Note: Descriptions are shown in the official language in which they were submitted.
x k ,. P~
2174341
WO 95/11739 PCT/US94/12100
1
MEMBRANE AND NON-MEMBRANE SOUR GAS TREATMENT PROCESS
FIELD OF THE INVENTION
The invention relates to processes for removing acid gases from gas streams.
More particularly,
the invention relates to a membrane process, and to combinations of membrane
and non-membrane
processes, for removing hydrogen sulfide and carbon dioxide from gas streams,
such as natural gas.
BACKGROUND OF THE INVENTION
Natural gas provides more than one-fifth of all the primary energy used in the
United States.
Much raw gas is "subquality", that is, it exceeds the pipeline specifications
in nitrogen, carbon dioxide
and/or hydrogen sulfide content.
The best treatment for natural gas right now is no treatment. Raw gas that is
lrnown to be high
in nitrogen content, high in nitrogen plus carbon dioxide content, or high in
hydrogen sulfide content is
usually leh in the ground, because it cannot be extracted and treated
economically with present processing
technology.
There are several aspects to the problem of treating natural gas to bring it
to pipeline
specifications. The first is the removal of impurities, primarily water,
hydrogen sulfide and carbon
dioxide; the second is loss of methane during processing. Processes that
remove hydrogen sulfide and
carbon dioxide may also remove a portion of the methane. Losses of less than
about 3% are nonmally
acceptable; losses of 3-10% may be acceptable if offset by other advantages;
losses above 10% are
normally unacceptable. A third aspect is the fate of the impurities once
removed. Carbon dioxide can be
discharged or reinjected, but hydrogen sulfide, which is toxic even in low
concentrations, must be treated.
If the waste stream containing hydrogen sulfide can be concentrated
sufficiently, it may be passed to a
Claus plant for conversion to sulfur. Waste streams containing low
concentrations must be disposed of
in some other way, such as a redox process of the LO CAT or Stretford type,
for example, or, less
desirably, flaring.
Choice of appropriate treatment is, therefore, not straightforward, and
depends on the feed gas
composition, the size and location of the plant and other variables.
When.natural gas is treated, most plants handling large volumes of sour gas
containing greater
than about 200 ppm hydrogen sulfide use amine-based technology for acid gas
removal. Amines
commonly used include MEA, DEA, DIPA, DGA and MDEA. The plants can remove both
carbon
dioxide and hydrogen sulfide. When the amine solution is spent, the acid gases
are flashed off and the
CA 02174341 2004-04-19
75136=9
solution is regenerated The mxhanicai equipment in an amine plant makes it
susceptible to failure. The
plant includes heaters, aerial coolers, pumps, etc. and requires frequent
quality checks and maintenance,
making operations! reliability probably the weakest feature of the technology.
Amine plants do not sorb mdhane to any signiG~t tent, so methane Loss is not
an issue in this
case. However, the hydnng~-sulGde~ontaining gas stre~tt when the sorbent is
rcgentratod must
still be treated, subjoct to the same constraints as above.
As an alternative to amine sorption, or as a polishing step following any
process, specialized
scavrnging or sulfur t~ecovery processes, such as Sulfa-Scrub, Sulfa-Check,
Chernsweet, Supertron 600,
solid iron sponge or solid zinc oxide may be used for low~volume streams
containing less than about
100 ppm hydrogen sulfide. Many scavengers present substantial disposal
problems, however. In an
increasing number of states, the spent scavenger constitutes toxic waste.
A considerable body of literature exists regarding membrane-based treatment of
natural gas,
mostly using cellulose acetate (CA) membranes to remove carbon dioxide.
Although cellulose aoetatc
membrane platys are designed to remove carbon dioxide, cellulose acetate
merabrarxs also have selectivity
for hydrogas sulfide over methane, sa thty tend to cocxtract small amounts of
hydrogen sulfide. Unless
the raw gas stream cattains very high concattrations of carbon diocide,
however, it is not possible to
reduce a stream containing even modest amounts of hydrogen sulfide to pipeline
specification (usually
4 ppm hydrogen sulfide) without vastly ovaprocessing as far as the carbon
dioxide specification is
concerned. If such ovcrprocessing is performed, large amounts of methane are
lost in the membrane
permeate stream, and this is normally unacceptable.
Only a few of the many literature refenmcex rztating to membrane-based carbon
dioxide treatment
spxifxallydiscuss removal ofhydrogat sulfide in conjunction with the carbon
dioxide. A paper by W.J.
Schell et al. ("Separation of COI Gem Mixtures by Membrane Permeation",
presented at the Gas
Conditioning Conference, Uttiversity of Oklahoma, March 1983) says that "If
the H=S level is low enough,
the membrane system can also be used to melt pipeline specification for this
component without arty
further lrcatmcnt required." The papa shows a case what a cellulose acetate
membrane system can be
used to reach pipeline spxification for carbon dioxide and hydrogen sulfide in
two stages, starting with
a Cecd content of 15% carbon dioxide and 250 ppm hydrogen sulfid and
c, points out that, for high
concsntrationt of hydrogen sulfide, "a much larger number of elements are
required to reduce the H=S
levels to pipeline specification (I/4 grain) than for CO= (3%)." The costs of
membrane trcatrnent are
estimated to be more than 100% highs than conventional amine treatment in this
case.
A report by N.N. Li et al. to the Depa:trrttttt of Energy ("Membrane
Separation Processes in the
" ~ r~
WO 95/11739 2 I 7 4 3 41 PCT/US94/12100
3
Petrochemical Industry", Phase II Final Report, September 1987) examined the
effect of impurities,
including hydrogen sulfide, on the ability of cellulose acetate membranes to
remove carbon dioxide from
natural gas. The reporters found that the membrane performance was not
affected significantly by
hydrogen sulfide alone. However, dramatic loss of membrane permeability was
observed if both hydrogen
sulfide and water vapor were pit in the food. The authors concluded that
"successful use of these CA
based membranes must avoid processing gas which simultaneously has high H20
and H2S concentrations".
