Title: Gas-to-liquid CO2 reduction by use of H2 as a fuel
Abstract: CO2 emissions Gas-to-Liquids (GTL) facilities such as, for example, Fischer-Tropsch facilities, are minimized by using recovered hydrogen as a fuel in at least one furnace in the GTL facility. A process for manufacturing hydrocarbonaceous products from a methane-containing feedstock in a GTL facility comprising at least one furnace generating reduced CO2 emissions comprises forming syngas from a methane-containing feedstock by means of a partial oxidation reaction. A hydrogen rich fuel is used in at least one furnace in the GTL facility to reduce CO2 emissions generated by the facility.
Patent Number: 6,890,962 Issued on 05/10/2005 to O'Rear, et al.
| Inventors:
|
O'Rear; Dennis J. (Petaluma, CA);
Brancaccio; Nicholas (Walnut Creek, CA)
|
| Assignee:
|
Chevron U.S.A. Inc. (San Ramon, CA)
|
| Appl. No.:
|
720674 |
| Filed:
|
November 25, 2003 |
| Current U.S. Class: |
518/700; 208/133; 208/141; 518/702; 518/703 |
| Intern'l Class: |
C07C 027/00; C10G035/00 |
| Field of Search: |
518/700,702,703
208/133,141
|
References Cited [Referenced By]
U.S. Patent Documents
| 4542122 | Sep., 1985 | Payne et al.
| |
| 4568663 | Feb., 1986 | Mauldin.
| |
| 4621072 | Nov., 1986 | Arntz et al.
| |
| 4663305 | May., 1987 | Mauldin et al.
| |
| 5423894 | Jun., 1995 | Child et al.
| |
| 5545674 | Aug., 1996 | Behrmann et al.
| |
| 5689031 | Nov., 1997 | Berlowitz et al.
| |
| 6043288 | Mar., 2000 | DeGeorge et al.
| |
| 6103773 | Aug., 2000 | Wittenbrink.
| |
| 6147126 | Nov., 2000 | DeGeorge et al.
| |
| 6693138 | Feb., 2004 | O'Rear.
| |
| 6703429 | Mar., 2004 | O'Rear.
| |
| Foreign Patent Documents |
| 0 635 555 | Jan., 1995 | EP.
| |
| 0 921 184 | Jun., 1999 | EP.
| |
| 0069989 | Nov., 2000 | WO.
| |
| 0069990 | Nov., 2000 | WO.
| |
Other References
U.S. patent application No. 10/720,673, O'Rear et al., Control of CO2 Emissions
from a Fischer-Tropsch Facility by Use of Dual Functional syngas Conversion,
filed on Nov. 25, 2003.
U.S. patent application No. 10/720,675, O'Rear, et al., Control of CO2 Emissions
from a Fischer-Tropsch Facility by Use of Multiple Reactors, filed on Nov.
25, 2003.
U.S. patent application No. 10/118,029, O'Rear, Reducing CO2
Levels in CO2 -Rich Natural Gases Converted into Liquid Fuels,
filed Apr. 9, 2002.
"Alchemy in Alaska", Frontiers pp 14-20 (2002).
|
Primary Examiner: Parsa; J.
Attorney, Agent or Firm: Burns, Doane, Swecker & Mathis, L.L.P.
Claims
1. A process for manufacturing hydrocarbonaceous products from a methane-containing
feedstock in a GTL facility comprising at least one furnace generating reduced
CO
2 emissions, the process comprising:
a) forming syngas from a methane-containing feedstock by means of a partial oxidation
reaction using a gaseous oxidant comprising molecular oxygen;
b) converting the syngas into C
3+ liquid products and recovering an
unreacted gas;
c) separating the C
3+ liquid products to obtain a naphtha;
d) reforming the naphtha to produce a by-product hydrogen-containing gas stream;
e) recovering a hydrogen rich gas stream from at least one of the syngas and
the by-product hydrogen-containing gas stream or combinations thereof; and
f) using a hydrogen rich fuel comprising the hydrogen rich gas stream and the
unreacted gas in at least one furnace in the GTL facility to reduce CO
2
emissions generated by the facility.
2. The process of claim 1, wherein the GTL facility is a Fischer-Tropsch facility.
3. The process of claim 1, wherein the syngas comprises about 5 mole percent
or less nitrogen.
4. The process of claim 1, wherein the CO
2 emissions from the GTL
facility are at least about 15% less than if recovered hydrogen were not used as
a fuel in the GTL facility.
5. The process of claim 4, wherein the CO
2 emissions from the GTL
facility are at least about 30% less than if recovered hydrogen were not used as
a fuel in the GTL facility.
6. The process of claim 5, wherein the CO
2 emissions from the GTL
facility are at least about 50% less than if recovered hydrogen were not used as
a fuel in the GTL facility.
7. The process of claim 1, wherein a hydrocarbonaceous product having a hydrogen
to carbon stoichiometric ratio below about 2.0 is isolated.
8. The process of claim 7, wherein the hydrogen to carbon stoichiometric ratio
is below about 1.90.
9. The process of claim 1, wherein the at least one furnace using the hydrogen
rich fuel is altered in a manner by providing the furnace with an enlarged gas
supply line, providing the furnace with enlarged burner nozzles, increasing convection
zone heating of the furnace or combinations thereof.
