Note: Descriptions are shown in the official language in which they were submitted.
METHODS AND SYSTEMS FOR PRODUCING LIQUID HYDROCARBONS
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the priority benefit of United States
Patent Application
61/913,009 filed December 6,2013 entitled METHODS AND SYSTEMS FOR PRODUCING
LIQUID HYDROCARBONS.
[0002] In addition U.S. Provisional patent application number 61/913,009
is related to but
does not claim priority to ExxonMobil Chemical Company's U.S. Provisional
patent
application number 61/912,877 (2013EM330) filed on December 6, 2013 entitled
HYDROCARBON CONVERSION; U.S. Provisional patent application number 61/912,866
filed on December 6, 2013 entitled PRODUCTION OF C2+ OLEFINS; U.S. Provisional
patent
application number 61/912,886 filed on December 6, 2013 entitled PRODUCTION OF
C2+
OLEFINS; and U.S. Provisional patent application number 61/912,901 filed on
December 6,
2013 entitled HYDROCARBON CONVERSION.
FIELD
[0003] The present techniques generally relate to producing an aromatic
hydrocarbon
stream and generating power. Particularly, the present techniques provide for
the conversion
of raw natural gas into an aromatic hydrocarbon stream and the generation of
electricity from
a tail gas stream.
BACKGROUND
[0004] This section is intended to introduce various aspects of the art,
which may be
associated with exemplary embodiments of the present techniques. This
description is
believed to assist in providing a framework to facilitate a better
understanding of particular
aspects of the present techniques. Accordingly, it should be understood that
this section
should be read in this light, and not necessarily as admissions of prior art.
[0005] Some processing technologies provide for the conversion of a high
quality gas
into longer-chain hydrocarbons. As used herein a "high quality gas" can be
formed by
purification and fractionation to form a narrow molecular weight material. For
example,
recovered raw natural gas may be separated from recovered crude oil and later
processed for
the removal of water, natural gas condensate, acid gases, and other
contaminants, and then
fractionated into different molecular weight components to produce the high
quality gas. The
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purification and fractionation may be done before the gas product is converted
into the higher
molecular weight hydrocarbons. This may be due in part to mainline
transportation systems
imposing restrictions on the make-up of the hydrocarbons before entry into
additional
processing units, pipelines facilities, or storage.
100061 The
technologies for the process of converting the high quality gas into the
higher
molecular weight hydrocarbons include relatively well-known and well-proven
techniques
that have been in development through the years. One example of a process that
can convert
a gas product into higher molecular weight hydrocarbons may include the
CyclarTM process
from UOP. The CyclarTM process is a non-integrated chemical production
facility that
converts liquefied petroleum gas (LPG) directly into a liquid, aromatic
product. Particularly,
the CyclarTm process provides a process for upgrading lower value propane and
butane
(C3/C4 hydrocarbons) into a higher value, liquid aromatic concentrate
(benzene, toluene,
xylene, or "BTX") that may be used as feedstock to an aromatics complex. The
process may
be typically operated at temperatures higher than 800 F (425 C). Another
process is the
Choudhary process, which also converts a percentage of methane, along with the
C3/C4
hydrocarbons, to yield up to a 30% conversion of the methane along with a
higher conversion
rate of the Cl/C4 hydrocarbons. See Journal of Natural Gas Chemistry 18(2009)
260-272,
Review: Energy-Efficient coaromatization of methane and propane, Jianjun Guo,
Hui Lou,
Xiaoming Zheng.
I0007j The Fischer-
Tropsch process can also be used to convert hydrocarbons or natural
gas into higher molecular weight hydrocarbons. The Fischer-Tropsch process is
an
exothermic conversion process including a collection of chemical reactions
that can convert a
mixture of carbon monoxide and hydrogen into liquid hydrocarbons. The more
useful
reactions produce mostly straight-chain alkanes, suitable for diesel fuel.
Generally, the
Fischer-Tropsch process is operated in the temperature range of 302 F to 572
F. In this
case, higher temperatures lead to faster reactions and higher conversion rates
while favoring
methane production. An increase in pressure in the process leads to higher
conversion rates
and also favors the formation of long-chained alkanes, both of which are
desirable. Typical
pressures can range from one to several tens of atmospheres.
100081 Another
process is the RZTM Platforming process from UOP. The RZTm
Platforming process is designed to efficiently convert paraffins and
naphthenes to aromatics
with limited ring opening or cracking. Specifically, the RZTM Platforming
process utilizes a
fixed bed system for the production of high yields of benzene toluene (BT)
aromatics and
hydrogen. Additionally, the Aromax Process from Chevron Phillips selectively
converts
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light paraffins and naphthenes to both hydrogen and aromatic products
utilizing fixed-bed
reforming equipment. The aforementioned process are just a few of the
techniques used to
convert high quality gas into aromatic products.
[00091 U.S. Patent Application Publication No. 2012/0036889 by Denton et
al. discloses
a methane conversion process. The process includes the conversion of a gaseous
hydrocarbon feed, including methane, to an aromatic hydrocarbon. The methane
conversion
process is integrated with a liquefied natural gas (LNG) and/or pipeline gas
process. In
operation, the gascous hydrocarbon stream is feed to a conversion zone with
specified
parameters to produce a gaseous effluent stream, including at least one
aromatic compound,
unreacted methane, and hydrogen.
[0010] U.S. Patent No. 8,455,707 to Hershkowitz discloses a process for
converting
methane into acetylene and other higher hydrocarbons. The process includes a
reverse-flow
reactor system where first and second reactants are supplied in a first
reactor bed such that
both reactants serve to quench the reactor bed and to control combustion for
thermal
regeneration. See also U.S. Patent No. 6,130,260 to Synfuels, which discloses
converting
methane into acetylene and then into liquid fuels.
[OM 11 U.S. Patent Application Publication No. 2007/0260098 by Iaccino et
al. discloses
the production of aromatic hydrocarbons from methane. The process includes a
process to
convert methane to aromatic hydrocarbons to produce first and second effluent
streams. The
hydrogen within the first effluent stream is reacted with an oxygen-containing
species to
produce a second effluent stream including a reduced hydrogen content.