Another problem associated with cellulose acetate membranes is water, which is
always present
in raw natural gas streams to some extent, as vapor, entrained liquid, or
both. The gas separation
properties of cellulose acetate membranes are destroyed by contact with liquid
water, so it is normally
necessary to provide pretreatment to knock out any liquid water and to reduce
the relative humidity low
enough that there is no risk of condensation .of water within the membrane
modules on the permeate side.
For example, the above-cited paper by W.J. Schell et al. ("Separation of COZ
from Mixtures by Membrane
Permeation", presented at the Gas Conditioning Conference, University of
Oklahoma, March 1983) points
out that '°Even though membrane systems simultaneously dehydrate while
removing C02, care must be
taken to avoid contacting the membrane with liquid water. Feed gas streams
saturated with water are
normally preheated to at least I 0 ° above the water dew point at the
feed inlet pressure and the pressure
tubes and inlet piping are insulated to prevent condensation."
The above-cited report by N. N. Li et al. ("Membrane Separation Processes in
the Petrochemical
Industry," Phase II Final Report, September 1987) presents data showing the
effect of water vapor on
membrane flux for cellulose acetate membranes, and concludes that "for
relative humidifies of 30% and
higher, the flux decline is large, rapid, and irreversible". E.W. Funk et al.
("Effect of Impurities on
Cellulose Acetate Membrane Performance", Recent Advances in Separation
Techniques - III, AIChE
Symposium Series, 250, Vol 82, 1986) advocate that "Moisture levels up to 20%
RH appear tolerable but
higher levels can cause irreversible membrane compaction".
U.S. Patent 4,130,403 to T.E. Cooley et al. (Removal of HZS and/or COz from a
Light
Hydrocarbon Stream by Use of Gas Permeable Membrane, 1978, Col. 12, Dines 36-
39) states that "It has
been discovered that in order to function effectively, the feed gas to the
cellulose ester membrane should
be substantially water free". A second paper by W.J. Schell et al.
(°'Spiral-Wound Permeators for
Purification and Recovery", Chemical Engineering Progress, October 1982, pages
33-37) confums that
"Liquid water is detrimental to the perfonmance of the membrane, however, so
that the feed gas is
delivered to the membrane system at less than 90% relative humidity."
In other words, although cellulose acetate membranes will permeate water
preferentially over
f , - ~ 17 4 3 41 pCT~594/12100
WO 95/11739 T
4
methane, and hence have the capability to dehydrate the gas stream, care must
be taken to keep the
amounts of water vapor being processed low, and, according to some teachings,
as low as 20-30% relative
humidity.
In light of these limitations, considerable effort has been expended over the
last few years in the
search for membrane materials that would be better able to handle streams
containing carbon dioxide plus
secondary contaminants, notably hydrogen sulfide and water.
For dense polymer membranes, the combined effect of the sorption and diffusion
phenomena
determines the selectivity of the membrane. The balance between mobility, or
diffusion, selectivity and
sorption selectivity is different for glassy and rubbery polymers. In glassy
polymers, the mobility term
is usually dominant, permeability falls with increasing permeant size and
small molecules permeate
preferentially. In rubbery polymers, the sorption term is usually dominant,
permeability increases with
increasing permeant size and large molecules permeate preferentially. Since
both carbon dioxide (3.3 A)
and hydrogen sulfide (3.6 A) have smaller kinetic diameters than methane (3.8
A), and since both carbon
dioxide and hydrogen sulfide are more condensable than methane, both glassy
and rubbery membranes
are selective for the acid gas components over methane. To date, however, most
membrane development
work in this area has focused on glassy materials, of which cellulose acetate
is the most successful
example.
In citing selectivity, it is important to be clear as to how the permeation
data being used have been
measured. It is common to measure the fluxes of different gases separately,
then to calculate selectivity
as the ratio of the pure gas permeabilities. This gives the "ideal"
selectivity for that pair of gases. Pure
gas measurements are more commonly reported than mixed gas experiments,
because pure gas
experiments are much easier to perform. Measuring the permeation data using
gas mixtures, then
calculating the selectivity as the ratio of the gas flu.~ces, gives the actual
selectivity that can be achieved
under real conditions. In gas mixtures that o~tain condensable components, it
is frequently, although not
always, the case that the mixed gas selectivity is lower, and at times
considerably lower, than the ideal
selectivity. The condensable component, which is readily sorbed into the
polymer matrix, swells or, in the
case of a glassy polymer, plasticizes the membrane, thereby reducing its
discriminating capabilities.
A technique for predicting mixed gas performance under real conditions from
pure gas
measurements with airy reliability has not yet been developed. In the case of
gas mixtures such as carbon
dioxidc/methane with other components, the expectation is that the carbon
dioxide at least will have a
swelling or plasticizing effect, thereby changing the membrane permeation
characteristics. This
expectation is borne out by cellulose acetate membranes. For example,
according to a paper by M.D.
~~ ~ ~ ~ r c 21 l 4 3 41 pCT~S94/12100
WO 95/11739 '
Donahue et al. ("Permeation behavior of carbon dioxide-methane mixtures in
cellulose acetate
membranes", Journal of Membrane Science, 42, 197-214, 1989) when measured with
pure gases, the
carbon dioxide permeability of asymmetric cellulose acetate is 9.8 x 10-5
em3/cm2-s-kPa and the methane
permeability is 2.0 x 10~ cm3/cm2~s~kPa, giving an ideal selectivity of about
50. Yet the acfual selectivity
~ 5 obtained with mixed gases is typically in the range 10-20, a factor of 3-5
times lower than the ideal
selectivity. For example, the report to DOE by Norman Li et al., discussed
above, gives carbon
dioxidc/mefhane selxtivities in the range 9-15 for one set of field trials (at
6000-6240 kPa (870-905 psi)
feed pressure) and 12 for another set (at 1483 kPa (200 psig) feed pressure)
with a highly acid feed gas.