10. The process of claim 1, wherein the hydrogen rich fuel comprises at least
about 40% hydrogen, on a molar basis.
11. The process of claim 10, wherein the hydrogen rich fuel comprises at least
about 60% hydrogen, on a molar basis.
12. A process for manufacturing hydrocarbonaceous products from a methane-containing
feedstock in a GTL facility comprising at least one furnace generating reduced
CO
2 emissions, the process comprising:
a) forming syngas from a methane-containing feedstock by means of a partial oxidation
reaction using a gaseous oxidant comprising molecular oxygen;
b) converting the syngas into C
3+ liquid products and recovering an
unreacted gas;
c) separating the C
3+ liquid products to obtain a naphtha;
d) reforming the naphtha to produce a by-product hydrogen-containing gas stream;
e) recovering a hydrogen rich gas stream from at least one of the syngas and
the by-product hydrogen-containing gas stream or combinations thereof; and
f) using a hydrogen rich fuel comprising the hydrogen rich gas stream and the
unreacted gas in at least one furnace in the GTL facility so that a mole percent
of CO
2 in a flue gas generated from the furnace, on a water-free basis,
is represented by the following formula:
wherein E-O
2 represents mole percent excess oxygen, on a water-free basis.
13. The process of claim 12, wherein the mole percent of CO
2 in the
flue gas from the furnace, on a water-free basis, is represented by the following formula:
14. The process of claim 12, wherein the GTL facility is a Fischer-Tropsch facility.
15. The process of claim 12, wherein the syngas comprises about 5 mole percent
or less nitrogen.
16. The process of claim 12, wherein a hydrocarbonaceous product having a hydrogen
to carbon stoichiometric ratio below about 2.0 is isolated.
17. The process of claim 16, wherein the hydrogen to carbon stoichiometric ratio
is below about 1.90.
18. The process of claim 12, wherein the at least one furnace using the hydrogen
rich fuel is altered in a manner by providing the furnace with an enlarged gas
supply line, providing the furnace with enlarged burner nozzles, increasing convection
zone heating of the furnace or combinations thereof.
19. The process of claim 12, wherein the hydrogen rich fuel comprises at least
about 40% hydrogen, on a molar basis.
20. The process of claim 19, wherein the hydrogen rich fuel comprises at least
about 60% hydrogen, on a molar basis.
Description
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention is directed to minimizing CO
2 emissions from
Gas-to-Liquids (GTL) facilities. In particular, the present invention is directed
to reducing CO
2 emissions from GTL facilities such as, for example,
Fischer-Tropsch facilities, by using hydrogen as a fuel used in the GTL facilities.
2. Description of the Related Art
The conversion of natural gas assets into more valuable chemicals, including
combustible liquid fuels, is desired to more effectively utilize these natural
gas assets. The conversion of natural gas to more valuable chemical products generally
involves syngas generation. Syngas generation involves converting natural gas,
which is mostly methane, to synthesis gas or syngas, which is a mixture of carbon
monoxide and hydrogen. Syngas can be used as a feedstock for producing a wide range
of chemicals, including combustible liquid fuels, methanol, acetic acid, dimethyl
ether, oxo alcohols, and isocyanates.
There are two main approaches to convert remote natural gas assets into conventional
transportation fuels and lubricants using syngas. Natural gas may be converted
into syngas followed by a Fischer-Tropsch process, or natural gas may be converted
into syngas followed by methanol synthesis, which is followed by a methanol to
gas process (MTG) to convert methanol into highly aromatic gasoline. The syngas
generation is the most costly step of these processes. A critical feature of these
processes is producing syngas with a desired H
2/CO ratio to optimize
formation of the desired products and to avoid problems in the syngas formation step.
Syngas can be generated from three major chemical reactions. The first involves
steam reforming of methane. The ratio of hydrogen to carbon monoxide, which is
formed from this process, is typically approximately 3.0. A second process for
syngas generation involves dry reforming of methane or the reaction between carbon
dioxide and methane. An attractive feature of this method is that carbon dioxide
is converted into syngas; however, this method has problems with rapid carbon deposition.
The carbon deposition or coke forming reaction is a separate reaction from the
one that generates the syngas and occurs subsequent to the syngas formation reactor.
However, the reaction of methane in dry reforming is slow enough that long residence
times are required for high conversion rates and these long residence times lead
to coke formation. The ratio of hydrogen to carbon monoxide, which is formed from
this process, is typically approximately 1.0. A third process for syngas generation
involves partial oxidation of methane using oxygen. The ratio of hydrogen to carbon
monoxide, which is formed from this process, is typically approximately 2.0. However,
in commercial practice, some amount of steam is typically added to a partial oxidation
reformer in order to control carbon formation and the addition of steam tends to
increase the H
2/CO ratio above 2.0.
It is possible to produce syngas with a H
2/CO ratio that is above
the
ratio ideally desired for the process in which the syngas is to be used, and then
to remove excess hydrogen to adjust the ratio to the desired value. However, the
H
2 removal process employs expensive H
2 separation systems
that tend to foul and decline in performance with use.
The Fischer-Tropsch and MTG processes both have advantages and disadvantages.