10012] U.S. Patent Application Publication No. 2009/0247804 by Sauer et
al. discloses a
method for converting methane to useful hydrocarbons. The process includes
combining a
methane/hydrogen fluid with a catalyst composition derived from an aluminum
compound
and a transition metal halide to produce higher molecular weight hydrocarbons.
[00131 Many other conversion process techniques exist for the production
of aromatics
from a high quality gas. However, the processes generally rely on an existing
infrastructure,
such as a chemical plant and purification systems. Accordingly, there is a
need for an
independent infrastructure process for the conversion of an unprocessed raw
hydrocarbon gas
to an aromatic product that may also incorporates other processing techniques
including
power generation and heat removal.
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SUMMARY
100141 An exemplary embodiment provides a method for producing liquid
hydrocarbons
and power. The method includes producing a first stream including methane. The
method
includes reacting the first stream in a reactor to form a second stream having
at least a portion
of the methane converted to a higher molecular weight hydrocarbon. The method
includes
separating the second stream into a tail stream that is enriched in methane
and a product
stream enriched in the higher molecular weight hydrocarbon. The method
includes
combusting at least a portion of the tail stream to generate power.
100151 Another exemplary embodiment provides a system for producing
liquid
hydrocarbons from a first stream including methane and generating power. The
system
includes a reactor configured to convert the first stream into a second stream
having at least a
portion of the methane in the first stream converted to a higher molecular
weight
hydrocarbon. The system includes a separation vessel configured to separate
the second
stream into a tail gas stream and a liquid hydrocarbon stream. The system
includes a
combustor to combust the tail gas stream to generate power.
100161 Another exemplary embodiment provides a method for producing an
aromatic
hydrocarbon and generating electricity from a tail gas stream. The method
includes feeding a
first stream including raw natural gas into an aromatic reactor. The method
includes
converting the first stream, at least in part, to a second stream including
the aromatic
hydrocarbon. The method includes separating the second stream into the tail
gas stream and
a liquid aromatic hydrocarbon stream. The method includes burning at least a
portion of the
tail gas stream in a gas turbine to generate the electricity.
DESCRIPTION OF THE DRAWINGS
100171 The advantages of the present techniques are better understood by
referring to the
following detailed description and the attached drawings, in which:
100181 Fig. 1 is an illustration of an oil and gas well reservoir
including trapped oil and
gas within rock formations;
[00191 Fig. 2 is a block diagram of a system for producing a higher
molecular weight
hydrocarbons product;
100201 Fig. 3 is a simplified process flow diagram for a natural gas liquid
recovery and
stabilization unit including a distillation column;
100211 Fig. 4 is a process flow diagram for a natural gas liquid recovery
and stabilization
unit including a crude wash;
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100221 Fig. 5 is a process flow diagram for a natural gas liquid recovery
and stabilization
unit that recovers hydrogen from the tail gas; and
100231 Fig. 6 is a flow block diagram of a method for producing liquid
hydrocarbons.
DETAILED DESCRIPTION
[0024] In the following detailed description section, specific embodiments
of the present
techniques are described. However, to the extent that the following
description is specific to
a particular embodiment or a particular use of the present techniques, this is
intended to be
for exemplary purposes only and simply provides a description of the exemplary
embodiments. Accordingly, the techniques are not limited to the specific
embodiments
described below, but rather, include all alternatives, modifications, and
equivalents falling
within the true spirit and scope of the appended claims.
10025] At the outset, for ease of reference, certain terms used in this
application and their
meanings as used in this context are set forth. To the extent a term used
herein is not defined
below, it should be given the broadest definition persons in the pertinent art
have given that
term as reflected in at least one printed publication or issued patent.
Further, the present
techniques are not limited by the usage of the terms shown below, as all
equivalents,
synonyms, new developments, and terms or techniques that serve the same or a
similar
purpose are considered to be within the scope of the present claims.
100261 The term "aromatic hydrocarbons" refers to molecules containing
one or more
.. aromatic rings. Examples of aromatic hydrocarbons are benzene, toluene,
xylenes,
naphthalene, and methylnaphthalenes
100271 The term "aromatic" refers to unsaturated compounds with at least
one closed ring
of at least 6 atoms, with all of the ring atoms being co-planar or almost co-
planar and
covalently linked, and with all of the ring atoms being part of a mesomeric
system. As used
herein, when the "aromatic" substituent is monocyclic, it preferably contains
6 ring atoms,
and when the "aromatic" substituent is polycyclic, it preferably contains 10
ring atoms
contained in fused rings.
100281 The term "Cn" hydrocarbon refers to a hydrocarbon with "n" carbon
atoms, and
"Cn-Cn, hydrocarbons" represents hydrocarbons having between "n" and "m"
carbon atoms.
100291 The term "catalyst" refers to a material, which under certain
conditions of
temperature or pressure increases the rate of specific chemical reactions. A
catalyst may also
be a material that performs as a physisorbent or chemisorbent for specific
components of the
feed stream.
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100301 The
term "chain length" may broadly refer to a number of atoms forming and/or
making a backbone and/or structure of a molecule and/or compound, such as
carbon atoms
for a hydrocarbon.
10031i The
term "chemical reaction" refers to any process including the breaking or
making of chemical bonds including a dissociation, recombination, or
rearrangement of
atoms.
10021 The
term "coke" refers to the solid residue remaining from the pyrolysis of
hydrocarbons.
100331 The
term "crude oil" refers to hydrocarbons formed primarily of carbon and
hydrogen atoms. The hydrocarbons may also include other elements, such as, but
not limited
to, halogens, metallic elements, nitrogen, oxygen, or sulfur. Hydrocarbons
derived from an
oil-bearing formation may include, but are not limited to, kerogen, bitumen,
pyrobitumen,
asphaltenes, resins, oils, or combinations thereof.
100341 The
term "fixed-bed reactor" refers to a reactor containing catalyst material
typically in pellet form, packed in a static bed.
100351 The
term "gas turbine" refers to a unit including a compressor, a combustion
chamber, and turbine mechanically connected to the compressor, most preferably
connected
on a common shaft. Generally, a gas turbine uses energy from burning a fuel in
the
combustion chamber to power a compressor that provides an oxidant stream to
the
combustion chamber. This is termed the Brayton cycle. A "turbine" is used in
the meaning of
an expansion unit for converting of the energy of high temperature gas to
rotational energy.
