U.S. patent application number 12/392554 was filed with the patent office on 2009-06-25 for process to maximize methane content in natural gas stream.
Invention is credited to Paul T. Barger, Frank S. Modica, David W. Penner, Mark E. Schott, Kurt M. Vanden Bussche.
Application Number | 20090158660 12/392554 |
Document ID | / |
Family ID | 40786964 |
Filed Date | 2009-06-25 |
United States Patent
Application |
20090158660 |
Kind Code |
A1 |
Vanden Bussche; Kurt M. ; et
al. |
June 25, 2009 |
Process to Maximize Methane Content in Natural Gas Stream
Abstract
The present invention relates to a hydrogenolysis process and
catalyst for conversion of ethane to methane in a natural gas
stream when such streams contain large quantities of ethane. Such
natural gas streams include the product of the in situ treatment of
oil shale to produce oil and gas. Hydrogenolysis catalysts have
been identified that produce high yields of ethane at low light-off
temperatures.
Inventors: |
Vanden Bussche; Kurt M.;
(Lake in the Hills, IL) ; Barger; Paul T.;
(Arlington Heights, IL) ; Penner; David W.; (Lake
Zurich, IL) ; Schott; Mark E.; (Palatine, IL)
; Modica; Frank S.; (Naperville, IL) |
Correspondence
Address: |
HONEYWELL INTERNATIONAL INC;PATENT SERVICES
101 COLUMBIA DRIVE, P O BOX 2245 MAIL STOP AB/2B
MORRISTOWN
NJ
07962
US
|
Family ID: |
40786964 |
Appl. No.: |
12/392554 |
Filed: |
February 25, 2009 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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11322411 |
Dec 30, 2005 |
|
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12392554 |
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Current U.S.
Class: |
48/127.7 |
Current CPC
Class: |
C10L 3/12 20130101; C10L
3/102 20130101; C10L 3/10 20130101 |
Class at
Publication: |
48/127.7 |
International
Class: |
C10L 3/00 20060101
C10L003/00 |
Claims
1. A process for increasing methane content in a natural gas feed
stream comprising: a) providing a gaseous feed stream comprising a
first quantity of methane, ethane, propane and hydrogen wherein
said ethane and propane comprise about 6 to 30 vol-% of said
gaseous feed stream; and b) sending said gaseous feed stream to a
conversion unit wherein a hydrogenolysis reaction takes place
wherein said natural gas feed stream is contacted with at least one
hydrogenolysis catalyst at a temperature and pressure sufficient to
substantially convert said ethane to a second quantity of
methane.
2. The process of claim 1 further comprising separating said first
quantity of methane and said second quantity of methane from other
components within said gaseous feed stream to form a purified
natural gas feed stream.
3. The process of claim 1 wherein said hydrogen and said ethane are
present in a molar ratio of about 0.8:1 to 10:1.
4. The process of claim 1 wherein said feed stream further
comprises carbon oxides.
5. The process of claim 1 wherein said feed stream further
comprises higher hydrocarbons than ethane.
6. The process of claim 1 wherein said hydrogenolysis catalyst
comprises at least one transition metal selected from the group
consisting of nickel, cobalt, osmium, iridium, rhodium, ruthenium,
rhenium and iron on a metal oxide support.
7. The process of claim 1 wherein said first quantity of methane is
separated from said gaseous feed stream before said gaseous feed
stream is sent to said conversion unit.
8. The process of claim 1 wherein at least 50% of said ethane and
propane are converted to methane.
9. The process of claim 1 wherein at least 90% of said ethane and
propane are converted to methane.
10. The process of claim 1 wherein a portion of said CO and
CO.sub.2 are converted to methane within said conversion unit.
11. The process of claim 1 wherein after said hydrogenolysis
reaction takes place, carbon oxides are added to a resulting
gaseous stream and then the resulting gaseous stream is subjected
to a methanation reaction to react said carbon oxides with hydrogen
to produce a third quantity of methane.
12. The process of claim 1 wherein said natural gas feed stream is
a product of thermal treatment of oil or carbon containing rocks or
sand.
13. The process of claim 1 wherein said hydrogenolysis reaction has
a light-off temperature between about 300.degree. and 375.degree.
C.
14. The process of claim 1 wherein said temperature for conversion
of said higher carbon hydrocarbons than methane to methane is from
about 2500 to 600.degree. C.