For instance, the Fischer-Tropsch process has the advantage of forming products
that are highly paraffinic. Highly paraffinic products are desirable because they
exhibit excellent combustion and lubricating properties. Unfortunately, a disadvantage
of the Fischer-Tropsch process is that the Fischer-Tropsch process emits relatively
large amounts of CO
2 during the conversion of natural gas assets into
saleable products. An advantage of the MTG process is that the MTG process produces
highly aromatic gasoline and LPG fractions (e.g., propane and butane). However,
while highly aromatic gasoline produced by the MTG process is generally suitable
for use in conventional gasoline engines, highly aromatic MTG gasoline may be prone
to form durene and other polymethyl aromatics having low crystallization temperatures
that form solids upon standing. In addition, the MTG process is more expensive
than the Fischer-Tropsch process and the products produced by the MTG process cannot
be used for lubricants, diesel engine fuels or jet turbine fuels. Furthermore,
like the Fischer-Tropsch process, the MTG process also generates CO
2.
Hydrogen recovered during petrochemical processing has been used for various
purposes. For example, U.S. Pat. Nos. 6,043,288 and 6,103,773, and 6,147,126 to
Exxon describe recovering hydrogen from syngas for uses including hydrotreating
and catalyst regeneration, while CO rich offgas is used for fuel.
In another example, BP has disclosed using a steam reformer followed by a membrane
separator to recover excess hydrogen which is used as a fuel gas in the steam reformer.
("Alchemy in Alaska," Frontiers, December 2002, pages 14-20).
In addition, WO 00/69990 and WO 00/69989 describe producing hydrogen from light
products produced from hydrocracking for use in various operations, including hydrocracking.
The feedstock used in the disclosed processes can be a Fischer-Tropsch feedstock.
However, the methods of hydrogen production described in WO '990 beginning at page
9, line 30 and in WO '989 at page 12, lines 11-17 include partial oxidation, steam-methane
reformation and catalytic dehydrogenation.
Finally, EP 635555A describes using naphtha reformation to produce hydrogen
used for upstream hydrotreating. EP '555 refers to the refining of petroleum products.
There remains a need for efficient processes to convert a methane-containing
feedstock into hydrocarbonaceous products in a GTL facility and to minimize CO
2
emissions generated by such GTL processes.
SUMMARY OF THE INVENTION
The present invention satisfies the above objectives by providing a process that
minimizes the CO
2 generated by a GTL facility by using hydrogen produced
during upgrading processes as a fuel in the GTL facility.
The process, according to the present invention, for manufacturing hydrocarbonaceous
products from a methane-containing feedstock in a GTL facility comprising at least
one furnace generating reduced CO
2 emissions includes forming syngas
from a methane-containing feedstock by means of a partial oxidation reaction using
a gaseous oxidant comprising molecular oxygen and converting the syngas into C
3+
liquid products and recovering an unreacted gas. The process further includes separating
the C
3+ liquid products to obtain a naphtha. The process also includes
reforming the naphtha to produce a by-product hydrogen-containing gas stream and
recovering a hydrogen rich gas stream from at least one of the syngas and the by-product
hydrogen-containing gas stream or combinations thereof. Finally, the process includes
using a hydrogen rich fuel comprising the hydrogen rich gas stream and the unreacted
gas in at least one furnace in the GTL facility to reduce CO
2 emissions
generated by the facility.
According to another aspect of the present invention, the process for manufacturing
hydrocarbonaceous products from a methane-containing feedstock in a GTL facility
comprising at least one furnace generating reduced CO
2 emissions includes
forming syngas from a methane-containing feedstock by means of a partial oxidation
reaction using a gaseous oxidant comprising molecular oxygen and converting the
syngas into C
3+ liquid products and recovering an unreacted gas. The
process also includes separating the C
3+ liquid products to obtain a
naphtha. The process also includes reforming the naphtha to produce a by-product
hydrogen-containing gas stream and recovering a hydrogen rich gas stream from at
least one of the syngas and the by-product hydrogen-containing gas stream or combinations
thereof. Finally, the process includes using a hydrogen rich fuel comprising the
hydrogen rich gas stream and the unreacted gas in at least one furnace in the GTL
facility so that a mole percent of CO
2 in a flue gas generated from
the furnace, on a water-free basis, is represented by the following formula: P-CO
2≦22/(1-4.76(E-CO
2/100)),
wherein E-CO
2 represents mole percent excess oxygen, on a water-free basis.
Tail gas, having a high CO
2 content and low BTU content, is the normal
fuel used in GTL facilities, resulting in high CO
2 emissions. Thus,
the present invention minimizes CO
2 emissions from GTL processes by
recovering hydrogen and using the recovered hydrogen in fuel gas in the GTL facility.
By increasing the hydrogen content of the fuel gas, the present invention can reduce
the CO
2 content of a flue gas generated by a GTL facility. Accordingly,
one important advantage of the present invention is that it can reduce or substantially
minimize CO
2 emissions generated by Fischer-Tropsch GTL processes or
furnaces without having to employ expensive CO
2 isolation techniques
including, but not limited to, gaseous CO
2 compression, liquefaction
or solidification.
