 and on surfaces downstream of the reactor 202. As a
specific example, a structural member may have at least one surface
(e.g., at least one surface within the interior (in contact with
the reactor products) of the injection components 213 and/or 215
within the reactor 202 (such as, poppet valve heads), of the heat
exchanger 229, portion of the injection components 225, of portions
of the combustion removal components 217 within the reactor 202
(poppet valve heads), of the reactor bed 204 and/or of the lines
228 and/or 230) having a catalytic material on at least one
surface. As noted above, these downstream locations may also
include the addition of a hydrogen (H.sub.2) containing stream or
oxidant containing stream to the reactor product or hydrocarbon
stream downstream of the reaction zone 208 and upstream equipment
having the catalytic material to provide the proper environment for
the catalytic material. The catalytic material may be utilized to
reduce the coking resulting from the cooling of the stream, as some
molecules begin to condense (e.g., the "dew point"). Regardless,
the use of the catalytic material may reduce coking (e.g., to
prevent oligomerization or polymerization of those materials and
subsequent deposition as coke) to enhance operations by extending
the time that the equipment may be utilized without having to be
interrupted to perform decoking operations.
[0083] With regard to the combustion stage of the cycle, the fuel
stream, combustion oxidant stream and combustion products may also
be utilized to reduce coking and enhance the process. For example,
coking may occur at locations upstream of the reaction zone 208 for
the fuel stream, while the combustion oxidant stream is expected to
remove coke in the portions of the reactor bed 206 that the
combustion oxidant stream flows through. Accordingly, to reduce or
minimize coking, a catalytic material may be applied upstream of
the reaction zone 208 for these streams. As a specific example, a
structural member may have at least one surface (e.g., at least one
surface within the interior (in contact with the fuel or combustion
oxidant streams) of the injection components 213 and 215, of the
heat exchanger 229 which is exposed to the combustion oxidant or
fuel stream, of a portion of the removal component 227 that are
exposed to the streams (such as, the poppet valve heads), of the
reactor bed 206 and/or of the lines 212 and/or 214) having a
catalytic material on the at least one surface. This catalytic
material is rendered catalytically active for the reaction with
coke and/or coke precursors at temperatures greater than
150.degree. C., greater than 200.degree. C. and/or greater than
250.degree. C., but should not be exposed to certain temperatures,
as noted above.
[0084] Similar to the discussion above, the catalytic material may
be used on surfaces within these structural members that are
utilized to provide the fuel stream to the reactor. By including
the catalytic material, the fuel stream to the reactor 202 may be
provided at process conditions that may produce coke. That is, the
fuel stream or combustion oxidant stream may recover heat from the
reactor products in the heat exchanger 229. By providing the fuel
stream at these higher temperatures, the reactor 202 may be managed
to reduce the temperature swing within the reactor 202, which
reduces fatigue on components within the reactor, enhances the
energy efficiency by reducing the amount of heat to be generated,
and enhance efficiency by recovering heat from the different
streams.
[0085] Also, the process environment may be adjusted to further
enhance the process. In particular, a hydrogen (H.sub.2) containing
stream or oxidant stream may be added to the separator vessel 223
or upstream of the separator vessel 223 to provide a specific
environment. That is, hydrogen (H.sub.2) may be added to the
hydrocarbon stream to provide a reducing environment or
alternatively, an oxidant, such as steam, may be added to the
hydrocarbon stream to provide an oxidizing environment. The use of
these streams operates similar to the discussion above.
[0086] While the catalytic material may not be utilized within the
reaction zone 208 because of the higher temperatures, as noted
above, a catalytic material may be utilized downstream of the
reaction zone 208 within the reactor 202 and on surfaces downstream
of the reactor 202. As a specific example, a structural member may
have at least one surface (e.g., at least one surface within the
interior (in contact with the combustion products) of the injection
components 225 within the reactor 202 (such as, poppet valve
heads), of the heat exchanger 219, portion of the removal
components 217, of the reactor bed 204 and/or of the lines 218
and/or 220) having a catalytic material on the at least one
surface. As noted above, these downstream locations may also
include the addition of a hydrogen (H.sub.2) containing stream or
oxidant containing stream to the combustion product downstream of
the reaction zone 208 and upstream equipment having the catalytic
material to provide the proper environment for the catalytic
material.
[0087] Further, as yet another embodiment, the process may be
conducted in a pyrolysis system that includes a pulsed compression
reactor in the pretreatment stages for a pyrolysis unit. In this
embodiment 300, a preheater 302, a pulsed compression reactor 304,
a wash drum 306, a high pressure separator 308 and pyrolysis unit
310 are coupled together via lines 320, 322, 324, 326, 330, 332,
334, 336 and 338. This system may utilize a catalytic material to
enhance the processing of a hydrocarbon stream in a manner similar
to the discussion above of the steam cracking system of FIG. 2 or
regenerative reverse flow reactor system of FIG. 3. The embodiment
is explained in further detail below.