15. The process of claim 1 wherein said gaseous feed stream
comprises about 10 to 25 vol-% combined ethane and propane.
16. The process of claim 1 wherein said gaseous feed stream
comprises about 20 to 25 vol-% combined ethane and propane.
17. The process of claim 1 wherein said gaseous feed stream is sent
to at least two of said conversion units sequentially.
18. The process of claim 17 wherein said gaseous feed stream is
divided into a first gaseous feed stream and a second gaseous feed
stream prior to passing to said at least two of said conversion
units, said first gaseous feed stream is heated to a hydrogenolysis
reaction temperature, then said first gaseous feed stream is sent
to a first conversion unit to produce a first enhanced methane
stream, then said first enhanced methane stream is cooled upon
being mixed with said second gaseous feed stream to form a combined
gaseous feed stream, and then said combined gaseous feed stream is
sent to a second conversion unit to be converted to a second
enhanced methane stream.
19. The process of claim 1 further comprising sending said gaseous
feed stream to a reactor to convert said carbon dioxide and carbon
monoxide to methane.
20. The process of claim 1 wherein said purified natural gas stream
is sent into a natural gas pipeline to be transported.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application is a Continuation-in-Part of copending
application Ser. No. 11/322,411 filed Dec. 30, 2005, the contents
of which are hereby incorporated by reference in its entirety.
FIELD OF THE INVENTION
[0002] The present invention relates to a process for enhancement
of methane content in a natural gas stream. More particularly, the
present invention relates to a hydrogenolysis process and catalyst
for conversion of ethane to methane in a natural gas stream when
such streams contain large quantities of ethane.
[0003] The composition of natural gas that will be sent into a
pipeline must adhere to a large number of specifications to ensure
proper operation of downstream equipment that uses it. The energy
value of the gas, normally expressed in BTU's is an important
criterion. The maximum allowable BTU value of the gas varies
between 1180 and 1060 BTU/scf, depending on the pipeline and the
country it is in. In some locations, the composition of the natural
gas stream needs considerable treatment to meet these criteria.
[0004] Ever since the commercial use and production of liquid
hydrocarbons commenced in the mid-19th century, scientists have
pursued ways of economically extracting hydrocarbons from
organic-rich rocks such as oil shale. Historically and currently,
almost all hydrocarbons are produced from subterranean reservoir
strata and formations. Such hydrocarbon-bearing reservoirs,
containing natural gas and/or oil, typically comprise permeable and
porous rock such as sandstone or limestone (carbonate). Frequently,
these types of rocks serve as traps for hydrocarbons and can be
commercially exploited as oil or gas reservoirs. Once penetrated by
a well, reservoir strata may be able to produce hydrocarbons in
commercial quantities.
[0005] Reservoir strata and formations such as sandstone and
carbonate are not, however, the original source of the
hydrocarbons. The reservoirs are usually the rocks into which the
hydrocarbons have migrated over geologic time. The precursors to
these reservoirs are the organic-rich rocks from which the
hydrocarbons originally derive. A common organic-rich source rock
is shale which contains a hydrocarbon precursor known as kerogen.
The kerogen is a complex organic material that is the product of
the initial biologic organic matter that was buried with the soils
and clays which ultimately formed the shale rocks. The kerogen is
generally tightly bound within the rock and only releases
hydrocarbons when it is exposed to temperatures over 100.degree.
C., typically under deep burial. This process is extremely slow and
normally takes place over thousands or millions of year's time.
Eventually, under the right conditions, the hydrocarbons within the
shale or other source rocks will migrate (often through natural
fissures, fractures and faults) until they reach a reservoir trap
such as a sandstone or carbonate formation.
[0006] Source rocks that have yet to liberate their kerogen in the
form of hydrocarbons are known as "immature" source rocks. These
immature source rocks, however, contain the overwhelming majority
of buried organic matter in the earth's crust. It is estimated that
less than 1% of the organic matter is in the form of is
hydrocarbons contained in reservoir rocks. The great majority is
still present as kerogen and thus represents a vast untapped energy
source.