The W.J. Schell et al. Chemical Engineering Progress paper, discussed above,
gives carbon
dioxide/methane selectivities of 21 (at 1828-3207 kPa (250-450 psig) feed
pressure) and 23 (at SG20 kPa
(800 prig) feed pressure). Thus, even in mixed gas measurements, a wide spread
of selectivities is
obtained, the spread depending partly on operating conditions. In particular,
the plasticizing or swelling
effect of the carbon dioxide~on the membrane tends to show pressure
dependence, although it is sometimes
hard to distinguish this from other effects, such as the contribution of
secondary condensable components.
The search for improved membranes for removing acid components from gas
streams, although
it has focused primarily on glassy membranes, encompasses several types of
membranes and membrane
materials. A paper by A. Deschamps et al. ("Development of Gaseous Permeation
Membranes adapted
to the Purification of Hydrocarbons", LLF - LLR - Commission A3, Paris, 1989)
describes work with
aromatic polyimides having an intrinsic material selectivity of 80 for carbon
dioxide over methane and
200,000 for water vapor over methane. The paper defines the target
selectivities that the researchers were
aiming for as 50 for carbon dioxide/methane and 200 for water vapor/methane.
The paper, which is
principally directed to dehydration, does not give carbon dioxide/methane
selectivities, except to say that
they were °'gencxally low", even though the experiments were carried
out with pure gas samples. In other
words, despite the high intrinsic selectivity of 80, the lower target value of
50 could not be reached.
British Patent number 1,478,083, to Klass and Landahl, presents a large body
of permeation data
obtained with methane%arbon dioxide/hydrogen sulfide mixed gas streams and
polyamide (nylon 6 and
rrylon 6/6), polyvirryl alcohol (PVA), polyacrylonitrile (PAN) and gelatin
membranes. Some unexpectedly
high selactivities are shown. For the rrylon membranes, carbon dioxide/methane
selectivities of up to 30,
and hydrogen sulfide/methane selectivities up to 60, are reported. The best
carbon dioxide/methane
selectivity is 160, for PAN at a temperature of 30 °C and a feed
pressure of 448 kPa (65 psia); the best
hydrogen sulfide/methane selectivity is 200, for gelatin at the same
conditions. In both cases, however,
the permeability is extremely low: for carbon dioxide through PAN, less than 5
x 10'' Barer and for
~ ,. t~s ,-e., ~
WO 95!11739 ~ ~ ~ PCT/US94/12100
6
hydrogen sulfide through gelatin, less than 3 x 10'' Barrer. These low
permeabilities would make the
transmembrane fluxes miserable for any .practical purposes. It is also unknown
whether the gelatin
membrane, which was plasticized with glycerin, would be stable much above the
modest pressures under
which it was tested.
U.S. Patent 4,561,864, also to Klass and Landahl, incorporates in its text
some of the data
reported in the British patent discussed above. The '864 patent also includes
a table of calculations for
cellulose acetate membranes, showing the relationship between "Figure of
Merit", a quantity used to
express the purity and methane recovery in the residue stream, as a function
of "Flow Rate Factor", a
quantity that appears to be somewhat akin to stage-cut. In performing the
calculations, separation factors
(where the separation factor is the ~ of the carbon dioxide/methane
selectivity and the hydrogen
sulfideJmethane selectivity) of 20 to 120 are assumed. The figures used in the
calculations appear to range
from the low end of the combined carbon dioxide and hydrogen sulfide
selectivides from mixed gas data
to the high end of the combined selectivities calculated from pure gas data.
A paper by D.L. Ellig et al. ("Concentration of Methane from Mixtures with
Carbon Dioxide by
permeation through Polymeric Films", Journal of Membrane Science, 6, 259-263,
1980) summarizes
permeation tests carried out with 12 different commercially available films
and membranes, using a mixed
gas feed containing 60% carbon dioxide, 40% methane, but no hydrogen sulfide
or water vapor. The tests
were carried out at 2,068 kPa (about 300 psi) feed pressure. The results show
selectivities of about 9-27
for cellulose acetate, up to 40 for polyeihersulfone and 20-30 for
polysulfone. One of the membranes
tested was nylon, which, in contradiction to the results reported by Klass and
Landahl, showed essentially
no selectivity at all for carbon dioxide over methane.
The already much-discussed DOE Final Report by N.N. Li et al. contains a
section in which
separation of polar gases from non-polar gases by means of a mixed-matrix,
facilitated transport
membrane is discussed. The membrane consists of a silicone rubber matrix
carrying polyethylene glycol,
which is used to facilitate transport of polar gases, such as hydrogen
sulfide, over non-polar gases, such
as mclhane. In tests on natural gas streams, the membranes exhibited hydrogen
sulfide/methane selectivity
of 25-30 and carbon dioxide/methane selectivity of 7-8, which latter number
was considered too low for
practical carbon dioxide separation. The membrane was also shown to be
physically unstable at feed
pressure above about 1276 kPa (170 psig), which, even if the carbon
dioxidelmethane selectivity were
~iequate, would render it unsuitable for handling raw natural gas streams.
U.S. Patents 4,608,060, to S.
Kulprathipanja, and 4,606,740, to S. Kulprathipanja and S.S. Kulkarni, of Li's
group at UOP, present
additional data using the same type of glycol-laden membranes as discussed in
the DOE report. In this
2174341
~ WO 95/11739 PCT/US94/12100
7
case, however, pure gas tests were performed and ideal hydrogen
sulfideJmethane selectivities as high as
115-185 are quoted. It is interesting to note that these are 4-8 times higher
than the later measured mixed
gas numbers quoted in the DOE report. The same effect obtains for carbon
dioxide, where the pure gas
selectivifies are in the range 21-32 and the mixed gas data give selectivities
of 7-8.
Similar in concept is U.S. Patent 4,737,166, to S.L. Matson et al., which
discloses an immobilized
liquid manbrane typically containing n-methylpyrrolidone or another polar
solvent in cellulose acetate or
any other compatible polymer. The membranes and processes discussed in this
patent are directed to
selective hydrogen sulfide removal, in other words leaving both the methane
and the carbon dioxide behind
in the residue stream. As in the UOP patents, very high hydrogen
sulfide/methane selectivities, in the
range 90-350, are quoted. Only pure gas data are given, however, and the feed
pressure is 793 kPa
( 100 psig). There is no discussion as to how the membranes might behave when
exposed to
multicomponent gas streams and/or high feed pressures. Based on the UOP
teachings, the mixed gas,
high-pressure results might be expected to be not so good.