[0088] To begin, a hydrocarbon stream in line 320 is combined with
a hydrogen containing stream via line 322, and optionally with
steam via line 324, a catalyst stream via line 326, and/or a
recycle stream (not shown); and sent to a preheater 302. The
mixture of lines 320, 322, 324 and 326 are initially provided to a
pre-heater 302 to heat to a temperature sufficient to vaporize at
least a portion of the mixture. The preheater may include a heat
exchanger, boiler or other suitable device. Then, the heated
mixture is provided to the pulsed compression reactor 304 via line
330. The pulsed compression reactor 304 may be any suitable pulsed
compression reactor, such as the pulsed compression reactor
disclosed in U.S. patent Ser. No. 12/689,154, incorporated by
reference herein in its entirety. The pulsed compression reactor
304, which comprises a free piston enclosed within a double-ended
cylinder having an inlet port and an outlet port. The piston is
free to reciprocate between limiting positions so as to form
compression chambers at either end of the cylinder between the end
of the free piston and the internal surface of the cylinder end,
which is either coated or impregnated with the catalytic materials
of the present techniques.
[0089] In the pulsed compression reactor 304, the mixture flows
across the cylinder in which the free piston, dividing the cylinder
into two compression-reaction chambers, reciprocates with a very
high frequency, such as up to 400 Hz, compressing the mixture in
lower and upper chambers. The rapid compression of the mixture in
each chamber results in its heating to sufficiently high
temperatures and pressures to drive chemical reactions.
Advantageously, when the chemical reaction is exothermic, the
resulting expansion of the reactants acts to force the piston in
the opposite direction to compress the reactants in the opposite
compression chamber. A reaction product exits outlet port via line
332 to wash drum 306.
[0090] In a preferred embodiment, catalytically active
metals/compounds for hydrogenation, such as Mo, Ni, Co, V, Fe, Cu
and/or compounds thereof, and combinations thereof may be added as
a mobile catalyst to the distillate feed via stream 326, and/or
recycled via stream, to enhance the hydrogenation reactions which
occur. A mobile catalyst may comprise: (i) a vapor phase species,
(ii) a liquid phase species; (iii) a material dissolved in a
hydrocarbon; and/or (iv) solid particles of sufficiently small size
to be entrained in the hydrocarbon. In a particularly preferred
embodiment, the hydrogenation catalysts are deposited on a
carbonaceous solid, such as soot formed during the process, which
aids in hydrogen transfer. In an alternative embodiment, the
hydrogenation catalyst may be a stationary catalyst which is
incorporated within combustion chambers.
[0091] Due to the short residence times and rapid decompression
inherent in the compression reactor 304, the stream leaving the
reactor 304 through line 332 are rapidly quenched, avoiding
undesirable chemical recombinations, such as oligomerization or
polymerization, of the reaction products. The wash drum 306 acts to
remove catalyst/soot and uncracked bottoms as a liquid stream from
the vaporized stream, and recycle those liquid by-products via line
(not shown) to the beginning of the process. A portion of the
bottoms from the wash drum 306 may be purged to remove and recover
excess soot and metals (not shown). The soot and metals may be
separated or concentrated from the bulk of the bottoms from the
wash tower by filtration or centrifugation.
[0092] The washed stream are passed through line 334, optionally
cooled, and sent into a high pressure separator 308 to separate
remaining hydrogen-containing gas (not shown) for potential recycle
to the system, or for other refinery uses, and the upgraded liquid
hydrocarbon via line 336, (e.g., the hydroprocessed product), may
be sent downstream to a pyrolysis unit 310, such as a steam cracker
or regenerative reverse flow reactor. In one embodiment, the
upgraded liquid hydrocarbon is sent to a vapor/liquid separator or
separator 310, wherein at least a portion of the separated
hydrocarbon vapors via line 338 are forwarded to a steam cracker
for further cracking, and the separated liquid bottoms 340 may be
recycled to wash drum 306.
[0093] According to the present embodiment, liquid hydrocarbon
feeds, even ones containing resid, can be hydroprocessed in a
pulsed compression reactor as a pretreatment for the pyrolysis unit
310. Suitable liquid hydrocarbon feeds may include, but are not
limited to vacuum tower bottoms, resid, fuel oil, steam cracking
separator bottoms (e.g., flash drum bottoms prior to the cracking
the feed), atmospheric tower bottoms, steam cracker tar, whole
crude oil, coker products, and/or FCC bottoms.