BRIEF DESCRIPTION OF THE FIGURES OF THE DRAWING
FIG. 1 is a schematic view of a conventional Fischer-Tropsch facility.
FIG. 2 is a schematic view of an exemplary embodiment of a GTL facility of the
present invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
In the present invention, hydrogen is recovered from the GTL facility and used
as a fuel in at least one furnace in a GTL facility. The hydrogen used can be recovered
from any number of sources in a GTL process including, but not limited to, syngas
streams, unreacted gas streams from a syngas conversion unit, gas streams associated
with hydrotreaters/hydrocrackers used for upgrading hydrocarbonaceous products,
gas streams associated with reformers used to make aromatic products, combinations
thereof and the like. Hydrogen recovery can be conducted using various conventional
hydrogen recovery processes including, but not limited to, adsorption, absorption
(pressure swing adsorption (PSA) and displacement purge cycles (DPC)), cryogenic
separation, membrane separation, combinations thereof and the like. While one or
more recovery processes may be needed to recover H
2 from syngas or tail
gas, by-product gas from a reformer or C
3+ product upgrader will not
contain appreciable amounts of CO or CO
2 and thus may not need any recovery
process except for condensation of heavy hydrocarbons (C
6+). Additionally,
while it is desirable to use recovered hydrogen in processes of the present invention,
it is also possible to supplement or replace recovered hydrogen with hydrogen obtained
from alternative sources.
Membrane separators are expensive to build and operate, thus routes that
do not require membrane separators have lower capital costs and are preferred.
Accordingly, a preferred embodiment of the present invention relies on syngas formation
comprising partial oxidation, as such processes do not require membrane separation
to obtain a hydrogen rich gas stream. Further, deriving hydrogen rich gas streams
from upgrading process steps such as naphtha reforming, which generates hydrogen
as a by-product, does not require the use of membrane separations to recover the
hydrogen. In these processes, rather, condensation of heavy hydrocarbons (C
6+)
alone may allow recovery of hydrogen.
Catalysts and conditions for performing Fischer-Tropsch reactions are well
known to those of skill in the art, and are described, for example, in EP 0 921
184A1, the contents of which are hereby incorporated by reference in their entirety.
A schematic of a conventional Fischer-Tropsch process is shown in FIG.
1.
In this process, a feedstream
10 comprising C
4, O
2
and H
2O enters a syngas generator
12. The syngas generator
12
generates syngas comprising CO, H
2, and CO
2. The syngas stream
14 exits the syngas generator
12 and enters a Fischer-Tropsch reactor
16. A product stream
17 exits the Fischer-Tropsch reactor
16
and enters a separator
18. The separator
18 separates the syngas
into a hydrocarbonaceous stream
21 comprising C
5+ liquids and
an unreacted gas stream
19.
The unreacted gas stream
19, exiting the separator
18, can be divided
into two additional streams. The first stream can be comprised of excess unreacted
gas comprising CO, H
2 and CO
2. This stream exits the process
in an exit stream
32, to be used as fuel. The second stream, also comprising
unreacted CO, H
2, and CO
2, can be recycled (
33) to
be mixed with the syngas stream
14, exiting the syngas generator
12,
before entering the Fischer-Tropsch hydrocarbon reactor
16 to produce a
mixed syngas stream
15.
The Fischer-Tropsch process can be understood by examining the stoichiometry
of the reaction that occurs during a Fischer-Tropsch process. For example, during
Fischer-Tropsch processing, syngas (i.e., a mixture including carbon monoxide and
hydrogen), is generated, typically from at least one of three basic reactions.
Typical Fischer-Tropsch reaction products include paraffins and olefins, generally
represented by the formula nCH
2. While this formula accurately defines
mono-olefin products, it only approximately defines C
5+ paraffin products.
The value of n (i.e., the average carbon number of the product) is determined by
reaction conditions including, but not limited to, temperature, pressure, space
rate, catalyst type and syngas composition. The desired net syngas stoichiometry
for a Fischer-Tropsch reaction is independent of the average carbon number (n)
of the product and is about 2.0, as determined by the following reaction equation:
where C
nH
2n+2 represents typical Fischer-Tropsch reaction
products such as, for example, olefins and paraffins. The amount of by-product
water produced by the reaction is significant. For instance, when converting the
molar ratios to weight ratios, one can see that the relative weight percentages
of water to CH
2 hydrocarbons is 56%/44%.
The three general reactions that produce syngas from methane are as follows:
- 1. steam reforming of methane: CH4+H2O→CO+3H2;
- 2. dry reforming, or reaction between CO2 and methane: CH4+CO2→2CO+2H2; and
- 3. partial oxidation using oxygen: CH4+½O2→CO+2H2.
Although the above general reactions are the basic reactions used to produce
syngas, the ratio of hydrogen to carbon monoxide produced by the above reactions
is not always adequate for the desired Fischer-Tropsch conversion ratio of 2.0.