U.S. Patent 4,781,733, to W.C. Babcock et al., describes results obtained with
an interfacial
composite membrane made by a polycoc~nsation reaction between a diacid-
chloride- terminated silicone
rubber and a diamine. In pure gas experiments at 793 kPa (100 psig), the
membrane exhibited hydrogen
sulfide/methane selectivities up to 47 and carbon dioxide/methane
selectivities up to 50. No mixed gas
or high-pressure data are given.
U.S. Patent 4,493,716, to RH. Swick, reports permeation results obtained with
a composite
manbrane consisting of a polysulfide polymer on a Gorete~c (polytetra-
fluoroethylene) support. Only pure
&'~~ I~'-pressure test cell permeability data are given. Based on the reported
permeabilities, which only
give an upper limit for the methane permeability, the membrane appears to have
a hydrogen
sulfide/mcthane selectivity of at least 19-42 and a carbon dioxide/methane
selectivity of at least 2-6. Some
results show that the carbon dioxide permeability increased after exposure to
hydrogen sulfide, which
might suggest an overall decrease in selectivity if the membrane has become
generally more permeable,
although no methane data that could confirm or refute this are cited.
U.S. Patent 4,963,165, to I. Blume and I. Pinnau reports pure gas, low-
pressure data for a
composite membrane consisting of a polyamide-polyether block copolymer on a
polyamide support.
Hydrogen sulfide/methane selectivities in the range 140-190, and carbon
dioxide/methane selectivities in
the range 18-20, are quoted. Mixod gas data for a stream containing oxygen,
nitrogen, carbon dioxide and
sulfur dioxide are also quoted and discussed in the text, but it is not clear
how these data would compare
with those for methane- or hydrogen-sulfide-containing mixed gas streams.
~, ~: ~~ a- ~ ~~.; 21. 7 4 3 41
WO 95111739 PCT/US94/12100
8
Despite the many and varied research and development efforts that this body of
literature
represents, cellulose acetate membranes, with their attendant advantages and
disadvantages, remain the
only membrane type whose properties in handling acid gas streams under real
gas-field operating
conditions are reasonably well understood, and the only membrane type in
commercial use for removing
acid gas components from methane.
U.S. Patent 4,589,896, to M. Chen et al., exemplifies the type of process that
must be adopted
to remove carbon dioxide and hydrogen sulfide from methane and other
hydrocarbons when working
within the performance limitations of cellulose acetate membranes. The process
is directed at natural gas
streams with a high acid gas content, or at streams from enhanced oil recovery
(EOR) operations, and
consists of a multistage membrane separation, followed by fractionation of the
acid gas components and
multistage flashing to recover the hydrogen sulfide. The acid-gas-depleted
residue stream is also subjected
~ ~~ ~~nent to recover hydrocarbons. The raw gas to be treated typically
contains as much as 80%
or more carbon dioxide, with hydrogen sulfide at the relatively low, few
thousands of ppm level. Despite
the fact that the ratio of the carbon dioxide content to the hydrogen sulfide
content is high (about 400:1),
the raw gas stream must be passed through a minimum of four membrane stages,
arranged in a three-step,
two-stage configuration, to achieve good hydrogen sulfide removal. The goal is
not to bring the raw gas
stream to natural gas pipeline specification, but rather to recover relatively
pure carbon dioxide, free from
hydrogen sulfide, for further use in FOR The target concentration of carbon
dioxide in the treated
hydrocarbon stream is less than 10%, which would, of course, not meet natural
gas pipeline standards.
The methane left in the residue stream after higher hydrocarbon removal is
simply used to strip carbon
dioxide from hydrogen-sulfite-rich solvent in a later part of the separation
process; no methane passes to
a natural gas pipeline. Despite the multistep/multistage membrane arrangement,
in a representative
example, about 7% carbon dioxide is felt in the hydrocarbon residue stream
alter processing, and about
12% hydrocarbon loss into the permeate takes place.
It is n to combine treatment by membranes with treatment by non-membrane
processes.
As a few sample references, the DOE Final Report by N.N. Li et al., Figure 1,
shows such a membrane
system upstream of an absorption unit and a Claus plant. U.S. Patent
4,737,166, to S.L. Matson et al.,
shows an immobilized liquid membrane unit combined with sulfur recovery from
the permeate stream and
methanation of the residue stream. The W.J. Schell et al. paper presented at
the Gas Conditioning
Conference, Figure 6, shows conventional treatment, such as amine absorption,
of the membrane residue
stream. A paper by D.J. Stookey et al. ("Natural Gas Processing with PRISM~
Separators",
Environmental Pro~~ress, August 1984, Vol 3, No. 3, pages 212-214) shows
various figures in which
- 75136-9
CA 02174341 2005-05-17
9
membrane separation is combined with non-membrane treatment
processes. A paper by W.H. Mazur et al. ("Membranes for
Natural Gas Sweetening and COz Enrichment", Chemical
Engineering Progress, October 1982, pages 38-43) shows
several membrane/non-membrane treatment schemes.
In summary, it may be seen that there remains a
need for improved membranes and improved processes for
handling streams containing methane, acid gas components and
water vapor. Such improved membrane processes could, in
turn, be combined with non-membrane treatment techniques to
provide improved "hybrid" processes.
SUMMARY OF THE INVENTION
In one aspect, the invention provides a process
for treating a gas stream comprising hydrogen sulfide and
methane, said process comprising: (a) carrying out a
membrane separation process, comprising: (i) passing said
gas stream across the feed side of a membrane having a feed
side and a permeate side; (ii) withdrawing from said feed
side a residue stream depleted in hydrogen sulfide compared
with said gas stream; (iii) withdrawing from said permeate
side a permeate stream enriched in hydrogen sulfide compared
with said gas stream; said membrane separation process being
characterized in that said membrane, when in use in said
process, exhibits a selectivity for hydrogen sulfide over
methane of at least 35, measured with a mixed gas stream
containing at least hydrogen sulfide and methane, and at a
feed pressure of at least 3,552 kPa (500 psig); and (b)
passing said permeate or residue stream to a non-membrane
process for additional treatment.