[0094] The formation of coke and/or coke precursors may be a
problem within this system, as noted above with the other systems.
For example, coking may occur at locations upstream of the reaction
zone, which is within the pyrolysis unit 310. To reduce or minimize
coking, a catalytic material may be applied upstream of the
reaction zone. As a specific example, a catalytic material may be
applied to structural members having at least one surface (e.g., at
least one surface within the interior (in contact with the
hydrocarbon stream) of the preheater 302, at the top of each end of
the cylinder in a pulsed compression reactor 304 and/or on the
piston within the pulsed compression reactor 304, within high
pressure separator 308 and/or within the of the lines 320, 322,
330, 332, 334 and/or 336) having a catalytic material on the at
least one surface. This catalytic material is rendered
catalytically active for the reaction with coke and/or coke
precursors at temperatures greater than 150.degree. C., greater
than 200.degree. C. and/or greater than 250.degree. C.
[0095] Beneficially, the catalytic material may be utilized in
process conditions that reduce coking within the system, extend
hydrocarbon processing operations and increase feed flexibility, as
noted above with the other systems. As an example, the preheater
302, pulsed compression reactor 304 and lines 320, 330 and 332 may
have a catalytic material on at least one surface within the
interior of these structural members in contact with the
hydrocarbon stream. By including the catalytic material, the
preheater 302 and pulsed compression reactor 304 may be operated at
process conditions that produce more coke (e.g., visbreaking
conditions prior to the cracking in the reaction zone). This may
operate similar to the steam cracking conditions, which include
process conditions to initiate incipient thermal cracking.
Specifically, it may involve temperatures greater than or equal to
371.degree. C., greater than or equal to 399.degree. C., greater
than or equal to 415.degree. C. and at sufficient partial pressure
in the preheater 302 to maximize conversion of resid to lower
boiling fractions, such as resid fractions having boiling points of
up to and in excess of 593.degree. C. (593.degree. C..sup.+)
fractions, and even a portion of the resid fractions up to
760.degree. C.
[0096] Further, as noted above, the environment for this process
may include an oxidizing or reducing environment. That is, upstream
of the reaction zone, the different fluids added to the hydrocarbon
stream to control the environment and promote the conversion of
coke and coke precursors via kinetic pathways for removal of the
coke and/or coke precursors. Accordingly, with the catalytic
material, various stages may operate at higher temperatures with
reduced coking as opposed to conventional practices, while
providing more of the hydrocarbon feed to the reaction zone and
still maintaining or reducing the coking of the upstream equipment
surfaces. For instance, the hydrocarbon stream may be heated to
temperatures between about between 360.degree. C. and 650.degree.
C. in the preheater 302 and in the pulsed compression reactor 304.
At the preheater 302, a hydrogen (H.sub.2) containing stream may be
added to the hydrocarbon stream in an amount of greater than 0.1
mole % or greater than 1 mole %, but less that 5 mole % or less
than 4 mole % to provide a reducing environment. Alternatively,
steam may be added to the hydrocarbon stream to provide an
oxidizing environment, as noted above. The mixture from the
preheater 302 may be provided to the pulsed compression reactor 304
to convert the hydrocarbons at temperatures between 650.degree. C.
and 1000.degree. C. Further, the temperature of the wash drum 306
and high pressure separator 308 may be between 100.degree. C. and
1000.degree. C.
[0097] Further, in addition to the catalytic material upstream of
the reaction zone, the catalytic material may be utilized within
the reaction zone or downstream of the reaction zone, as noted
above for the other systems.
[0098] Other embodiments may include other different application of
the catalytic material. Likewise, the present techniques may be
utilized within a thermal coking system, wherein conversion of a
hydrocarbon stream to produce coke, hydrocarbon gases, and light
hydrocarbon liquids are conducted. Such systems generally include a
thermal coking unit along with pretreatment and recovery units,
which may include heat exchangers, preheat furnaces and separator
vessels. Regardless, of the specific configuration, the catalytic
materials may be disposed on or incorporated into the surfaces
upstream and downstream of the thermal coking unit, such as various
tubes (e.g., conduits and piping) for carrying vaporized
hydrocarbons to and from the thermal coking unit and the other
units, as noted above.
[0099] Further still, the present techniques may be utilized for
catalytic olefin generation system, wherein conversion of a
hydrocarbon stream to produce coke, hydrocarbon gases, and light
hydrocarbon liquids are conducted. Such systems generally include a
fluid catalytic cracking reactor along with pretreatment and
recovery units, which may include heat exchangers, preheat furnaces
and separator vessels. Regardless, of the specific configuration,
the catalytic materials may be disposed on or incorporated into the
surfaces upstream and downstream of the fluid catalytic cracking
reactor, such as various conduits and piping for carrying vaporized
hydrocarbons to and from the fluid catalytic cracking reactor and
the other units, as noted above.