[0007] Unfortunately, kerogen is not readily liberated from shale
or other source rocks. Kerogen-bearing rocks near the surface can
be mined and crushed and, in a process known as retorting, the
crushed shale can then be heated to high temperatures which convert
the kerogen to liquid hydrocarbons. Commercial and experimental
mining and retorting methods for producing hydrocarbons from shale
have been conducted since 1862 in various countries around the
world. In the 1970s and 1980s several oil companies conducted pilot
plant shale oil operations in the Piceance Basin of Colorado where
large, high-quality reserves of oil shale are located. There are a
number of drawbacks to surface production of shale oil which has
made its production more costly compared to conventional
hydrocarbon production.
[0008] One solution to the high costs associated with surface shale
oil production and the problems involved in trying to mine shale
that is located at depths too deep to mine, is to produce shale oil
using in situ processes. In situ processing eliminates the costs
associated with the mining, crushing, handling and disposal of the
shale rock. In the in situ process, the oil shale can first broken
into large fragments with explosives and then the kerogen is
subjected to in situ heating. The heating may be a combustion
process or by another method of introducing heat underground such
as steam injection or by air injection into the shale formation.
The end result is the production of a product that on an energy
basis is about two-thirds liquid with about one-third being a gas
similar to natural gas. There will be some variation in
composition, but the gas product comprises methane, ethane,
propane, higher carbon hydrocarbons, hydrogen, carbon dioxide and
carbon monoxide. This gas product stream may contain substantially
higher percentages of ethane and propane than in a typical natural
gas stream. This composition poses new challenges for gas
composition adjustment to the pipeline specification.
[0009] Several techniques have been proposed to reduce the caloric
value of a rich gas that contains up to 30 vol-% combined ethane
and propane. They range from the addition of nitrogen or air to the
removal of higher hydrocarbons, by condensation. The addition of
nitrogen requires the construction of an air separation plant on
site, while the selective removal of the heavier hydrocarbons
generates an LPG or NGL product stream. In certain cases, the value
associated with such a hydrocarbon side-stream is significant, due
to co-location of the gas conditioning plant with other chemical
processing plants (such as ethane cracker) or a convenient outlet
for liquid fuels.
[0010] In other cases however, the side product is of little value,
as the producer has no viable means to bring it to the market due
to remote location, capital expenditure of conversion process, or
lack of interest in making chemicals. The latter case results in
atypical economics: higher hydrocarbons are only valued at local
fuel value, where as methane can be sold at a higher natural gas
value in the market. In a typical gas stream from an in situ
process, the gas comprises about 20-25% by volume ethane (including
a small volume propane). In some locations it will be feasible to
separate the ethane from the methane and then dehydrogenate the
ethane to produce ethylene. However, in some locations it is not
practical to produce ethylene and products such as polyethylene. In
such locations, it is highly desirable to be able to transport this
ethane in the natural gas pipeline. The present invention provides
an inexpensive process to achieve this goal.
SUMMARY OF THE INVENTION
[0011] We have now invented a method for adjusting the composition
of natural gas or other methane containing stream prior to entry
into the pipeline. The technique makes use of the available
hydrogen in the feed to convert the higher hydrocarbons (especially
ethane), as well as the carbon oxides, into methane, through
catalytic hydrogenolysis and other reactions. While it is
envisioned that the catalytic steps required can be carried out in
a single reactor, it may be desirable to use separate reactors
operating at different conditions to optimize the catalytic
performances for the various steps required, such as olefin
saturation, COx hydrogenation and light paraffin hydrogenolysis.
The process of the present invention comprises a process for
increasing methane content in a natural gas feed stream or a
similar feed stream comprising providing a gaseous feed stream
comprising a first quantity of methane, ethane, and hydrogen and
sending the gaseous feed stream to a conversion unit wherein a
hydrogenolysis reaction takes place wherein said natural gas feed
stream is contacted with at least one hydrogenolysis catalyst at a
temperature and pressure sufficient to substantially convert said
ethane to a second quantity of methane. Further separation of the
methane from any other components may be required to form a
purified natural gas feed stream. In addition, a methanation
reaction may be a part of the process to increase the methane
content while reducing the carbon dioxide and hydrogen content. To
the extent that there are higher hydrocarbons than ethane (such as
propane), these hydrocarbons are also substantially converted to
methane by the hydrogenolysis reaction.
[0012] The gaseous feed stream may contain 6 to 30 vol-% combined
ethane and propane, preferably from 10 to 25 vol-% ethane and
propane and most preferably from 20 to 25 vol-% combined ethane and
propane.