The invention provides improved membranes and
improved membrane processes for treating gas streams
75136-9
CA 02174341 2005-05-17
9a
containing hydrogen sulfide, carbon dioxide, water vapor and
methane, particularly natural gas streams. The processes
rely on the availability of two membrane types: one,
cellulose acetate, or a material with similar properties,
characterized by a mixed gas carbon dioxide/methane
selectivity of about 20 and a mixed gas hydrogen
sulfide/methane selectivity of about 25; the other an
improved membrane with a much higher mixed gas hydrogen
sulfide/methane selectivity of at least about 30, 35 or 40
l0 and a mixed gas carbon dioxide/methane selectivity of at
least about 12. These selectivities must be achievable with
gas streams containing at least methane, carbon dioxide and
hydrogen sulfide and at feed pressures of at least 3550 kPa
(500 psig), more preferably 5621 kPa (800 psig), most
preferably 7000 kPa (1,000 psig).
An important aspect of the invention is the
availability of membranes with much higher hydrogen
sulfide/methane selectivities than cellulose acetate. This
provides the flexibility to choose between the membrane with
the higher carbon dioxide/methane selectivity, in treating
streams containing little hydrogen sulfide relative to
carbon dioxide; the membrane with the higher hydrogen
sulfide/methane selectivity, in treating streams containing
substantial amounts of hydrogen sulfide relative to carbon
dioxide; and a mixed membrane configuration in treating
streams in the intermediate category.
The availability of the two membrane types enables
treatment processes balanced in terms of the two membranes,
so as to optimize any process attribute accordingly, to be
designed. Based on the different permeation properties of
the two membrane types, we have discovered that it is
possible, through computer modeling, to define gas
composition zones in which a particular treatment process is
CA 02174341 2005-05-17
75136-9
9b
favored. For example, if it is the primary goal to minimize
methane loss in the membrane permeate, it may be better to
carry out the treatment using only the more hydrogen-
sulfide-selective membrane, only the more carbon-dioxide-
selective membrane or a mixture of both, depending on the
particular feed gas composition. Similar determinations may
be made if the amount of membrane area used is to be
minimized, the costs
CA 02174341 2004-04-19
75136-9
and a~agy of rxomprtssion are to be ktpt below a target value, the hydrogen
sulfide concentration in the
pc~ncate is to be nra,omiaed, the ovcall operating costs arc to be reduced, or
any other mtmbratte process
attribute is to be the kry design factor.
If a combination of the two membrane types is to be usod, the preferred
configuration is to pass
the gas stream fast through modules containing the one membrane type, then to
pass the residue stream
from the fast bank of modules through a second bank containing membranes of
the other type. If the raw
gas stream contains signif cant amounts of water, for example, it is prcferabk
to use the more hydrogen-
sulZde-sdcctive membrane first. These mtsabrarres arc not usually damagod by
water, and can handle gas
streams having very high relative humidifies, up to saturation. Furthermore,
the membranes an: very
10 permeable to water vapor, and so can be used to dehydrate the gas stream
before it passes to the secmtd
bank of modules.
Any membranes that can achieve the nocessary carbmt dioxid~tltane and hydrogat
sulGdclmethar~e selxtivities under mixod gas, high-pressure conditions, plus
provide commercially useful
transmcmbrsne fluxes, can be usod. The most proCemed material for the more
carbon-dioxide-sdective
membrane is cellulose acetate or its variants. The most preferred material for
the more hydrogen-sulfide~
selective membrane is a polyamide-polyether bkxk copolymers having the general
formula
HOC-PA-C-O-PE---C ~--H
~i a
O O
where PA is a polyamide se~nent, PE is a polycther segment and n is a positive
integer. Such polymtrs
n~
2o are available commercially as Pebax~ from Atochem lnc., Glen Rock, New
Jersey or as Vestamid~ from
~.
Nuodex inc., Piscataway, New Jersry.
In their most basic embodiments, the processes of the imrention make use of a
one-stage
mcmbr5ne design, if a single membrane type is indicated, and a two-step
membrane design, in which the
residue from the first step becomes the Toed for the second step, if a
combination of membrane types is
indicated. It is possible, however, to optimize the process in light of the
various aspects of gas treatment
discussad above, namely removal of impurities, less of mdharre, and ultimate
fate of the impiaities. To
simultaneously moat pipeline spocificatiarLS, minimize methane kiss and
produce a waste stream containing
a high hydrogen sulfide cocrcartratian, it may be desirable, for example, to
use a two-stago (or more
axnplicatod) membrane caa~figuration, in which the permeate from the first
stage bocatret the fend for the
3o scud. This will both increase the concentration of hydrogen sulfide in the
socond stage pate and
reduce the methane loss.
An important aspect of the imatbion is that the manbrarte process is oi>;eu
combined with ante or
E .- ."~' A
~WO 95111739 21 T 4 3 41 p~~s94/12100
11
more non-membrane processes, to provide a treatment scheme that delivers
pipeline quality methane, on
the one hand, and that concentrates and disposes of the acid-gas-laden waste
stream, in an environmentally
acceptable manner, on the other.
The processes of the invention exhibit a number of advantages compared with
previously
available acid gas treatment technology. First, provision of a membrane with
much higher selectivity for
hydrogen sulfide over methane makes it possible, for the first time, to apply
membrane treatment
efTiciently to gas streams characterized by relatively high concentrations of
hydrogen sulfide. Secondly,
the processes are much better at handling gas streams of high relative
humidity. Thirdly, it is sometimes
possible to bring a natural gas stream into pipeline specifications for all
three of carbon dioxide, hydrogen
sulfide and water vapor with a single membrane treatment. Fourthly,
overprocessing of the gas stream by
removing the carbon dioxide to a much Beater extent than is actually
necessary, simply to bring the
hydrogen sulfide content down, can be avoided. Fifthly, much greater
flexibility to adjust membrane
operating and perforn~ance parameters is provided by the availability of two
types of membranes. Sixthly,
the process can be optimized for any chosen process attribute by calculating
the appropriate membrane
mix to use.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 is a diagram showing zones in which particular membranes should be
used to separate hydrogen
sulfide and carbon dioxide from methane.