[0100] Moreover, the process of the present techniques may be
utilized in catalytic hydrodearomatization processes of naphtha
boiling range materials to product aromatic rich streams for motor
gasoline and/or chemical feedstocks, wherein the at least one
surface in contact with the hydrocarbon feed are inner surfaces of
process tubes for feed preheating and/or inter-catalyst stage
reheating, wherein lighter hydrocarbons are vaporized and can
deposit as coke. Again, these processes and apparatuses for
conducting them are well-known in the art.
[0101] In yet another embodiment, the process of the present
techniques is conducted within a hydroconversion process of a
hydrocarbon feed to reduce sulfur compounds, nitrogen compounds,
aromatic compounds, and/or boiling point distribution, and the at
least one surface in contact with the hydrocarbon feed are inner
surfaces of process tubes for feed preheating, again where lighter
hydrocarbons are vaporized and non-volatile components may deposit
as coke.
[0102] One or more embodiments may involve the following
paragraphs:
1. A method of converting hydrocarbons into C.sub.2+ unsaturates
comprising: providing at least one structural member upstream of a
reaction zone at least a portion of an inner surface of such member
comprising a catalytic material (which may be rendered
catalytically active at process conditions) that promotes the
reaction of coke and/or coke precursors with hydrogen (H.sub.2)
and/or an oxidant to form vapor products; exposing a hydrocarbon
stream that contains coke and/or coke precursors to the catalytic
material in the presence of hydrogen and/or an oxidant and reacting
at least a portion of the coke and/or coke precursors to form vapor
products; and converting at least a portion of the hydrocarbon
stream containing the hydrocarbons and the vapor products in the
reaction zone to produce a reactor product having C.sub.2+
unsaturates. 2. The method of paragraph 1, wherein the reaction
zone is a radiant section of a steam cracking furnace downstream of
a convection section and/or wherein the converting is thermally
cracking performed in a steam cracking furnace having the
convection section and the radiant section. 3. The method of
paragraph 2, wherein the at least one structural member comprises a
process tube in the convection section of the steam cracking
furnace. 4. The method of any one of paragraphs 2 to 3, wherein the
at least one structural member further comprises a separator vessel
integrated with the convection section of the steam cracking
furnace. 5. The method of any one of paragraphs 2 to 4, wherein the
at least one structural member comprises a process tube coupled
between a separator vessel and the radiant section of the steam
cracking furnace. 6. The method of any one of paragraphs 2 to 5,
wherein the separator vessel is a single unit configured to receive
the hydrocarbon stream and separate the stream into a vapor portion
provided to an overhead line and a bottoms portion provided via a
bottoms line. 7. The method of any one of paragraphs 2 to 6,
wherein the at least one structural member further comprises one of
a chamber of a pulsed compression reactor, a piston of the pulsed
compression reactor, a process tube coupled between the pulsed
compression reactor and the radiant section of the steam cracking
furnace and any combination thereof, wherein the pulsed compression
reactor is upstream of the radiant section of the steam cracking
furnace. 8. The method of any one of paragraphs 1 to 7, further
comprising exposing at least a portion of the reactor product that
contains coke and/or coke precursors to at least one structural
member downstream of the reaction zone, wherein at least a portion
of the surface of such structural member comprises a downstream
catalytic material thereon that promotes the reaction of the coke
and/or coke precursors with hydrogen and/or an oxidant to form
vapor products. 9. The method of paragraph 8, wherein the at least
one structural member downstream of the reaction zone is one of a
process tube downstream of a radiant section of the steam cracking
furnace, a process tube in transfer line exchanger and any
combination thereof. 10. The method of any one of paragraphs 1 to 9
comprising exposing at least a portion of the reactor product to at
least one structural member in the reaction zone and having at
least one surface of a reaction zone catalytic material, wherein
the reactor product comprises coke and/or coke precursors that
react in the presence of the reaction zone catalytic material to
convert at least a portion of the coke and/or coke precursors to
vapor products. 11. The method of paragraph 1, wherein the reaction
zone is a portion of a regenerative reverse flow reactor. 12. The
method of paragraph 11, wherein the at least one structural member
comprises one of a feed injection component upstream of the
regenerative reverse flow reactor, a process tube upstream of the
regenerative reverse flow reactor, and any combinations thereof.