[0013] The hydrogenolysis of ethane process is shown by the
following equation:
H.sub.2+C.sub.2H.sub.6.fwdarw.2CH.sub.4.
Preferred catalytic materials for this purpose are transition
metals (particularly nickel, cobalt, osmium, iridium, rhodium,
ruthenium and rhenium) supported on metal oxide supports. In the
case of nickel and cobalt, the metal is present in a relatively
high concentration on the support due to a lower activity level
(>5 wt-%), while the more active but much more expensive
ruthenium and rhodium catalysts use lower levels of metals (<1
wt-%). The hydrogenolysis reaction has a light off temperature
below which catalyst activity is very low (under 20% conversion)
and above which where ethane conversion to methane can be more than
90%. A catalyst with a low light-off temperature is preferred in
that it saves energy by reducing the amount of preheating of feed
that is required. Preferred supports include alumina, silica,
zirconia, titania, other metal oxides and their mixtures. A theta
form of alumina was found to be a particularly preferred support
material. The invention further consists of flow schemes for
implementation of the invention and integration with existing
components.
DETAILED DESCRIPTION OF THE INVENTION
[0014] In the present invention, the enhancement of the methane
content in a natural gas stream has been found to be achievable
through the catalytic hydrogenolysis of paraffins by the following
general reaction:
C.sub.nH.sub.m+(4n-m)/2H.sub.2=nCH.sub.4.
[0015] The predominant paraffin to be converted to methane found in
the natural gas streams is ethane. The combined volume percent of
ethane plus propane may range from about 6 to 30 vol-%, preferably
from 10 to 25 vol-% and most preferably from 20 to 25 vol-%. This
reaction is exothermic and will therefore be limited in conversion
at higher temperatures. Optimizing kinetics vs. extent of
conversion, the preferred temperature range for this conversion
will be 250.degree. to 600.degree. C. Depending on the actual
composition of the gas, some means may need to be employed to
reduce the adiabatic temperature rise. A relatively cheap method to
accomplish this is the use of interbed quenches, using the cold
feed. In one embodiment of the present invention, the feed can be
divided into two or more portions with a first portion sent through
the hydrogenolysis reaction and then mixed with a remaining portion
of feed before the combined feed is sent again through a
hydrogenolysis reaction. The effect of pressure on the rate of
conversion is substantial. The reaction will preferably be run at
either the well pressure or the pipeline pressure.
[0016] A useful catalytic system in the present invention is
reduced nickel supported on a refractory metal oxide, such as
alumina. The catalyst can be prepared as supported NiO that is
reduced in situ with H.sub.2 prior to use. Conditions for the
hydrogenolysis of light paraffins, such as ethane, to methane are
250.degree. to 600.degree. C. (preferably 300.degree. to
400.degree. C.), 0 to 500 total psig (preferably 10 to 50 psig
ethane partial pressure), 0.1 to 1000 hr.sup.-1 WHSV (preferably
0.5 to 5 hr.sup.-1) and a H.sub.2 to hydrocarbon molar feed ratio
that can be as low as sub-stoichiometric at 0.8 moles of hydrogen
to each mole of ethane and where complete conversion of ethane is
sought preferably 2 to 5 times stoichiometric since some of the
hydrogen may react with carbon oxides in the stream to produce
methane. The feed will likely include other components, in
particular methane, CO and CO.sub.2. Other potential catalysts for
catalyzing the hydrogenolysis reaction include supported Co, Ru,
Rh, Os, Ir, Re and Fe.
[0017] The gas will also contain the carbon oxides as well as
steam. These will most likely be removed prior to entry in the
pipeline. It is of interest to note that the carbon oxides can also
readily be converted to methane over the same catalyst and
conditions described for the hydrogenolysis reaction. Even if both
oxides are not converted directly to methane, the water gas shift
reaction, which is also catalyzed by the catalysts and conditions
proposed for hydrogenolysis, will rapidly equilibrate any
CO/CO.sub.2 ratio according to the following formulas:
Methanation reaction: CO+3H.sub.2=CH.sub.4+H.sub.2O
Water gas shift reaction: CO+H.sub.2O=CO.sub.2+H.sub.2
[0018] Depending on the amount of hydrogen available in the feed,
the conversion of the higher hydrocarbons and the conversion of the
carbon oxides may both be feasible. In doing so though, more water
is formed as a side product, putting an additional load on the gas
driers. The following table shows an example of a feed treated in
accordance with the present invention with the pipeline
specification and the predicted composition of a treated stream.