Figure 2 is a basic schematic drawing of a one-stage membrane separation
process.
Figure 3 is a gaph showing the effect of water vapor on carbon dioxide flux
through cellulose acetate
membranes.
Figure 4 is a gaph showing the effects of hydrogen sulfide and water vapor on
the performance of
cellulose acetate membranes.
Figure 5 is a basic schematic drawing of a typical two-stage membrane
separation process.
Figure 6 is a basic schematic drawing of a two-step membrane separation
process.
Figure 7 is a basic schematic drawing of a two-step/two-stage membrane
separation process.
Figure 8 is a basic schematic drawing of a two-stage membrane separation
process with an auxiliary
membrane unit forming a second-stage loop.
Figure 9 is a diagram showing zones in which particular membranes should be
used to separate hydrogen
. sulfide and carbon dioxide from methane, based on different hydrogen
sulfide/methane selectivities.
Figure 10 is a diagram showing zones in which particular membranes should be
used to separate hydrogen
WO .95!11739 ° f a '~, '; ° '.; ~ ~ ~ ~ PCT/US94/12100
12
sulfide and carbon dioxide from methane, based on different carbon
dioxide/methane selectivities.
Figure 11 is a diagram showing zones in which particular membranes should be
used to separate hydrogen
sulfide and carbon dioxide from methane, for different feed gas pressures.
Figure 12 is a basic schematic drawing of a membrane process combined with non-
membrane processes
to treat both the residue and permeate streams from the membrane unit.
DETAILED DESCRIPTION OF THE INVENTION
The term intrinsic selectivity, as used herein, means the selectivity of the
polymer material itself,
calculated as the ratio of the permeabilities of two gases or vapors through a
thick film of the material, as
measured with pure gas or vapor samples.
The term ideal selectivity, as used herein, means the selectivity of a
membrane, calculated as the
ratio of the permeabilities of two gases or vapors through the membrane, as
measured with pure gas or
vapor samples.
The terms mixed gas selectivity and actual selectivity, as used herein, mean
the selectivity of a
membrane, calculated as the ratio of the permeabilities of two gases or vapors
through the membrane, as
measured W th a gas mixture containing at least the two gases or vapors in
question.
The invention has several aspects. In one aspect, the invention concerns
processes for treating
gas mixtures containing carbon dioxide in certain concentrations, hydrogen
sulfide in certain
concentrations and methane, to remove the carbon dioxide and hydrogen sulfide.
In another aspect, the
invention concerns optimizing such membrane separation processes in terms of a
particular process
attribute. This optimizing may be done to minimize the methane loss from the
membrane process, to
maximize the hydrogen sulfide cor~ntration in the permeate stream, or to
provide the best fit between the
membrane process and a non-membrane process or processes acting together as a
"hybrid" process, for
example. In yet another aspect, the invention concerns membranes that maintain
high hydrogen
sulficklmethane selectivities when challenged with mixed gas streams under
high pressures. In yet another
aspect, the invention concerns combinations of membrane and non-membrane
treatment processes.
The processes of the invention rely on the availability of two membrane types:
one, cellulose
acetate, or a material with similar properties, characterized by a mixed gas
carbon dioxide/methane
selectivity of about 20 and a mixed gas hydrogen sulfide/methane selectivity
of about 25; the other a
membrane with a much higl~r mixed gas hydrogen sulfide/methane selectivity of
at least about 30, 35 or
and a mixed gas carbon dioxide/methane selectivity of at least about 12. These
selectivities must be
achievable with gas streams containing at least methane, carbon dioxide and
hydrogen sulfide and at feed
°
~ ;": :~ ?~. ~". ~, ; '
WO 95/11739 217 4 3 41 PCT/US94/12100
13
pressures of at least 3550 kPa (500 psig), more preferably 5620 kPa (800
psig), most preferably 7000 kPa
(1,000 psig).
The invention provides three forms of basic membrane treatment process:
1. Using only the more hydrogen-sulfide-selective membrane
2. Using only the more carbon-dioxide-selective membrane
3. Using a combination of both types of membrane.
Based o~n the different per~ation properties of the two membrane types, we
have discovered that
it is possible, through computer modeling, to define gas composition zones
most amenable to each one of
these three types of basic processes. In performing the computer calculation,
a specific process attribute
is used as a basis for calculating the boundaries of the gas composition
zones. It will be apparent to those
of ordinary skill in the art that any one of many process attributes could
serve as the basis for the
calculation. Representative, non-limiting, examples include methane loss,
membrane area, stage cut,
energy consumption, annual operating costs, permeate composition, residue
composition, best match with
other processes in the treatment train, volume%omposition of recycle streams,
and so on.
Loss of methane is usually one of the most important factors in natural gas
processing. On the
one hand, pipeline grade methane is the desired product, and substantial
losses of product have a
substantial adverse effect on the process economics. On the other hand, large
quantities of methane in the
acid gas stream make further handling and recovery of any useful products from
this stream much more
diihcult. As a general rule, a successful natural gas treatment process should
keep methane losses during
processing to no more than about 10%, and preferably no more than about 5%.
For simplicity, therefore, most of the discussion and examples have been
directed to processes
designed to minimize methane losses, although it should be appreciated that
the scope of the invention is
intended to encompass any process design calculations done with the same goal,
namely, defining zones
applicable to the various processing options made possible by the two membrane
types.
We believe the concept of these zones, how to calculate them and how to use
them, is new, and
will be useful in treating any gas stream that comprises methane, carbon
dioxide and hydrogen sulfide.
such streams arise from natural gas wells, from carbon dioxide miscible
flooding for enhanced oil recovery
(EOR) and from landfills, for example. We believe that it will be particularly
useful in the sweetening of
natural gas containing acid gas components.