13. The method of paragraph 11, wherein the at least one structural
member comprises a poppet valve, wherein the surface is the portion
of the poppet valve continuously exposed to an interior region of
the regenerative reverse flow reactor. 14. The method of any one of
paragraphs 11 to 13, wherein the at least one structural member
further comprises a separator vessel upstream of the regenerative
reverse flow reactor. 15. The method of any one of paragraphs 11 to
14, wherein the at least one structural member comprises a process
tube coupled between a separator vessel and the regenerative
reverse flow reactor. 16. The method of any one of paragraphs 11 to
15, wherein the at least one structural member further comprises a
heat exchanger upstream of the regenerative reverse flow reactor.
17. The method of any one of paragraphs 1 and 11 to 16, further
comprising exposing at least a portion of the reactor product that
contains coke and/or coke precursors to at least one structural
member downstream of the reaction zone, wherein at least a portion
of the surface of the structural member comprises a downstream
catalytic material that promotes the reaction of coke and/or coke
precursors with hydrogen and/or oxidant to form vapor products. 18.
The method of paragraph 17, wherein the at least one structural
member downstream of the reaction zone is one of a process tube
downstream of the reaction zone, a removal component, a portion of
the reactor bed adjacent to the removal component, a process tube
in a transfer line exchanger, and any combination thereof. 19. The
method of any one of paragraphs 17 and 18, wherein the at least one
structural member downstream of the reaction zone comprises a
poppet valve, wherein the surface is the portion of the poppet
valve continuously exposed to the interior region of the
regenerative reverse flow reactor. 20. The method of any one of the
paragraphs 11 to 19, wherein the converting step comprises
thermally cracking the hydrocarbon stream by exposure to
temperatures in the range of 1200.degree. C. to 2200.degree. C. in
the reaction zone. 21. The method of any one of paragraphs 1 to 20,
wherein a hydrocarbon stream contains greater than or equal to 1 wt
% non-volatile non-combustibles. 22. The method of any one of
paragraphs 1 to 21, wherein hydrogen (H.sub.2) is added to the
hydrocarbon stream upstream of the catalytic material in an amount
of greater than 0.1 mole percent and less than 5.0 mole percent.
23. The method of any one of paragraphs 1 to 21, wherein hydrogen
(H.sub.2) is added in a ratio of hydrogen to carbon (H.sub.2/C) in
the range of 0.1 to 5.0 in the hydrocarbon stream. 24. The method
of any one of paragraphs 1 to 23, wherein the hydrocarbon stream
comprises combustible non-volatiles below 1 wt % of the
hydrocarbons in the hydrocarbon stream that is subject to the
converting. 25. The method of any one of paragraphs 1 to 24,
wherein greater than 75% of heat for the converting is provided via
indirect heat transfer. 26. The method of any one of paragraphs 1
to 25, wherein the catalytic material comprises one or more of the
elements from Group IVB-VIIIB and Group IA-IVA and oxides,
sulfides, nitrides, carbides intermetallic and/or reduced metal
species. 27. The method of any one of paragraphs 1 to 26, wherein
the catalytic material is selected to provide a surface net coke
deposition rate of less than 0.1 g/m.sup.2/hr. 28. The method of
any one of paragraphs 1 to 21, wherein oxidant is added to the
hydrocarbon stream upstream of the catalytic material in a ratio of
oxygen to carbon (0/C) in the range of 0.01 to 0.6. 29. A pyrolysis
system comprising: a pyrolysis unit having a reaction zone, wherein
the pyrolysis unit is configured to convert hydrocarbons into
C.sub.2+ unsaturates; and at least a portion of a surface of at
least one structural member upstream of the reaction zone comprises
a catalytic material thereon (which may be rendered catalytically
active at process conditions) that promotes the reaction of coke
and/or coke precursors with hydrogen (H.sub.2) and/or an oxidant.
30. The pyrolysis system of paragraph 29, wherein the pyrolysis
unit is a steam cracking furnace having a convection section and a
radiant section. 31. The pyrolysis system of paragraph 30, wherein
the at least one structural member upstream of the reaction zone
comprises one or more of a process tube in the convection section
of the steam cracking furnace, a separator vessel integrated with
the convection section of the steam cracking furnace, a process
tube coupled between the separator vessel and the radiant section
of the steam cracking furnace, a chamber of a pulsed compression
reactor, and a piston of the pulsed compression reactor and any
combination thereof, wherein the pulsed compression reactor is
upstream of the radiant section of the steam cracking furnace. 32.