10036] The
term "higher hydrocarbons" refers to hydrocarbon(s) having more than one
carbon atom per molecule, oxygenate having at least one carbon atom per
molecule, e.g.,
ethane, ethylene, propane, propylene, benzene, toluene, xylenes, naphthalene,
and/or methyl
naphthalene; and/or organic compound(s) including at least one carbon atom and
at least one
non-hydrogen atom, e.g., methanol, ethanol, methylamine, and/or ethylamine.
100371 The
term "hydrocarbon" refers to an organic compound that includes primarily, if
not exclusively, the elements hydrogen and carbon. Hydrocarbons may also
include other
elements, such as, but not limited to, halogens, metallic elements, nitrogen,
oxygen, and/or
sulfur. Hydrocarbons generally fall into two classes: aliphatic, or
straight chain
hydrocarbons, and cyclic, or closed ring hydrocarbons, including cyclic
terpenes. Examples
of hydrocarbon-containing materials include any form of natural gas, oil,
coal, and bitumen.
[NA The
term "hydrocarbon diluent" refers to any substance containing one or more
hydrocarbon compounds and/or substituted hydrocarbon compounds, which is
suitable for
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use for diluting a hydrocarbon in the practice of the invention. For example,
a tail gas stream
containing hydrocarbons may be an added diluent for natural gas.
10039] The term "hydrocarbon stream" refers to a hydrocarbon or mixtures
of
hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may
include a
.. hydrocarbon or mixtures of hydrocarbons that are gases or liquids at
formation conditions, at
processing conditions or at ambient conditions (15 C and 1 atm pressure).
Hydrocarbon
fluids may include, for example, oil, natural gas, coalbed methane, shale oil,
pyrolysis oil,
pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that arc in
a gaseous or
liquid state
10040] The term "light hydrocarbons" refer to hydrocarbons having carbon
numbers in a
range from 1 to 5.
100411 The term "natural gas" refers to a multi-component gas obtained
from a crude oil
well (associated gas) or from a subterranean gas-bearing formation (non-
associated gas). The
composition and pressure of natural gas can vary significantly. A typical
natural gas stream
contains methane (Cl) as a significant component. Raw natural gas may also
contain ethane
(C2), higher molecular weight hydrocarbons, acid gases (such as carbon
dioxide, hydrogen
sulfide, carbonyl sulfide, carbon disulfide, and mercaptans), and minor
amounts of
contaminants such as water, nitrogen, iron sulfide, wax, and crude oil. As
used herein,
natural gas includes gas resulting from the regasification of a liquefied
natural gas, which has
been purified to remove contaminates, such as water, acid gases, and most of
the higher
molecular weight hydrocarbons.
10042] The term "high quality gas" refers to a gas that has undergone
natural gas
processing to separate various hydrocarbons and fluids from a raw natural gas.
Also referred
to as pipeline quality dry natural gas.
100431 The term "raw natural gas" refers to a gas that is included of
methane, but may
also include numerous other light hydrocarbons including ethane, propane, and
butanes.
Higher molecular weight hydrocarbons, including pentanes, hexanes, and
impurities like
benzene may also be present in small amounts. Furthermore, raw natural gas may
contain
amounts of non-hydrocarbon impurities, such as nitrogen, hydrogen sulfide,
carbon dioxide,
and traces of helium, carbonyl sulfide, various mercaptans, and water.
10044] The term "oil and gas reservoir" refers to a well or reservoir
that is a subsurface
zone that produces oil and/or gas and lacks communication other reservoirs. As
used in the
claims, "oil and gas well" and "oil and gas reservoir" are interchangeable.
100451 The term "reservoir" refers to a formation or a portion of a
formation that includes
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sufficient permeability and porosity to hold and transmit fluids, such as
hydrocarbons or
water.
Overview
10046]
Embodiments of the present disclosure provide a method and system for
producing liquid hydrocarbons from unpurified, raw natural gas while
generating power.
More specifically, various embodiments may provide a raw hydrocarbon gas
stream
converted in a reactor, at least in part, to a higher molecular weight
hydrocarbons stream.
Thc reactor is endothermic and the heat supplied to the reaction may be
generated in other
units within the system. The separation of the higher molecular weight
hydrocarbons stream
may yield a liquid hydrocarbons stream and a tail gas stream where at least a
portion of the
tail gas may be combusted and utilized for power generation.
100471 Raw
natural gas recovered at a well-head usually contains impurities and
contaminants including water vapor, hydrogen sulfide, carbon dioxide,
nitrogen, and other
compounds. However, most techniques for converting light hydrocarbons into
aromatic, or
heavy hydrocarbons, utilize a feedstock of purified hydrocarbons having 2 to 5
carbon atoms
per molecule. Some of
the methods for purification may include hydrogenation,
dehydrogenation, sulfur, and acid gas removal techniques, among other
processes, to remove
the aforementioned impurities and contaminants. Thus, the purified hydrocarbon
feed
utilized in the conventional production of aromatic hydrocarbons usually
includes propane,
propylene, butanes, butylenes, with unsaturated compounds being preferred in
many
processes. Further, specific hydrocarbon reactants can be separated from the
purified stream
by fractionation. The resulting gaseous hydrocarbons may then be recycled or
transported for
further processing or commercialization.
100481
However, in remote locations, the appropriate infrastructures may not exist to
purify and fractionate the raw natural gas before it can be used. Thus, the
recovery of raw
natural gas may not outweigh the cost to implement the necessary facilities to
remove, purify,
and transport the natural gas from remote locations. Thus, the raw natural gas
may be burned
or flared as a byproduct of oil production. Unfortunately, flaring wastes the
energy content
of the gaseous hydrocarbons. Furthermore, flaring can pose a hazard to human
health due to
constituents that may be present in the natural gas, such as sulfur compounds.
100491 Fig. 1
is an illustration of an oil and gas well reservoir 100 including trapped oil
and gas within rock formations. As shown in Fig. 1, an oil and gas well
reservoir 100 can be
a subsurface pool of hydrocarbons contained in porous sedimentary rock 102. A
layer of
impermeable rock formations, termed cap rock 104, may prevent the escape of
the naturally
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occurring hydrocarbons into overlying sediment and rock formations 107 (the
overburden).
Various recovery methods may be implemented to extract and recover both the
oil and gas
hydrocarbons. During recovery, the oil and gas reservoir 100 may produce the
crude oil and
raw natural gas along with other liquid, gaseous, and solid hydrocarbons.