For example, in the steam reforming reaction, the resulting ratio of hydrogen to
carbon monoxide is 3.0, which is higher than the desired hydrogen to carbon monoxide
ratio of 2.0 for a Fischer-Tropsch conversion. Similarly, in the dry reforming
reaction, the resulting hydrogen to carbon monoxide ratio is 1.0, which is lower
than the desired hydrogen to carbon monoxide ratio of 2.0. In addition to exhibiting
a hydrogen to carbon monoxide ratio that is lower than the desired ratio for a
Fischer-Tropsch conversion, the above dry reforming reaction also suffers from
problems associated with rapid carbon deposition. Finally, because the above partial
oxidation reaction provides a hydrogen to carbon monoxide ratio of 2.0, the partial
oxidation reaction is the preferred reaction for Fischer-Tropsch conversions.
In commercial practice, an amount of steam added to a partial oxidation reformer
can control carbon formation. Likewise, certain amounts of CO
2 can be
tolerated in the feed. Thus, even though partial oxidation is the preferred reaction
for Fischer-Tropsch conversions, all of the above reactions can occur, to some
extent, in an oxidation reformer.
During partial oxidation, CO
2 forms because the reaction is not
perfectly selective. That is, some amount of methane in the reaction will react
with oxygen to form CO
2 by complete combustion. The reaction of methane
with oxygen to form CO
2 is generally represented by the following reactions:
and
Furthermore, steam added to the reformer to control coking, or steam
produced during the Fischer-Tropsch reaction can react with CO to form CO
2
in a water gas shift reaction represented by the following general reaction:
In addition, light by-product gases, including C
1-C
4 hydrocarbons,
are frequently used as fuel in furnaces. These fuels often include CO
2 from
a GTL facility along with some unreacted CO. Moreover, during operation, a furnace
provides heat that can contribute to the generation of substantial amounts of CO
2.
Thus, invariably a significant amount of CO
2 is formed during the
conversion of methane into transportation fuels and lubricants by the Fischer-Tropsch
process. The CO
2 produced during the Fischer-Tropsch process exits the
Fischer-Tropsch/GTL process in a tail gas exiting the Fischer-Tropsch unit. Tail
gases exiting a Fischer-Tropsch/GTL process comprise any gases that remain unconsumed
by the Fischer-Tropsch process.
The overall proportion of carbon in methane that is converted to heavier hydrocarbon
products has been estimated to be as high as about 68%. Thus, the remaining 32%
can form significant amounts of CO
2. These estimates of carbon efficiency
are provided, for example, by Bechtel Corporation for a GTL complex using cryogenic
air separation, an autothermal reformer, a slurry bed Fischer Tropsch unit and
a hydrocracker for conversion of heavy wax into saleable products. See "CO
2
Abatement in GTL Plant: Fischer-Tropsch Synthesis," Report # PH3/15, November 2000,
published by IEA Greenhouse Gas R&D Programme, the contents of which are hereby
incorporated by reference in their entirety. Additionally, although the above estimates
are provided for a specific GTL complex, it is believed that similar carbon efficiencies
and CO
2 emissions would be produced by GTL processes employing alternative technologies.
The above equations represent general stoichiometric equations; they do not reflect
an optimum syngas composition for the kinetics or selectivity of a Fischer-Tropsch
reaction. Moreover, depending on the nature of the Fischer-Tropsch catalyst, syngas
ratios other than 2.0, typically less than 2.0, are used to prepare the feed to
a Fischer-Tropsch unit. However, because Fischer-Tropsch units typically produce
products exhibiting a hydrogen to carbon ratio of about 2.0, the limiting reagent,
typically H
2, is consumed first. The extra reagent, typically CO, is
then recycled back to the Fischer-Tropsch unit for further conversion. Syngas compositions
having hydrogen to carbon ratios other than 2.0 are typically generated by recycling
unused reagents. Accordingly, in the present invention, hydrogen rich gas may be
recovered from the formed syngas in order to achieve a desired syngas ratio in
the feed to the Fischer-Tropsch reactor.
In preferred embodiments, processes of the present invention reduce CO
2
emissions by at least about 15%, more preferably by at least about 30% and most
preferably by at least about 50%.
The concentration of CO
2 (P-CO
2) in a flue gas from a furnace
in a GTL facility, according to the present invention, in which hydrogen gas used
as fuel is combusted, is represented by the following formulae:
preferably
wherein E-O
2 represents the mole percent of excess oxygen in a
flue gas generated from the furnace.
In addition to reducing CO
2 emissions, this process can also increase
carbon efficiency of a GTL process. Saleable hydrocarbonaceous products generated
from the GTL process of the present invention include, but are not limited to,
transportation fuels including jet, diesel, and motor gasoline, aromatic hydrocarbons,
syncrudes, lubricant base stocks, combinations thereof and the like.
One source of hydrogen, for use in processes of the present invention, is hydrogen
generated, for example, during naphtha reformation. Hydrogen is generated during
naphtha reformation by converting at least a portion of C
5+ Fischer-Tropsch
product into aromatics. A typical reaction for a C
6 paraffin is as follows:
Processes for converting paraffin-rich streams into aromatics are well
known in the field. Commonly, such conversion processes referred to as "naphtha
reforming processes," are divided into two classes. The first class of naphtha
reforming processes are referred to as "conventional reforming processes." Conventional
reforming processes use a catalyst composed, for example, of Pt, alumina, and a
halogen, typically Cl, and further typically comprising Re or Ir. Generally, the
catalyst is exposed to sulfur prior to being used in the reaction. Those of ordinary
skill in the art commonly expose conventional reforming catalysts to sulfur prior
to use in the reaction to obtain highly selective conversion of C
8-10
paraffins into aromatics. However, it is well known that the exposure of conventional
reforming catalysts to high levels of sulfur (>10 ppm) during use generates
poor selectivity for the conversion of C
8-10 paraffins into aromatics.