The pyrolysis system of any one of paragraphs 30 to 31, comprising
at least one structural member downstream of the reaction zone and
having at least one surface of a downstream catalytic material,
wherein the downstream catalytic material is rendered catalytically
active to promote the reaction of coke and/or coke precursors with
hydrogen (H.sub.2) and/or an oxidant. 33. The pyrolysis system of
paragraph 32, wherein the at least one structural member downstream
of the reaction zone is one or more of a process tube downstream of
a radiant section of the steam cracking furnace, and a process tube
in transfer line exchangers. 34. The pyrolysis system of any one of
paragraphs 30 to 33, wherein the reaction zone comprises a radiant
section tube having at least one surface of a reaction zone
catalytic material, wherein the reaction zone catalytic material is
rendered catalytically active to promote the reaction of coke
and/or coke precursors with hydrogen (H.sub.2) and/or an oxidant.
35. The pyrolysis system of paragraph 29, wherein the pyrolysis
unit is a regenerative reactor or a regenerative reverse flow
reactor. 36. The pyrolysis system of paragraph 35, wherein the at
least one structural member upstream of the reaction zone and
comprises one or more of a feed injection component upstream of the
regenerative reverse flow reactor, a process tube upstream of the
regenerative reverse flow reactor, a poppet valve, wherein the
surface is the portion of the poppet valve continuously exposed to
the interior region of the regenerative reverse flow reactor, a
separator vessel upstream of the regenerative reverse flow reactor,
a process tube coupled between the separator vessel and the
regenerative reverse flow reactor, and a heat exchanger upstream of
the regenerative reverse flow reactor. 37. The pyrolysis system of
any one of paragraphs 29, 35 and 36 comprising at least one
structural member downstream of the reaction zone, wherein the at
least one structural member has a downstream catalytic material
that reacts coke and/or coke precursors in the presence of the
downstream catalytic material to convert at least a portion of the
coke and/or coke precursors to vapor products. 38. The pyrolysis
system of paragraph 37, wherein the at least one structural member
downstream of the reaction zone is one or more of a process tube, a
removal component, a portion of the reactor bed adjacent the
removal component, a process tube in a transfer line exchanger, and
a poppet valve, wherein the surface is the portion of the poppet
valve continuously exposed to the interior region of the
regenerative reverse flow reactor. 39. The pyrolysis system of any
one of paragraphs 29 to 38, wherein greater than 75% of the heat
for the converting is provided via indirect heat transfer. 40. The
pyrolysis system of any one of paragraphs 29 to 39, wherein the
catalytic material comprises one or more elements from Group
IVB-VIIIB and Group IA-IVA and oxides, sulfides, nitrides, carbides
intermetallic and/or reduced metal species thereof. 41. The
pyrolysis system of any one of paragraphs 29 to 40, wherein the
catalytic material is selected to provide a surface net coke
deposition rate of less than 0.1 g/m.sup.2/hr. 42. A method of
converting hydrocarbons into C.sub.2+ unsaturates comprising:
converting the hydrocarbon stream in a reaction zone of a
regenerative reverse flow reactor to produce a reactor product
comprising C.sub.2+ unsaturates and hydrogen (H.sub.2); exposing at
least a portion of the reactor product to at least one structural
member having at least a portion of the surface of the at least one
structural member having the catalytic material thereon (which may
be rendered catalytically active at process conditions), wherein
the catalytic material promotes the reaction of coke and/or coke
precursors with hydrogen (H.sub.2) and/or an oxidant at
temperatures greater than 150.degree. C.; and reacting in the
presence of the catalytic material at least a portion of the coke
and/or coke precursors with the hydrogen (H.sub.2) and/or oxidant
to convert the coke and/or coke precursors to vapor products. 43.
The method of paragraph 42, wherein the at least one structural
member is one of a process tube downstream of the reaction zone, a
removal component, a portion of the reactor bed adjacent the
removal component, a process tube in a transfer line exchanger, and
any combination thereof. 44. The method of any one of paragraphs 42
and 43, wherein the at least one structural member comprises a
poppet valve, wherein the surface is the portion of the poppet
valve continuously exposed to the interior region of the
regenerative reverse flow reactor. 45. The method of any one of the
paragraphs 42 to 44, wherein the converting comprises exposing the
hydrocarbon stream to temperatures in the range of 1200.degree. C.