[00501 A hydrocarbon stream 106 can be produced from the reservoir 102,
which may
include gas, oil, water, and any combinations thereof. The hydrocarbon stream
106 can be
flowed into a gas-oil separator 108, where the raw natural gas may be
processed for the
removal of an oil stream 110 including oil and other liquids. An overhead gas
stream 114
from the gas-oil separator 108 may be further processed in a reactor 116.
[00511 The liquid/gas mixture stream 118 generated in the reactor 116 may
flow to a
separator 120 where a bottoms liquid stream 122 can be combined with the oil
stream 110. A
tail gas stream 124 may be produced overhead and later combustcd, for example,
in a gas
turbine generator 126, to generate power. In some embodiments, the pressure in
the reservoir
102 can be maintained by recycling a portion of the tail gas 124 back into the
reservoir 100,
.. via a compressor 128, to maintain the pressure of a gas cap located within
the reservoir 100.
The tail gas hydrogen content may be relatively high and processes known to
those skilled in
the art can be used to separate the tail gas into a hydrogen rich stream and
hydrogen poor
stream. Accordingly, the hydrogen poor tail gas can be reinjected via
compressor 128, while
the hydrogen rich stream can be used as fuel or recycled, as required.
[00521 Fig. 2 is a block diagram of a system 200 for producing a higher
molecular weight
hydrocarbons product. As shown in Fig. 2, a raw hydrocarbon 202 may be
produced from a
reservoir and may flow into a production separator 204. In some embodiments,
the raw
hydrocarbon 202 may contain crude oil and raw natural gas along with water,
trace organic
compounds, trace metals, and other entrained liquids and solids. A crude oil
stream 206 can
be taken from the bottom of the separator 204. The crude oil stream 206 can be
directed to a
field crude stabilizer 208, where water, light hydrocarbons, and gas
contaminants are boiled
off to produce a stabilized crude oil liquid stream 210. As shown in Fig. 2,
an overhead gas
stream 212 from the field crude stabilizer 208 may be directed to a reactor
214.
100531 A raw natural gas stream 216 can be taken from the top of the
separator 204 and
combined with the overhead gas stream 212 before being flowed into the reactor
214. In
various embodiments, the stream 216 may include methane, ethane, propane,
butanes,
nitrogen, carbon dioxide, and hydrogen, among other components. Within the
reactor 214,
conversion reactions may enable the conversion of lower molecular weight
hydrocarbons in
the raw natural gas to higher molecular weight hydrocarbons. In some
embodiments, the
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lower molecular weight hydrocarbons may include methane and C2 to C5+
hydrocarbons and
the higher molecular weight hydrocarbons may include C6 to C9 aromatics. In
some
examples, the overhead gas stream 212 may include sulfur compounds, such as
mercaptans,
sulfides, and other organosulfur compounds, in addition to hydrogen sulfide
(H2S). The
organosulfur compounds may be at least partially converted in the reactor,
forming further
amounts of H2S.
liM541 A stream 218 containing higher molecular weight hydrocarbons may
flow from
the reactor 214 and into a liquid separator 220. As shown in Fig. 2, the
liquid separator 220
may separate the higher molecular weight hydrocarbons containing stream 218
into a tail gas
stream 222 and a liquid hydrocarbons stream 224. The product value and
transportability of a
hydrocarbons stream in liquid form may be enhanced since liquid hydrocarbons
can achieve a
higher reduction in volume than hydrocarbons in gas form. Thus, it may be more
cost
effective to recover the natural gas and convert it into a liquid hydrocarbons
stream, instead
of flaring the natural gas, since it can now be transported by methods other
than pipelines.
100551 To reduce the volatility of the liquid hydrocarbons stream 224
during
transportation, the liquid hydrocarbons stream 224 may be subjected to liquid
stabilization.
A liquid stabilizer 226 may operate at a low pressure to remove any volatile
hydrocarbons
and other gaseous contaminants within the liquid hydrocarbons stream 224 to
produce a
stabilized liquid hydrocarbons stream 228. As shown in Fig. 2, the stabilized
liquid
hydrocarbons stream 228 and the stabilized crude oil liquid stream 210 may
merge together
to form a liquid hydrocarbons product stream 230.
10056] If the overhead gas stream 212 used as the feed contains
organosulfur compounds,
H2S, or both, the resulting tail gas stream 222 may be treated to reduce or
remove the H2S,
for example, if the concentration is greater than about 10 ppm, greater than
1000 ppm, or
greater than 1 %, depending on the sensitivity of the environment to SOx's
formed from
combusting the H2S. The H2S can be removed by an adsorption column, a Claus
process, a
counter-current separation column, or any number of other techniques. If
removal of the H2S
is not convenient, for example, due to the remoteness of the site, treating
the combustion
exhaust to remove SOS's may be performed. This could be done by passing the
exhaust gas
.. through a water scrubbing column.
100571 The tail gas stream 222 may be utilized for on-site generation of
power to turn a
power generator 232, where power may be generated and used by those in remote
areas with
limited access to power grids. This type of distributed power generation may
be attractive
since it can provide electricity that may be more reliable, more efficient,
and cheaper than
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purchasing power from a centralized utility. Distributed power generation may
also allow for
increased local control over an electricity supply in remote areas, as well
as, possibly
lowering electricity losses during transmission. Additionally, the tail gas
stream 222 may be
used in heat integration to supply energy to the reactor 214. In some
embodiments, the power
generator may include a gas turbine or combustion engine.
100581 The block diagram of Fig. 2 is not intended to indicate that the
gas system 200 is
to include all of the components shown in Fig. 2. Further, any number of
additional
components may be included within the method of producing a higher molecular
weight
hydrocarbons product. The system 200 may include any suitable types of
heaters, chillers,
.. condensers, pumps, compressors, other types of separation and/or
fractionation equipment,
among others, including any desirable purification steps prior to introducing
the gas streams
216 and 212 into reactor 214. For example, the system 200 may include a
suitable device or
structure for condensing at least a portion of the gas streams 216 and/or 212,
e.g., a pressure
expansion device, an external refrigeration system, etc., prior to
introduction into the reactor
.. 214. Condensing in this way may create a liquid stream comprising higher
molecular weight
hydrocarbons and a gas stream comprising methane and other light components
(e.g.,
nitrogen, helium, carbon dioxide, etc.). The liquid stream may be vaporized
and introduced
into the reactor 214 as feedstock, while the gas stream may be reinjected into
the ground or
used for another purpose. Those of skill in the art will recognize that this
technique may be
utilized to variably control the composition of the tail stream, and therefore
the amount of co-
produced power that may be generated.