In addition, conventional reforming catalysts are not very selective for the conversion
of hexane and heptane to aromatics.
The second class of naphtha reforming processes are referred to as "non-acidic
zeolitic reforming processes" such as, for example, AROMAX® reforming processes.
Non-acidic zeolitic reforming processes use a catalyst comprising Pt, a non-acidic
zeolite, typically an L-zeolite, K, optionally Ba, mixtures thereof and the like.
Generally, non-acidic zeolitic reforming catalysts are not exposed to sulfur prior
to operation. In addition, non-acidic zeolitic reforming catalysts are highly selective
for the conversion of hexane and heptane into aromatics.
The present invention can employ either or both of the above naphtha reforming
processes. Aromatic products produced by the above reforming processes can be used
in various applications including, but not limited to, high octane blend components
for gasolines, typically including a mixture of C
6-C
10 aromatics,
benzene for use in chemicals, especially for use in the production of cyclohexane,
ethylbenzene and/or cumene, toluene for use as a chemical and xylenes for use as
chemicals, especially for the production of paraxylene.
The removal of hydrogen from a Fischer-Tropsch product causes the net C
5+
product to have a lower hydrogen to carbon stoichiometric ratio. That is, even
though the initial hydrogen to carbon ratio is about 2.0, after conversion of a
portion of the product into aromatics, the hydrogen to carbon stoichiometric ratio
of the C
5+ product declines to a value less than about 2.0, preferably
less than about 1.95, and more preferably less than about 1.90. Because it is preferable
to make aromatics from a C
6-C
10 portion of the product, this
stream often contains a lower amount of hydrogen than the heavier product. Preferably,
the C
6-C
10 portion of the C
5+ hydrocarbon product
has a lower hydrogen to carbon ratio than the C
10+ product.
The hydrogen to carbon stoichiometric ratio of the products can be determined
using a number of suitable methods well-known to those of skill in the art. These
suitable methods include, for example, chemical analyses for identification of
individual species such as Carlo-Erba combustion and gas chromatography, and NMR
spectroscopy. Chemical analyses for individual species are preferred.
The product streams from the process of the present invention can constitute
a mixture such as, for example, a synthetic crude. In addition, product streams
of the present invention can be produced, shipped and/or sold as individual streams
such as LPG (C
3's and C
4's), condensate (C
5's
and C
6's), high-octane blend components (C
6-C
10
aromatic-containing streams), jet fuel, diesel fuel, other distillate fuels, lube
blend stocks or lube blend feedstocks. The desired stoichiometric ratios specified
in this invention refer to the net product analysis.
Hydrogen generated during naphtha reformation can also be used for other
processes such as, for example, hydrotreating a portion of the C
5+ product
to remove olefins, oxygenates and other trace heteroatoms.
During operation of a Fischer-Tropsch GTL facility, the fuel used in the GTL
process is commonly composed of unreacted syngas, often referred to as "tail gas."
Under typical operating parameters for a slurry bed Fischer-Tropsch process, operating
with a catalyst that does not promote a water-gas-shift reaction and with oxygen
as an oxidant, the tail gas molar composition, on a water-free basis, is:
| |
|
| |
hydrogen |
25 |
| |
carbon monoxide |
23 |
| |
carbon dioxide |
35 |
| |
methane |
14 |
| |
C2+ |
3 |
| |
Total |
100 |
| |
|
If air is used as an oxidant to form the syngas, large quantities of nitrogen
are often incorporated in the syngas and the unreacted tail gas. Thus, the present
invention relates to a syngas that is composed of very little nitrogen such as,
for example, less than about 5 mole percent, more preferably less than about 1
mole percent.
When the tail gas is burned as a fuel, flue gas is generated (see Table below).
The nitrogen (N
2) associated with combustion of each element is calculated
from the relative molar concentration of N
2 and O
2 in air,
about 79 and about 21, respectively.
| |
| Combustion Stoichiometries |
Flue Gas |
| nent |
Mole % |
O2 required |
produced |
associated |
CO2 |
N2 |
| |
| Hydrogen |
25 |
½ |
0 |
1.88 |
0 |
0.47 |
| CO |
23 |
½ |
1 |
1.88 |
0.23 |
0.43 |
| CO2 |
35 |
0 |
1 |
0 |
0.35 |
0 |
| Methane |
14 |
2 |
1 |
7.52 |
0.14 |
1.05 |
| Ethane |
3 |
7/2 |
2 |
13.17 |
0.06 |
0.40 |
| Total |
100 |
|
|
|
0.78 |
2.35 |
| Molar Percentage, water-free basis |
|
25 |
75 |
| |
The flue gas compositions of 25 mol % CO
2 and 75 mol % N
2 are
on a water free basis, as water is produced by the reaction of oxygen with hydrogen,
methane, and ethane. The hydrogen content of the fuel gas can be increased to higher
values, resulting in flue gases having a lower CO
2 concentration. The
following table shows the results of this calculation wherein other components
in the fuel gas are reduced in proportion.