to 2200.degree. C. 46. The method of any one of paragraphs 42 to
45, wherein hydrogen (H.sub.2) is added to the reactor product
upstream of the catalytic material in an amount of greater than 0.1
mole percent and less than 5.0 mole percent. 47. The method of any
one of paragraphs 42 to 46, wherein hydrogen (H.sub.2) is added in
a ratio of hydrogen to carbon (H.sub.2/C) in the range of 0.1 to
5.0 in the hydrocarbon stream. 48. The method of any one of
paragraphs 42 to 47, wherein greater than 75% of the heat for the
converting is provided via indirect heat transfer. 49. The method
of any one of paragraphs 42 to 48, wherein the catalytic material
comprises one or more elements from Group IVB-VIIIB and Group
IA-IVA and oxides, sulfides, nitrides, carbides intermetallic
and/or reduced metal species thereof. 50. The method of any one of
paragraphs 42 to 49, wherein the catalytic material is selected to
provide a surface net coke deposition rate of less than 0.1
g/m.sup.2/hr. 51. The method of any one of paragraphs 42 to 50,
wherein oxidant is added to the reactor product upstream of the
catalytic material in a ratio of oxygen to carbon (0/C) in the
range of 0.01 to 0.6. 52. A pyrolysis system comprising: a
regenerative reverse flow reactor having a reaction zone, wherein
the regenerative reverse flow reactor is configured to convert
hydrocarbons into C
.sub.2+ unsaturates; and at least one structural member downstream
of the reaction zone having at least one surface of a catalytic
material, wherein the catalytic material promotes the reaction of
coke and/or coke precursors with hydrogen (H.sub.2) and/or an
oxidant to form vapor products. 53. The pyrolysis system of
paragraph 52, wherein the at least one structural member is one or
more of a process tube downstream of the reaction zone, a removal
component, a portion of the reactor bed adjacent the removal
component, a process tube in a transfer line exchanger, a poppet
valve, wherein the surface is the portion of the poppet valve
continuously exposed to the interior region of the regenerative
reverse flow reactor. 54. The pyrolysis system of any one of
paragraphs 52 to 53, wherein the catalytic material comprises one
or more elements from Group IVB-VIIIB and Group IA-IVA and oxides,
sulfides, nitrides, carbides intermetallic and/or reduced metal
species thereof. 55. The pyrolysis system of any one of paragraphs
52 to 54, wherein the catalytic material is selected to provide a
surface net coke deposition rate of less than 0.1 g/m.sup.2/hr.
[0103] One or more other embodiments may involve the following
paragraphs: 1A. A method of converting hydrocarbons into C.sub.2+
unsaturates comprising: converting a first hydrocarbon stream into
a reactor product comprising C.sub.2+ unsaturates and coke in a
reaction zone of a regenerative reverse flow reactor having a
reactor bed and at least one structural member adjacent to an end
of the reactor bed, wherein the at least one structural member
comprises one or more of a removal component and a injection
component;
removing a first portion of the reactor product comprising C.sub.2+
unsaturates and a portion of the coke from the reaction zone;
exposing an oxidant stream to the at least one structural member
having at least a portion of a surface with a catalytic material
thereon that promotes the reaction of coke with the oxidant stream;
reacting the oxidant stream with the second portion of the reactor
products comprising coke in the presence of the catalytic material
to convert at least a portion of the coke to vapor products;
exothermically reacting the remaining oxidant stream with a fuel
stream in the reaction zone to produce a combustion product; and
removing the combustion product prior to the providing a second
hydrocarbon stream to the reaction zone. 2A. The method of
paragraph 1A, wherein the at least one structural member comprises
a poppet valve, wherein the surface is the portion of the poppet
valve continuously exposed to an interior region of the
regenerative reverse flow reactor. 3A. The method of any one of
paragraphs 1A to 2A, further comprising disposing a catalytic
material on at least a portion of a surface of the reactor bed
adjacent the at least one structural member, wherein the catalytic
material promotes the reaction of coke with the oxidant stream at
temperatures less than 600.degree. C. 4A. The method of any one of
the paragraphs 1A to 3A, wherein the converting comprises exposing
the hydrocarbon stream to temperatures in the range of 1400.degree.
C. to 2200.degree. C. 5A. The method of any one of paragraphs 1A to
4A, wherein the first hydrocarbon stream comprises combustible
non-volatiles below 1 wt % of the hydrocarbons in the first
hydrocarbon stream that are subject to the converting. 6A. The
method of any one of paragraphs 1A to 5A, wherein greater than 75%
of heat for the converting is provided via indirect heat transfer.