10059] Fig. 3 is a simplified process flow diagram 300 for a natural gas
liquid recovery
and stabilization unit including a distillation column. The raw natural gas
stream 302 may
include methane and lower molecular weight hydrocarbons, for example, C2 to
CS+
hydrocarbons. The pressure of a raw natural gas stream 302 may be decreased by
flashing
the raw natural gas stream 302 across a valve 303, generating a low-pressure
stream 304.
The low-pressure stream 304 may be warmed in a product chiller 305 and heated
in a reactor
feed heater 306 to form a warm gas stream 312. The warm gas stream 312 can be
further
heated, for example, to operating temperatures of about 510 C (about 950 F)
to about
.. 600 C (about 1100 F) in a furnace heater 314 to form a reactor feed gas
315 that is fed to the
reactor 308. The reactor feed gas 315 may undergo conversion reactions to form
higher
molecular weight hydrocarbons within the reactor 308. In some embodiments, the
reactor
feed gas 315 may be at a pressure range of about 280 KPa (about 40 psia) to
about 480 KPa
(about 70 psia). The pressure may be increased before entering the reactor
308, for example,
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by a compressor (not shown). A gaseous diluent, such as methane, may be
blended with the
raw natural gas stream 302 to reduce the formation of a byproduct, coke, which
tends to
accumulate on the catalyst pores and lower the reaction efficacy.
10060] Any number of types of reactor 308 may be used, including a
catalytic membrane
reactor, a fixed-bed catalyst reactor, continuous catalytic regeneration
reactor, or a fluidized
bed reactor. The type of reactor utilized may depend on feed compositions and
feed rates,
conversion reaction temperatures, yield compositions, among other input and
output factors.
Moreover, the reaction rates and production yields may be enhanced by the use
of a selective
catalyst for the optimization of reaction conditions.
100611 The catalyst can include at least one metal component on an
inorganic support,
such as amorphous silica, or alumina. The inorganic support may be a porous
material such
as a micro-porous crystalline material or a meso-porous material.
Additionally, suitable
molecular sieves may be utilized in the present catalyst and may include at
least one medium
pore molecular sieve having a Constraint Index of 2-12 (as defined in U.S.
Patent No.
4,016,218). Examples of such medium pore molecular sieves include ZSM-5, ZSM-
11, ZSM-
12, ZSM-22, ZSM-23, ZSM-35, ZSM-48, MCM-22 and MCM-49 and mixtures and
intermediates thereof. ZSM-5 is described in detail in U.S. Patent Nos.
3,702,886 and Re.
29,948. ZSM-11 is described in detail in U.S. Patent No. 3,709,979. A ZSM-
5/ZSM-11
intermediate structure is described in U.S. Patent No. 4,229,424. ZSM-12 is
described in U.S.
Patent No. 3,832,449. ZSM-22 is described in U.S. Patent No. 4,556,477. ZSM-23
is described
in U.S. Patent No. 4,076,842. ZSM-35 is described in U.S. Patent No.
4,016,245. ZSM-48 is
more particularly described in U.S. Patent No. 4,234,231.
100621 The metal component of the catalyst may be present in an amount of
at least 0.1
wt. %, such as from 0.1 to 5 wt. %, of the overall catalyst. The metal
component may include
one or more neutral metals selected from Groups 3 to 13 of the Periodic Table
of the
Elements, such as Ga, In, Zn, Cu, Re, Mo, W, La, Fe, Ag, Pt, Pd, and/or one or
more oxides,
sulfides and/or carbides of these metals. The metal component can be provided
on the catalyst
in any known manner, for example by impregnation or ion exchange of the
molecular sieve
with a solution of a compound of the relevant metal, followed by conversion of
the metal
compound to the desired form, namely neutral metal, oxide, sulfide and/or
carbide. Part or all
of the metal may also be present in a crystalline framework of the molecular
sieve.
[00631 In a preferred embodiment, a bifunctional catalyst may be selected
from the group
consisting of Ga and/or In-modified ZSM-5 type zeolites, such as Ga and/or In-
impregnated
H-ZSM-5, Ga and/or In-exchanged H-ZSM-5, H-gallosilicate of ZSM-5 type
structure and
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H-galloaluminosilicate of ZSM-5 type structure. These zeolites can also be
prepared by
methods known in the prior art.
10064j For example, the bifunctional catalyst may contain tetrahedral
aluminum or
gallium, which is present in the zeolite framework or lattice. The
bifunctional catalyst may
also contain octahedral gallium or indium, which is not present in the zeolite
framework, but
present in the zeolite channels in close vicinity to the zeolitic protonic
acid sites that may be
attributed to the presence of tetrahedral aluminum and gallium in the
catalyst. The
tetrahedral or framework of Al or Ga can be responsible for the acid function
of the catalyst
and octahedral or non-framework Ga or In may be responsible for the
dehydrogenation
function of the catalyst. In a preferred embodiment, the bifunctional catalyst
may include H-
galloaluminosilicate of ZSM-5 type structure having framework (tetrahedral)
Si/A1 and Si/Ga
mole ratios of about 10:1 to 100:1 and 15:1 to 150:1, respectively, and non-
framework
(octahedral) Ga of about 0.5 to 0 wt. %.
100651 In addition to the molecular sieve and hydrogenation component,
the catalyst may
be composited with other materials, which may be resistant to the temperatures
and other
conditions employed in the conversion reaction. Such other materials can
include active and
inactive materials and synthetic or naturally occurring zeolites as well as
inorganic materials
such as clays and/or oxides such as alumina, silica, silica-alumina, zirconia,
titania, magnesia
or mixtures of these and other oxides. The latter may be either naturally
occurring or in the
form of gelatinous precipitates or gels including mixtures of silica and metal
oxides. Clays
may also be included with the oxide type binders to modify the mechanical
properties of the
catalyst or to assist in its manufacture. Use of a material in conjunction
with the molecular
sieve, i.e., combined therewith or present during its synthesis, which itself
is catalytically
active may change the conversion and/or selectivity of the catalyst.