The stream's methane content is increased by a very significant
50%. The feed and predicted values may not total exactly 100% due
to rounding of values.
TABLE-US-00001 Vol-% Feed Pipeline Spec Predicted H.sub.2 19.6 0.1
0.01 CH.sub.4 56 n/a 94.2 C.sub.2 21 C2 + C3 <3.7 1.5
C.sub.2.dbd. 0.2 (low) .04 C.sub.3 1.5 C2 + C3 <3.7 1.1
C.sub.3.dbd. 0.1 (low) 0.5 CO 0.5 (low) 0.53 CO.sub.2 0.0 Non
hydrocarbon total <3 vol-% 0.9 N.sub.2 1.3 Non hydrocarbon total
<3 vol-% 1.2 H.sub.2S <10 ppmv (low) <0.1 ppmv Water Dry
<5 lbs/MM scf on spec
[0019] In a prior art process, the following separation and
purification steps take place. Upon separation of the produced
crude and associated gas (this will be done in a number of steps at
different pressures), the crude oil is sent down its pipeline,
while the gas composition undergoes further adjustment. Upon
desulphurization of the gas, the gas typically passes through a
demethanizer to remove the methane and hydrogen. The bottoms of
this column are then led to a de-ethanizer, where ethane and
ethylene are separated from a potential LPG product. From the
demethanizer, methane and hydrogen are split. Hydrogen can be sold
as a by-product; the methane is the main product on the gas side
and is sent down the pipeline. The ethane can be dehydrogenated to
produce ethylene.
[0020] In one embodiment of the present invention, an ethane
conversion step is integrated into the process. This scheme takes
the C.sub.2 stream from the de-ethanizer, and part of the hydrogen
product to a converter in which a hydrogenolysis reaction takes
place. The ethane and hydrogen streams are preheated to a
temperature of about 300.degree. to 350.degree. C. and led into the
converter. The ethane is substantially converted to methane, with
at least 50%, more preferably over 90% and as much as 99% or even
more of the ethane converted to methane. The effluent of the
converter is cooled in the F/E exchanger, cooled further against
cooling water, potentially chilled further and sent back to the
hydrogen/methane separation column. Note that the conversion needs
to be such that the BTU value of the stream coming out of the
bottom of the hydrogen/methane separator does not exceed the
pipeline specification.
[0021] In another embodiment of the invention, instead of
separating out and processing the ethane separately, the whole gas
stream is mixed with a recycle stream and fed into the conversion
reactor. This processing of the complete stream avoids the expense
of including a deethanizer in the design which would add a
significant energy cost for refrigeration. Larger reactors are
required due to the increase in the volume processed, but this
embodiment reduces the adiabatic temperature rise over the
conversion significantly and makes the reactor simpler and cheaper.
The product exiting this reactor may still has a relatively high
hydrogen concentration due to excess hydrogen present for the
hydrogenolysis reaction and would require further product
separation. Typically, a membrane unit can be used to produce a
product gas stream low in hydrogen and a corresponding stream high
in hydrogen content. In some designs a lower amount of hydrogen is
used which allows for this step to be unnecessary.
[0022] Additional control of the temperature can be achieved by
splitting the gas stream into two or more streams prior to entering
the hydrogenolysis converter units. The first stream is then
preheated prior to entering a first converter. Then the second
stream acts as a quench stream upon being combined with the first
stream that has now exited the first converter. This arrangement
can control the reaction temperatures and avoid the need for any
auxiliary cooling. This is important as the reactions involved are
equilibrium limited and as the equilibrium constant is strongly
temperature dependent in the range of operation considered here.
The temperature at the exit of Converter 2 should preferably not
exceed 470.degree. C. and is preferably lower.