| |
|
| |
|
Carbon Dioxide Content of |
| |
Fuel Gas Hydrogen Content, |
Flue Gas (mole percent, |
| |
Mole Percent |
water-free basis) |
| |
|
| |
25 |
25 |
| |
40 |
22 |
| |
60 |
16 |
| |
|
Thus, as the mole percent of hydrogen in the fuel gas increases, the mole percent
of CO
2 in the resulting flue gas decreases. While the energy content
of the fuel may change somewhat, the amount of the fuel or the burner design can
be adjusted to accommodate a new fuel, as described below. The above stoichiometries
apply to complete and ideal combustion. In a furnace, combustion is essentially
complete and thus, H
2 is present in the flue gas only in trace amounts.
Excess oxygen present in the flue gas assures complete combustion of the carbon
monoxide in the furnace, preventing the emission of harmful carbon monoxide. Typically,
furnaces are designed to operate with about 2-3 mole percent excess oxygen, but
may operate at between about 3-5 mole percent excess oxygen. Because excess oxygen
in the flue gas will dilute the carbon dioxide, corrections may be necessary.
Assuming that there are (x) moles of excess oxygen per mole flue gas, there
will also be 79/21 (x) moles of N
2 added to the flue gas in association
with this excess oxygen. Thus, when using a 25% hydrogen-containing fuel gas, the
total number of moles, on a water-free basis, in the flue gas will be:
| |
|
| |
N2 |
0.75 |
| |
CO2 |
0.25 |
| |
Excess O2 |
x |
| |
N2 with excess O2 |
3.76 x, wherein 3.76 = 79/21 |
| |
Total moles |
1 + 4.76 (x). |
| |
|
The percent excess oxygen (E-O
2) in the flue gas is a measurable quantity
that can be calculated using the following equation:
Solving for x in terms of E-O
2 results in the following equation:
Using this value for x, the total number of moles is then:
Solving for the percent CO
2 (P-CO
2) in the flue gas,
as a function of E-O
2, results in the following equation:
If sufficient hydrogen is added to the fuel gas to raise its hydrogen content
to about 40%, the flue gas composition will be:
If sufficient hydrogen is added to the fuel gas to raise its hydrogen content
to about 60%, the flue gas composition will be:
The use of hydrogen as a fuel, and the reduction of CO
2 emissions
will likely necessitate a decrease in hydrogen content of the product generated
from a GTL process. In conventional GTL processes, the products are predominantly
paraffins, linear olefins and linear alcohols. These products have a hydrogen to
carbon molar ratio of about 2, or greater. When hydrogen is used as a fuel, the
hydrogen to carbon ratio will likely decrease to below about 1.95 and preferably
below about 1.90. The most attractive source of hydrogen is the C
6-C
10
portion that can be readily reformed to obtain aromatics and sold as a high-octane
gasoline or aromatic hydrocarbons such as, for example, benzene, toluene, xylene,
combinations thereof, and the like. In contrast, the C
11+ products are
best used, for example, for jet fuel, diesel fuel, and lube-based products. Generally,
C
11+ products are not converted into aromatics and hydrogen. When the
C
6-C
10 portion of a syncrude is selectively reformed to produce
hydrogen and higher carbon number portions are not converted to aromatics, the
hydrogen to carbon molar ratio of at least a portion of the C
6-C
10
product will be at least about 0.1 unit less than the hydrogen to carbon
molar ratio of the C
11+ product. Preferably, the hydrogen to carbon
molar ratio of at least a portion of the C
6-C
10 product will
be at least about 0.25 unit less than the hydrogen to carbon molar ratio of the
C
11+ product.
Processes for the recovery of hydrogen from other gaseous streams is well
known in the art. Suitable techniques for recovering hydrogen from gaseous streams
include, but are not limited to, adsorption (pressure swing adsorption (PSA) and
displacement purge cycles (DPC)), membrane separation, and cryogenic separation.
These technologies are described, for example, in
Separation Process Technology,
Jimmny L. Humprey, George E. Keller II, McGraw-Hill, 1997, pp. 175-268, Handbook
of
Separation Techniques for Chemical Engineers, 2nd Ed., Philip A. Schweitzer,
McGraw-Hill, Sections 3.1, 3.2, 3.3, and
Chemical Engineer's Handbook, 4th
Ed., John H. Perry, McGraw-Hill, pp. 12-21 to 12-41 with specific reference to
pp. 12-32 to 12-33.
On rare occasions, hydrogen has been used as a fuel in petroleum refining. The
rare use of hydrogen in conventional petroleum refining is due, at least in part,
to the unusually high costs of products produced by such refining processes and
the high alternative value uses for upgrading petroleum. Nevertheless, hydrogen
is used as a fuel in rare locations when it is produced as a by-product and when
there are no alternative uses for the hydrogen at a particular site. This can be
the case, for example, in petrochemical manufacture of ethylene from ethane.
The processes of the present invention further provide integrated processes,
which refers to processes comprising a sequence of steps, some of which may be
parallel to other steps in the process, but which are interrelated or somehow dependent
upon either earlier or later steps in the total process. Specifically, according
to the processes of the present invention, the furnace or furnaces fueled by hydrogen
produced in the GTL facility are used to power other units in the GTL facility.