10066j Additionally, inactive materials may serve as diluents to control
the amount of
conversion so that products can be obtained without employing other means for
controlling
the rate of reaction. These materials may be incorporated into naturally-
occurring clays, e.g.,
bentonite and kaolin, to improve the crush strength of the catalyst under
commercial
operating conditions and function as binders or matrices for the catalyst. The
relative
proportions of molecular sieve and inorganic oxide matrix may vary, with the
sieve content
ranging from about 1 to about 90 percent by weight and more usually,
particularly, when the
composite is prepared in the form of beads, in the range of about 2 to about
80 weight percent
of the composite.
[00671 The product of the conversion reactions in the reactor 308 may
include a higher
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molecular weight hydrocarbons stream 316, e.g., including C6 to C9 aromatics,
and other
entrained solid and liquid hydrocarbons. The higher molecular weight
hydrocarbons stream
316 may be cooled upon exiting the reactor 308 by an air cooler 318. For
initial liquids
recovery, the higher molecular weight hydrocarbons stream 316 may further be
chilled to a
temperature range of about 10 C (50 F) to about 26 C (80 F) by exchanging
heat with the
low-pressure stream 304 in the product chiller 305. The chilled higher
molecular weight
hydrocarbons stream 320 may then flow into a gas liquid separator 322 for the
initial
recovery of liquid hydrocarbons. During separation, a tail gas stream 324 may
be produced
overhead and a liquid hydrocarbons stream 326 may be produced as a bottoms
stream.
[00681 The tail gas stream 324 can be compressed in a tail gas compressor
328 and
chilled in a heat exchanger 330 to remove the heat of compression. From the
heat exchanger
330, the tail gas 324 may be sent to a distillation column 332. An overhead
gas stream from
the distillation column 332 may be chilled in a refrigeration cycle 334, and
returned to the
distillation column 332 as a reflux stream 335. A liquid stream 336 can be
taken from the
bottom of the distillation column 332 at a relatively high pressure (e.g. 300
psia). A portion
of the liquid stream 336 may be passed through a reboiler 340 and returned as
a vapor 342 to
the column 332. The remainder of the liquid stream 336 can be combined with
the liquid
hydrocarbons stream 326 from the two-phase separator 322.
[0069] A product gas stream 338 taken from the overhead of the
distillation column 332
can be heated against the hot tail gas stream from the compressor 328 forming
a fuel gas
stream 346. The fuel gas stream 346 may include methane, ethane, as well as
non-
hydrocarbon gases such as hydrogen, carbon dioxide, hydrogen sulfide, and
nitrogen. The
fuel gas stream 346 can be burned in a combustor 344 to power a gas turbine
generator 356.
[00701 A portion of the fuel gas stream 346 can be sent to a pressure
maintenance system
347 to be re-injected into the reservoir 102 (Fig. 1) to maintain the pressure
of a gas cap
located within the reservoir 102 or recycled to the front to mix with the
inlet feed gas.
Likewise, as stated earlier the fuel gas may be divided into hydrogen rich and
hydrogen poor
streams, so that only the hydrogen poor stream is reinjected, if required.
Further, the fuel gas
stream 346 may be used to supply heat to the reactor 308, for example, by
being combusted
in a burner to heat the stream 346 in the furnace heater 314.
100711 In the gas turbine generator 356, an air compressor 348 can
compress an air
stream taken from the atmosphere 350, and feed the compressed stream to the
combustor 344.
The hot gas stream 352 from the combustion is flowed through a turbine
expander 354 to turn
a shaft 355. The shaft 355 can provide the power to turn the air compressor
348, closing the
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Brayton cycle. Further, the shaft 355 can be used to drive the generator 356,
providing
electricity that can be used on-site, placed on a power grid, or both. The gas
turbine
generator 356 may burn up to 1% hydrogen sulfide in the hot gas stream 352. If
desired, a
gas treatment system can be added to remove at least a portion of the hydrogen
sulfide, or
other impurities, to generate acceptable gas turbine performance or lower
exhaust pollutants.
100721 After flowing through the turbine expander 354, the pressure of a
hot gas stream
352 is lowered, forming an exhaust 358. The heat in the exhaust 358 may be
used in other
processes in the facility. For example, a portion of the exhaust 358 can be
used to heat the
reactor feed gas 315 in the furnace heater 314, before being released to the
atmosphere 350.
This may be implemented, for example, by flowing the warm gas stream 312
through a tube
bundle in a heat recovery unit placed at the end of the expander turbine 354.
As described
herein, the furnace heater 314 is not limited to using the exhaust 358, but
may be heated by a
burner that combusts a portion of the fuel gas stream 346. Further, the
reactor 308 may also
contain a tube bundle to maintain a reasonable isothermal reactor. A fluid
from the reactor
308 may be pulled and re-injected into the furnace heater 314 and into
multiple points of heat
inputs within the reactor 308. The tube bundle of the reactor 308 may be
located on the
outside of the reactor 308 and heated by an external burner.
10073] Another portion of the exhaust 358 may be used to heat a heat
exchange fluid in a
heat exchanger 360, before being released to the atmosphere 350. A hot fluid
362 can be
used to heat any number of other systems, as described herein. The resulting
cool fluid 364
can then be returned to the heat exchanger 360 to close the cycle. In
addition, a convective
section the furnace heater 314 could be used to supply the heat source from
stream 362.
100741 The gas turbine generator may operate on the same concept as
larger centralized
gas turbine generators as used in many processing facilities. However, instead
of being
located in a centralized plant, the gas turbine generator may be located in
close proximity to
where the electricity being generated can be used. Thus, the tail gas may
provide power to
remote locations without a substantial power generation system making small
electrical grids
possible, or increasing the capacity of existing electrical grids.
100751 The liquid hydrocarbons stream 326 from the two-phase separator
322, combined
with the liquid stream 336 from the distillation column 322, forming a
combined stream 368,
can be flowed into a stabilizer vessel 366, for example, operating in a
pressure range of about
207 KPa (about 30 psia) to about 414 KPa (about 60 psia). The combined stream
368 may
include a liquid hydrocarbons mixture of higher molecular weight hydrocarbons
with lesser
amounts of light hydrocarbons and other gases. A reboiler 370 can be used to
heat the liquid
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in the stabilizer vessel 366, for example, with heat from the hot fluid 362.