Referring now to Figure 1, this shows a typical zone diagram, with feed gas
carbon dioxide
concentration on one axis and hydrogen sulfide concentration on the other. The
diagram was prepared by
running a series of membrane separation computer simulat5ons for hypothetical
three-component
2I 74341
WO 95/11739 PCT/US94/12100
14
(methane, carbon dioxide, hydrogen sulfide) gas streams of particular slow
rates and compositions. In all
cases, the target was to bring the stream to a pipeline specification of 4 ppm
hydrogen sulfide and
2% carbon dioxide. The membrane properties were assumed to be as follows:
$ Mnre C'p~~elective membrane: Carbon dioxide/methane selectivity: 20
Hydrogen sulfide/methane selectivity: 25
Methane flux: 7.5 x 10'~ cm'(STP)/cm2~s~cmHg
ore I-I~"S-selective membrane: Carbon dioxide/methane selectivity: 13
Hydrogen sulfidelmethane selectivity: 50
Methane flux: 7.5 x 10~ cm'(STP)/cm2~s~cmHg
In each case, the methane loss into the permeate stream that would occur if a
one-stage membrane
separation process were to be carried out was calculated, and was used to
define zones of least methane
loss. As can be seen, Figure 1 is divided into four zones. In zone A, no
treatment is required, because the
gas already contains less than 2% carbon dioxide and less than 4 ppm hydrogen
sulfide. In zone B,
methane loss is minimized if the more hydrogen-sulfide-selective membrane
alone is used. In zone C,
methane loss is minimized if the more carbon-dioxide-selective membrane alone
is used. In zone D,
m~hane loss is minimized by using a combination of the two membrane types. The
zones are calculated
based on the membrane selectivity and their exact position will change if the
membrane selectivity
changes. Figures 9 and 10 show the change in the B/D boundary for hydrogen
sulfide/methane
sclectivities of 30, 40 and 50 and for carbon dioxide/methane selectivities of
10, 13 and 15. As can be
seen, the Zone B/D boundary moves to the right as the ability of the membrane
to separate carbon dioxide
improves. Likewise, the boundary moves to the right as the selectivity for
hydrogen sulfide over methane
decreases. Although the area where the more hydrogen-sulfide-selective
membranes should be used is
larger at lower hydrogen sulfide/methane selectivity, the methane losses
encountered in using the
membrane will be greater. Figure 11 shows the change in the B/D boundary for
different feed pressures.
As can be seen, the zone boundary is relatively insensitive to changes in the
fced pressure.
The zone diagram may be used directly to determine the best type of membrane
to use for a
specific separation by reading off the zone into which the feed composition
fits.
Another way to use the diagram is to define concentration bands that can serve
as guidelines in
selecting a membrane process. Again refer ing to Figures 1, 9 and 10, we have
discovered that, as a guide,
three carbon dioxide concentration bands may be defined, thus:
1
t-. !': :_. '
WO 95/11739
21 l 4 3 41 p~~/~594/12100
1. (a) If the feed gas to the membrane system contains less than about 3%
carbon dioxide to less
than about 10% carbon dioxide and more than about 10 ppm hydrogen sulfide to
more than about
300 ppm hydrogen sulfide, with the lower end of the carbon dioxide range
corresponding to the lower end
of the hydrogen sulfide range (<i% carbon dioxide; > 10 ppm hydrogen sulfide)
and the upper end of the
carbon dioxide range ~ponding to the upper end of the hydrogen sulfide range
(<10% carbon dioxide;
>300 ppm hydrogen sulfide), then the most favorable process, in terms of
minimizing methane loss, is
carried out using the more hydrogen-sulfide-selective membrane only.
(b) If the feed gas contains less than about 10% carbon dioxide to less than
about 20% carbon
dioxide and more than about 300 ppm hydrogen sulfide to more than about G00
ppm hydrogen sulfide,
10 with the lower end of the carbon dioxide range corresponding to the lower
end of the hydrogen sulfide
range (<10% carbon dioxide; >300 ppm hydrogen sulfide) and the upper end of
the carbon dioxide range
corresponding to the upper erg of the hydrogen sulfide range (QO% carbon
dioxide; >600 ppm hydrogen
sulfide), then the most favorable process, in terms of minimizing methane
loss, is carried out using the
more hydrogen-sulfide-selective membrane only.
15 (c) If the feed gas contains less than about 20% carbon dioxide to less
than about 40% carbon
dioxide and more than about 600 ppm hydrogen sulfide to more than about 1%
hydrogen sulfide, with the
lower end of the carbon dioxide range c~ponding to the lower end of the
hydrogen sulFde range (QO%
carbon dioxide; >G00 ppm hydrogen sulfide) and the upper end of the carbon
dioxide range corresponding
to the upper end of the hydrogen sulfide range (<40% carbon dioxide; >1%
hydrogen sulfide), then the
most favorable process, in terms of minimizing methane loss, is carried out
using the more hydrogen-
sulfide-selective membrane only.
Also, three hydrogen sulfide concentration bands may be defined, thus:
2. (a) If the feed gas contains less than about 5 ppm hydrogen sulfide to less
than about 50 ppm
hydrogen sulfide and more than about 3% carbon dioxide to more than about 15%
carbon dioxide, with
the lower end of the carbon dioxide range corresponding to the lower end of
the hydrogen sulfide range
(<5 ppm hydrogen sulfide; >3% carbon dioxide) and the upper end of the carbon
dioxide range
corresponding to the upper end of the hydrogen sulfide range (<50 ppm hydrogen
sulfide; > 15% carbon
dioxide), then the most favorable process, in terms of minimizing methane
loss, is carried out using the
more carbon-dioxide-selective membrane only.