7A. The method of any one of paragraphs 1A to 6A, wherein the
catalytic material comprises one or more of the elements from Group
IVB-VIIIB and Group IA-IVA and oxides, sulfides, nitrides, carbides
intermetallic and/or reduced metal species. 8A. The method of any
one of paragraphs 1A to 7A, wherein the catalytic material is
selected to provide a surface net coke deposition rate of less than
0.1 g/m.sup.2/hr. 9A. A method of converting hydrocarbons into
C.sub.2+ unsaturates comprising: converting a first hydrocarbon
stream into a reactor product comprising C.sub.2+ unsaturates and
coke in a reaction zone of a regenerative reverse flow reactor
having a reactor bed and at least one structural member adjacent to
an end of the reactor bed, wherein the at least one structural
member comprises one or more of a removal component and an
injection component; removing a first portion of the reactor
product comprising C.sub.2+ unsaturates and a portion of the coke
from the reaction zone; exothermically reacting an oxidant stream
with a fuel stream in the reaction zone to produce a combustion
product; exposing the combustion product to the at least one
structural member having at least a portion of a surface with a
catalytic material, wherein the catalytic material promotes the
reaction of coke with the combustion product; reacting the
combustion product with the second portion of the reactor products
comprising coke in the presence of the catalytic material to
convert at least a portion of the coke to vapor product; and
removing the combustion product and at least a portion of the vapor
product prior to the providing a second hydrocarbon stream to the
reaction zone. 10A. The method of paragraph 9A, wherein the at
least one structural member comprises one of a feed injection
component downstream of the reaction zone for the combustion
product. 11A. The method of paragraph 9A, wherein the at least one
structural member comprises a poppet valve, wherein the surface is
the portion of the poppet valve continuously exposed to an interior
region of the regenerative reverse flow reactor. 12A. The method of
any one of paragraphs 9A to 11A, wherein the at least one
structural member comprises a portion of the reactor bed adjacent
to a combustion removal component downstream of the reaction zone
for the combustion products. 13A. The method of any one of
paragraphs 9A to 12A, wherein the at least one structural member
comprises a process tube coupled between combustion removal
components and a heat exchanger downstream of the regenerative
reverse flow reactor for the combustion products. 14A. The method
of any one of paragraphs 9A to 13A, wherein the at least one
structural member comprises a heat exchanger downstream of the
regenerative reverse flow reactor for the combustion products. 15A.
The method of any one of the paragraphs 9A to 14A, wherein the
converting comprises exposing the hydrocarbon stream to
temperatures in the range of 1200.degree. C. to 2200.degree. C.
16A. The method of any one of paragraphs 9A to 15A, wherein the
first hydrocarbon stream comprises combustible non-volatiles below
1 wt % of the hydrocarbons in the hydrocarbon stream that are
subject to the converting. 17A. The method of any one of paragraphs
9A to 16A, wherein greater than 75% of heat for the converting is
provided via indirect heat transfer. 18A. The method of any one of
paragraphs 9A to 17A, wherein the catalytic material comprises one
or more of the elements from Group IVB-VIIIB and Group IA-IVA and
oxides, sulfides, nitrides, carbides intermetallic and/or reduced
metal species. 19A. The method of any one of paragraphs 9A to 18A,
wherein the catalytic material is selected to provide a surface net
coke deposition rate is less than 0.1 g/m.sup.2/hr. 20A. A
pyrolysis system comprising: a regenerative reverse flow reactor
having a reaction zone, wherein the regenerative reverse flow
reactor is configured to convert hydrocarbons into C.sub.2+
unsaturates; and at least a portion of a surface of at least one
structural member having a catalytic material, wherein the
catalytic material promotes the reaction of coke and/or coke
precursors with an oxidant. 21A. The pyrolysis system of paragraph
20A, wherein the at least one structural member is one or more of a
process tube downstream of the reaction zone, a combustion removal
component downstream of the reaction zone, a portion of the reactor
bed adjacent the combustion removal component, a process tube in a
transfer line exchanger downstream of the reaction zone, and a
poppet valve, wherein the surface of the poppet valve is the
portion of the poppet valve that is continuously exposed to the
interior region of the regenerative reverse flow reactor. 22A. The
pyrolysis system of paragraph 20A, wherein the at least one
structural member is one or more of a product removal component
upstream of the reaction zone, a portion of the reactor bed
adjacent the product removal component, and a poppet valve, wherein
the surface of the poppet valve is the portion of the poppet valve
that is continuously exposed to the interior region of the
regenerative reverse flow reactor. 23A. The pyrolysis system of any
one of paragraphs 20A to 22A, wherein the catalytic material
comprises one or more of the elements from Group IVB-VIIIB and
Group IA-IVA and oxides, sulfides, nitrides, carbides intermetallic
and/or reduced metal species. 24A. The pyrolysis system of any one
of paragraphs 20A to 23A, wherein the catalytic material is
selected to provide a surface net coke deposition rate is less than
0.1 g/m.sup.2/hr.
[0104] While the present invention has been described and
illustrated with respect to certain embodiments, it is to be
understood that the invention is not limited to the particulars
disclosed and extends to all equivalents within the scope of the
claims.
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