The heat applied
to the stabilizer vessel 366 strips the light hydrocarbons from the combined
stream 366,
forming a liquid product 372 that meets vapor pressure specifications for
transportation. A
small quantity of overhead vapor 374 from the stabilizer vessel 366 may be
sent to a flare
376, for example, if recovery and recompression is not economical. The liquid
product 372
may be sold as a separate product, or may be mixed into a crude oil stream
FM761 The process flow diagram of Fig. 3 is not intended to indicate
that the system 300
is to include all of the components shown in Fig. 3. Further, any number of
additional
components may be included in the system 300. For example, the system 300 may
include
any suitable types of heaters, chillers, condensers, pumps, compressors, other
types of
separation and/or fractionation equipment, valves, pumps, pressure-measuring
devices, or
temperature-measuring device, among others.
10077j Fig. 4 is a process flow diagram 400 for a natural gas liquid
recovery and
stabilization unit including a crude or condensate wash. Like numbered items
are as
described with respect to Fig. 3. Although similar to Fig. 3, the system in
Fig. 4 washes the
tail gas stream 324 with crude oil 402 to remove the liquid hydrocarbons,
resulting in crude
oil or condensate product 404 that includes the liquid hydrocarbons.
[0078] To perform the wash, the tail gas stream 324 if fed into the
bottom of a crude
wash column 406. The crude oil 402 is fed into the top of the crude wash
column 406,
solubilizing the higher molecular weight hydrocarbons in a counter current
extraction. The
crude oil 402 and solubilizcd hydrocarbons arc recovered as a bottom liquids
stream 408.
The crude oil 402 for the crude wash may include a produced crude oil, or any
other available
hydrocarbon stream such as a stabilized condensate.
[00791 As shown in Fig. 4, the liquid hydrocarbons stream 326 from the
two-phase
separator 322 and a liquid bottoms stream 408 from the crude wash column 406
may flow
into a stabilizer vessel 366 as a combined stream 410. As described with
respect to Fig. 3,
the light hydrocarbons and trace gases can be stripped from the combined
stream 410 to
produce a crude oil product 404 that contains the higher molecular weight
hydrocarbons
formed in the process.
100801 A vapor stream 412 can be taken from the top of the crude wash
column 406 and
flowed into a multi-stage compressor unit 414. The multi-stage compressor unit
414 can be
used to compensate for low pressures that may be used during the crude oil
wash. In the
multi-stage compressor unit 414, a first compressor 416 may increase the
pressure of the
vapor stream 412 from a pressure between about 280 KPa (about 40 psia) and
about 480 KPa
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(about 70 psia) up to a pressure between about 670 KPa (about 100 psia) and
about 3500 KPa
(about 500 psia). An inter-cooler 418 may be used to remove the heat of
compression from
the vapor stream, before it is fed to a second compressor 420. The second
compressor 420
may further increase the pressure to about 3500 KPa (about 500 psia) or
higher, to produce a
high pressure fuel gas 422 that can be combusted in the combustor 344, as
described with
respect to Fig. 3. As for the system 300 in Fig. 3, a portion of the high-
pressure fuel gas 422
can be sent to a pressure maintenance system 347 or recycled to the feed
stream. Further, a
portion may be combusted in a burner to heat the furnace heater 314, instead
of, or in
addition to, the exhaust 358 from the gas turbine generator.
100811 The process flow diagram of Fig. 4 is not intended to indicate that
the system 400
is to include all of the components shown in Fig. 4. Further, any number of
additional
components may be included within the system 400. For example, the system 400
may
include any suitable types of heaters, chillers, condensers, pumps,
compressors, other types of
separation and/or fractionation equipment, valves, pumps, pressure-measuring
devices, or
temperature-measuring device, among others.
100821 Fig. 5 is a process flow diagram 500 for a natural gas liquid
recovery and
stabilization unit that recovers hydrogen from the tail gas. Like numbered
items are as
described with respect to Fig. 3. Although similar to Fig. 3, Fig. 5
incorporates a hydrogen
recovery system to separate hydrogen from the tail gas stream.
10083j As discussed with respect to Fig. 3, a fuel gas stream 346 may be
formed in a
process that creates higher molecular weight hydrocarbons. The fuel gas stream
346
primarily includes methane, but may also include other gases, such as hydrogen
formed in the
reaction. The hydrogen may provide a useful feedstock, for example, to place a
chemical
plant near the site of the well. Accordingly, recovery of the hydrogen can
increase the value
of the products produced.
[0084] To recover the hydrogen, a portion of fuel gas stream 346 may be
redirected to a
hydrogen separation unit 502, for example, based on membrane technology
although any
number of technologies may be used. A membrane separation provides a simpler
technology,
which is more suited to use in remote locations. A membrane separation is
generally based
on the difference between in permeation rates between the hydrogen and
impurities across a
gas-permeable membrane. Hydrogen, which has a higher permeability, may diffuse
through
the membrane from the high-pressure side to the low-pressure side. Before
entering the
hydrogen separation unit 502, the fuel gas stream 346 may be cooled using an
air cooler 504
to produce a cool gas stream 506. A low-pressure, hydrogen-enriched stream 508
that may
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be formed from the low-pressure side of the membrane may be compressed in a
multi-stage
compressor unit 510 to produce compressed hydrogen 512. The compressed
hydrogen 512
can be used at the site for chemical reactions, sold to market, or recombined
with the fuel gas
stream 346, for example, to enhance the BTU content of the fuel gas. A
hydrogen-depleted
stream 514 may be mixed with the raw natural gas stream 302 for additional
conversion
within a reactor 308 or reinjected into the reservoir, as required.
[iM851 The process flow diagram of Fig. 5 is not intended to indicate
that the system 500
is to include all of the components shown in Fig. 5. Further, any number of
additional
components may be included within the system 500. For example, the system 500
may
include any suitable types of heaters, chillers, condensers, pumps,
compressors, other types of
separation and/or fractionation equipment, valves, pumps, pressure-measuring
devices, or
temperature-measuring device, among others.