For example, the furnace may be used to provide heat to a syngas generator, a Fischer-Tropsch
reactor, one or more separators or hydrogen recovery means, or combinations thereof.
Thus, the furnace may power a unit which is necessary for the production of hydrogen,
which fuels the furnace. The integrated processes of the present invention, wherein
by-products are used as fuel, not only result in minimized CO
2 emissions
from GTL facilities, but also result in efficiencies and cost savings, compared
to processes that are not integrated.
The furnace or furnaces fueled according to the present invention may also take
the form of steam generators (boilers), providing steam used to rotate equipment
such as used in, for example, pumps, compressors and air separation facilities.
When hydrogen is used as a fuel, minor adjustments must be made to the design
and/or operation of the furnace. Typical adjustments to the design and/or operation
of the furnace include, but are not limited to, providing the furnace with larger
gas manifolds to accommodate relatively low-density hydrogen, providing the furnace
with larger gas burner nozzles to accommodate relatively low-density hydrogen and
providing the furnace with increased convection zone heating tubes to accommodate
less radiant hydrogen. If hydrogen is burned as a replacement for methane in the
existing furnace, and the gas density is too low, the hydrogen can be supplemented
with a heavier hydrocarbon (e.g., propane, butane, etc.) to increase gas density
to a density equivalent to that of methane while still achieving a reduction in
CO
2 emissions.
Methods for measuring CO
2 and excess oxygen in flue gas are well
known in the industry. Conventional methods for measuring CO
2 and excess
oxygen include, but are not limited to, gas chromatography, mass spectroscopy,
Orsat chemical analysis and on-line analysis. Of these known methods, on-line analysis
is preferred.
Methods for on-line analysis of flue gases are described, for example, in
James A. Janke,
Continuous Emissions Monitoring, Van Norstrand Reinhold
and Kenneth J. Clevett,
Process Analyzer Technology, John Wiley & Sons.
Typically, CO
2 is analyzed by a technology using infrared adsorption.
Excess oxygen is typically analyzed using oxygen sensor technology such as, for
example, zirconium oxide probes or paramagnetic sensors. On-line analyzers are
available from a number of vendors. For instance, for measuring excess oxygen,
on-line analyzers are available from vendors including Rosemont Analytical, Ametec/Thermox,
Teledyne and Servomex. In addition, for measurement of carbon dioxide, on-line
analyzers are available from vendors including Rosemont Analytical and Thermoenvironmental.
An exemplary embodiment of a GTL facility according to the presently claimed
invention
is depicted in FIG.
2. In this embodiment a methane-containing stream
11
is introduced into a syngas generator
12. The syngas generator
12
generates syngas
13, which passes through hydrogen recovery means
26
and then enters a Fischer-Tropsch reactor
14. The Fischer-Tropsch reactor
produces two product streams: a liquid C
3+ containing stream
15
and a vapor C
3+ containing stream
28. Stream
28 is sent
to separator
16 to generate unreacted gas stream
17 and a recovered
C
3+ liquid stream
29. C
3+ liquid streams
15
and
29 are combined in
18, and sent to second separator
19.
The second separator
19 separates the hydrocarbonaceous products stream
18 into a C
1-C
5 product stream
20, a naphtha
stream
21 and a C
10+ product stream
22. The naphtha stream
21 enters a naphtha reformer
23 wherein the naphtha stream
21
is reformed to produce a C
6-C
10 product stream
24
and a hydrogen by-product stream
31. Unreacted gas stream
17 is further
separated in separator
36 into hydrogen-reduced gas stream
38 and
hydrogen rich gas stream
37.
Hydrogen rich gas is then recovered from at least one of the syngas stream
13, unreacted gas stream
17 and the hydrogen by-product stream
31
using hydrogen recovery means
26,
36 and
32. Additionally,
while the embodiment in FIG. 2 is depicted as including three separate hydrogen
recovery means, it is also possible to use a single (or two) hydrogen recovery
means. Once recovered, the hydrogen rich gas mixes with the unreacted gas stream
17 via recovered hydrogen streams
27 and
33 exiting the hydrogen
recovery means
26 and
32, respectively. Further, while the recovered
hydrogen streams
27 and
33 are depicted as mixing with the gas stream
37 before entering the furnace
34, it is equally suitable for the
recovered hydrogen streams
27 and
33 to mix with the gas stream
37
during and/or after the gas stream
37 enters the furnace
34 instead
of, or in addition to, mixing with the stream
37 prior to entering the furnace
34.
Regardless of the specific hydrogen recovery means used and the sequence
in which the recovered hydrogen mixes with the unreacted gas stream, the recovered
hydrogen acts to reduce the amount of CO
2 present in the flue gas
35
emitted from the furnace
34. In particular, the hydrogen acts to reduce
the mole percent of CO
2 in the flue gas
35 such that the mole
percent of CO
2 in the flue gas
35 is represented by the formula:
and more preferably by the formula:
While the present invention has been described with reference to specific embodiments,
this application is intended to cover those various changes and substitutions that
may be made by those of ordinary skill in the art without departing from the spirit
and scope of the appended claims.
*