[0023] Control of the hydrogen content within the stream can also
be achieved by employing a methanation step in which the carbon
oxides react with hydrogen to produce additional methane. One way
that this can be achieved is by adding a CO.sub.2 stream to the
stream higher in hydrogen content after using the membrane to
produce a methane stream and a hydrogen concentrated stream and
after this addition, performing a selective methanation. In one
example of the use of such selective methanation the raw feed is no
longer combined with a recycle stream but is still split into 2
streams. The ratio between the two streams is controlled such that
the exit of the second converter is a temperature between
450.degree. and 500.degree. C., and preferably in the lower part of
this range. Upon exiting the second Converter, CO.sub.2 is blended
into the stream and a selective methanation is performed in a
finishing reactor. Heat exchange with an incoming gas feed or other
cooling source may be required to bring the feed temperature to
this finishing reactor down to 300.degree. to 350.degree. C. The
adiabatic temperature rise in the finishing vessel will be minimal.
In the optimum case of sub-stoichiometric hydrogen mentioned above,
the temperature increases by some 2.degree. C. The effluent after
the methanation reaction is then taken to a CO.sub.2 removal unit
to be brought down to natural gas pipeline specification level for
CO.sub.2 using common technology such as solvent separation
systems, an adsorption process or a CO.sub.2 selective membrane.
The CO.sub.2 recovered from that separation can be recycled to an
earlier point in the process where it can undergo methanation to
further enhance the methane content to the natural gas
pipeline.
[0024] The following discussion concerns the catalysts that have
been found useful in the present invention. The initial experiments
used a commercial nickel on attapulgite clay catalyst. The
experimental conditions were a 400 psig, 1 hr.sup.-1 C.sub.2H.sub.6
weight hourly space velocity (WHSV) and molar feed ratios of
hydrogen/ethane of 2/1 and 4/1. The presence of a light-off
temperature could be clearly seen. The initial molar feed ratio of
hydrogen/ethane was 2/1. Initially it was found that increasing the
temperature from 300.degree. to 335.degree. C. increased conversion
to only about 12%. An additional increase of temperature to
340.degree. C. resulted in a dramatic increase in conversion to
over 95%. The high level of conversion was lost when the hydrogen
feed rate was doubled to provide a 4/1 hydrogen/ethane molar feed
ratio. However, it was found that a further temperature increase of
just 10.degree. to 350.degree. C. was sufficient to restore
conversion from ethane to methane to over 95%. It was found that
once high conversion was restored, the reactor block temperature
could be reduced by 10.degree. C. without a substantial change in
the level of conversion.
[0025] A second laboratory plant test was conducted at a lower
pressure of 50 psig using the same nickel/clay catalyst as above.
At a 1 hr.sup.-1 C.sub.2H.sub.6 WHSV and 2/1H.sub.2/C.sub.2H.sub.6
molar feed ratio a light-off phenomenon was again observed as an
inlet temperature of about 340.degree. C. was required to obtain
greater than 95% conversion. However, once the reaction exotherm
was established in the catalyst bed, the temperature could be
lowered to as low as 305.degree. C. without having conversion of
ethane fall below 90%. At about 170 hours on stream, the conditions
were changed to 2 hr.sup.-1 C.sub.2H.sub.6 WHSV and
4/1H.sub.2/C.sub.2H.sub.6 molar feed ratio which required an inlet
temperature of about 340.degree. C. to maintain an exotherm on the
catalyst bed.
[0026] Further tests were performed to screen for catalyst activity
using other metals besides nickel. Catalysts consisting of
different levels of cobalt, iron, iridium, nickel, rhenium, rhodium
and ruthenium were all tested on attapulgite clay, theta alumina
and potassium-modified theta alumina supports. Rhodium was found to
provide the greatest catalytic activity achieving near 100%
conversion of ethane at a 0.5% metal loading. High conversion can
also be achieved using higher concentrations of less expensive
nickel and somewhat higher temperatures. The lowest light-off
temperature of 225.degree. to 275.degree. C. was obtained with
rhodium, with the lowest temperature obtained with the highest (2%)
metal loading. Iridium and ruthenium at the 0.5 to 2% metal loading
levels give light-off temperatures in the 275.degree. to
325.degree. C. range, while nickel at 5 to 25% metal loading levels
falls in the 300.degree. to 350.degree. C. range.
[0027] In some embodiments of the present invention, a combination
of two or more transition metals may be used. For example, a small
amount of rhodium catalyst may be used to achieve light-off
temperature and a larger amount of nickel catalyst to catalyze the
continuing reaction. The four best transition metal catalysts that
were tested were rhodium, ruthenium, iridium and nickel.
* * * * *