10086j Fig. 6 is a flow block diagram of a method 600 for producing an
aromatic
hydrocarbon. According to embodiments described herein, the method may produce
an
aromatic hydrocarbon and generate electricity from a tail gas stream.
100871 The method 600 begins at block 602, when a first stream including
raw natural
gas is fed into an aromatic reactor. At block 604, the first stream is
converted, at least in part,
to a second stream including the aromatic hydrocarbon. At block 606, the
second stream is
separated into a tail gas stream and a liquid aromatic hydrocarbon stream. At
block 608, at
least a portion of the tail gas stream is burned in a gas turbine to generate
electricity.
Simulations
10088] Simulations were conducted to test the operation of the system
described herein.
The following Table 1 provides simulated data at various stages of the system
for producing a
higher molecular weight hydrocarbons product. In particular, the case studies
included the
flow rate, the volumetric flow, the molecular weight, and the composition of
the reactor feed
for the reactor feed, the liquid hydrocarbons product, the fuel gas, and the
flare gas. Further,
for various stages of the system, a particular catalyst was provided based on
conversion rates
measured against the varying flow rates, the volumetric flows, the molecular
weights, and the
compositions of the reactor feed.
100891 As shown in Table 1, Case 1 and Case 2 represent the use of Catalyst
1 during
simulation. Case 1 depicts separation of a tail gas stream from a liquid
hydrocarbons stream
using a liquid separator or a demethanizer. Conversely, Case 2 depicts
separation of a tail gas
stream from a liquids hydrocarbons stream using a crude wash column.
Particularly, Figure 3
of the present disclosure illustrates Case 1 and Figure 4 of the present
disclosure illustrates
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Case 2.
100901 Case 3 represents a simulation with little to no conversion using
Catalyst 2.
Moreover, Cases 4 and 5 depict conversion using Catalyst 3. Additionally,
Figure 5 also
illustrates Case 5 where recovered hydrogen is remixed with a fuel gas stream,
where the
combined streams are feed to a gas turbine for power production.
100911 While the present techniques may be susceptible to various
modifications and
alternative forms, the embodiments discussed above have been shown only by way
of
example. However, it should again be understood that the techniques is not
intended to be
limited to the particular embodiments disclosed herein. Indeed, the present
techniques include
all alternatives, modifications, and equivalents falling within the true
spirit and scope of the
appended claims.
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100921 Table 1: Simulations of Hydrocarbon Conversion
Case 1 2 3 4 5
Catalyst 1 Catalyst 1 Catalyst 2 Catalyst 3 Catalyst 3
Demethanizer Crude Wash Recycle
Reactor Feed
Mass Rate (kg/hr) 74,886 74,886 74,886 55,333 131,988
Std. Vol. Flow (m3/hr) 58,994 58,994 58,994 58,994 146,304
Mol Weight (g/gmol) 30.07 30.07 30.07 22.22 21.27
Composition (mol%)
N2 2.70 2.70 2.70 1.70 1.91
CO2 0.75 0.75 0.75 0.60 0.69
H2 0.00 0.00 0.00 0.00 1.92
Cl 44.80 44.80 44.80 73.60 73.84
C2 23.10 23.10 23.10 13.80 12.86
C3 18.00 18.00 18.00 6.00 5.25
C4 7.30 7.30 7.30 2.60 2.14
C5-C7 3.35 3.35 3.35 1.70 1.38
Liquid Product
Mass Rate (kg/hr) 35,101 33,461 35,975 22,378 50,846
Volume (m3/hr) 40.9 38.8 41.9 25.9 58.7
Mol Weight (g/gmol) 94.60 159.7 94.50 91.96 91.76
API 52.0 79.78 52.0 52.1 52.1
TVP (bara) 0.72 0.72 0.72 0.72 0.73
Blended w/
Composition (mol%) Crude
C2 0.52 0.89 0.54 0.66 0.65
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Case 1 2 3 4 5
Catalyst 1 Catalyst 1 Catalyst 2 Catalyst 3 Catalyst 3
C3 2.14 0.02 2.11 0.74 0.70
C4 1.07 0.78 1.05 0.40 0.36
C5-C7 1.52 0.97 1.48 1.01 0.89
Benzene 23.91 13.27 23.3 31.96 32.55
Toluene 23.19 12.74 25.06 31.35 31.90
Ethylbenzene 14.2 7.81 13.85 10.51 10.10
0-xylene 14.2 7.81 13.85 10.22 9.98
P-xylene 12.19 5.72 11.88 8.99 8.88
1,3,5-Trimethylbenzene 7.05 3.87 6.87 4.09 3.92
Fuel Gas
Mass Rate (kg/hr) 39,628 41,294 38,759 32,905 59,686
Std. Vol. Flow (m3/hr) 83,771 82,591 83,771 75,512 155,743
Mol Weight (g/gmol) 11.24 11.76 10.90 10.28 9.06
Composition (mol%)
N2 1.91 1.91 1.89 1.32 1.28
CO2 0.52 0.52 0.52 0.46 0.45
H2 52.84 50.97 55.06 51.70 58.33
Cl 33.43 34.99 31.32 39.98 34.87
C2 7.37 7.33 7.31 4.95 3.91
C3 3.40 3.31 3.37 1.27 0.95
C4 0.40 0.37 0.40 0.17 0.12
Case 1 2 3 4 5
Catalyst 1 Catalyst 1 Catalyst 2 Catalyst 3 Catalyst 3
C5-C7 0.08 0.50 0.08 0.06 0.04
Benzene 0.05 0.02 0.05 0.08 0.05
Toluene 0.0001 0 0.0002 0.0004 0.0002
Flare
Mass Rate (kg/hr) 157 131 152 49 133
Mol Weight (g/gmol) 25.70 18.89 25.63 18.92 19.46
Composition (mol%)
N2 0.58 1.31 0.61 0.70 0.74
CO2 2.89 1.14 2.96 1.16 1.45
H2 5.44 6.05 10.24 9.77
Cl 38.77 67.26 38.00 71.16 70.1
C2 41.18 12.42 41.34 11.49 12.14
C3 8.86 4.67 8.75 2.88 3.00
C4 0.96 0.57 0.95 0.42 0.42
C5-C7 0.23 0.12 0.23 0.16 0.16
Benzene 0.79 0.67 0.79 1.35 1.63
Toluene 0.20 0.16 0.22 0.36 0.45
21