(b) If the feed gas contains less than about 50 ppm hydrogen sulfide to less
than about 250 ppm
hY~g~ ode and more than about 15% carbon dioxide to more than about 50% carbon
dioxide, with
the lower end of the carbon dioxide range corresponding to the lower end of
the hydrogen sulfide range
_.... 2 ~ X4341
1'CTIUS94/12100
WO 95/11739
16
(<50 ppm hydrogen sulfide; >15% carbon dioxide) and the upper end of the
carbon dioxide range
corresponding to the upper end of the hydrogen sulfide range (<250 ppm
hydrogen sulfide; >50% carbon
dioxide), then the most favorable process, in terms of minimizing methane
loss, is carried out using the
more carbon-dioxide-selective membrane only.
(c) If the feed gas contains less than about 250 ppm hydrogen sulfide to less
than about 500 ppm
hydrogen sulfide and more than about 50% carbon dioxide to more than about 85%
carbon dioxide, with
the lower end of the carbon dioxide range corresponding to the lower end of
the hydrogen sulfide range
(<250 ppm hydrogen sulfide; >50% carbon dioxide) and the upper end of the
carbon dioxide range
con~sponding to the upper end of the hydrogen sulfide range (<500 ppm hydrogen
sulfide; >85% carbon
dioxide), then the most favorable process, in terms of minimizing methane
loss, is carried out using the
more carbon-dioxide-selective membrane only.
Also:
3. For feed gas compositions outside the ranges specified in points 1 and 2
above, the most favorable
process, in terms of minimizing methane loss, is carried out using a
combination of the more hydrogen-
sulfide-selective and the more carbon-dioxide-selective membranes.
Another way to express the teachings of the invention is simply to define
single limits for the
carbon dioxide and hydrogen sulfide concentrations that are best treated by
different types of membrane.
This approach gives a less accurate result in any individual circumstance than
the zone or band
approaches, but gives a broad guide that is useful irrespective of the
particular process attribute that is of
most concern. Specifically:
1. If the carbon dioxide content of the stream is less than about 40% and the
hydrogen sulfide content is
more than about 6,000 ppm (1%), the more hydrogen-sulfide-selective membrane
should be used.
2. If the carbon dioxide content of the stream is less than about 20% and the
hydrogen sulfide content is
more than about 500 ppm, the more hydrogen-sulfide-selective membrane should
be used.
3. If the carbon dioxide content of the stream is less than about 10% and the
hydrogen sulfide content is
more than about 10 ppm, the more hydrogen-sulfide-selective membrane should be
used.
4. If the hydrogen sulfide content of the stream is less than about 25 ppm and
the carbon dioxide content
is more than about 10%, the more carbon-dioxide-selective membrane only should
be used.
5. If the hydrogen sulfide c~tent of the stream is less than about 100 ppm and
the carbon dioxide content
is more than about 15%, the more carbon-dioxide-selective membrane only should
be used.
6. If the carbon dioxide content of the stream is in the range about 5-20%
carbon dioxide and the
hydrogen sulfide content is in the range 10-1,000 ppm, a combination membrane
system may be used.
iv
WO 95/11739
~ ~ 7 4 3 4 l pCT/US94/12100
17
7. If the carbon dioxide content of the stream is in the range about 10-25%
carbon dioxide and the
hydrogen sulfide content is in the range 50-5,000 ppm, a combination membrane
system may be used.
8. If the carbon dioxide content of the stream is greater than about 25%
carbon dioxide and the hydrogen
sulfide content is greater than about 200 ppm, a combination membrane system
may be used.
9. If the carbon dioxide content of the stream is greater than about 40%
carbon dioxide and the hydrogen
sulfide content is greater than about 600 ppm, a combination membrane system
may be used.
If a combination of the two membrane types is to be used, the simplest
configuration is to pass
the gas stream first through modules containing the one membrane type, then to
pass the residue stream
from the first bank of modules through a second bank containing membranes of
the other type. The order
in which the membrane types are encountered by the gas stream can be chosen
according to the specifics
of the application. If the raw gas stream contains significant amounts of
water and hydrogen sulfide, for
example, it is preferable to use the mode hydrogen-sulfide-selective membrane
fu~st, since cellulose acetate
membranes have been shown to lose both selecfivity and permeability
substantially if exposed to
combinations of water vapor and hydrogen sulfide. They also do not withstand
relative humidifies above
about 30% very well. The polyamide-polyether block copolymer membranes that
are preferred as the more
. hydrogen-sulfide-selective membrane, on the other hand, are not usually
damaged by water or hydrogen
sulfide, and can handle gas streams having high relative humidifies, such as
above 30% RH, above 90%
RH and even saturation. Furthermore, the membranes are very permeable to water
vapor, and so can be
us~i to dehydrate the gas stream before it passes to the second bank of
modules. If humidity and hydrogen
sulfide content are not issues, and no other factors that affect only one of
the membrane types are at work,
then the total methane loss into the permeate streams and the total membrane
area required to perform the
separation should be essentially independent of the order in which the
membranes are positioned.
Arty marrbranes that can achieve the necessary carbon dioxidc/methane
selectivity and hydrogen
sulfideJmethane selectivity, plus commercially useful transmembrane fluxes,
can be used. Preferably the
membranes should be characterized by transmembrane methane fluxes of at least
I x 10~ cm'(STP)/cm2~s~cmHg, most preferably by transmembrane methane fluxes
of at least
1 x 10-5 cm'(STP)/cm2~s~cmHg.
For the more carbon-dioxide-selective membrane, the preferred membranes are
the cellulose
acetate membranes that are ali~eady in use. Other candidates include different
cellulose derivatives, such
as ethylcellulose, methylcellulose, nitrocellulose and particularly other
cellulose esters. Otherwise,
membranes might be made &nrtr polysulfone, polyethersulfone, polyamides,
polyimides, polyetherimides,
polyacrylonitrile, polyvinylalcohol, other glassy materials or any other
appropriate material. Usually,
CA 02174341 2004-04-19
751369
18
glasry materials have enough mechanical strength to be fornned as integral
asymmetric membranes, the
production of which is well known in the art. The invention is not intended to
be limited to arty particular
membrane material or membrane type, however, and encompasses arty membrane, of
arty material, that
is capable of meerirrg the target pem>cation properties, including, for
acample, homogeneous membranes,
composite membranes, and membranes incorporating sorbents, carriers or
plasticizcrs.
For the more hydrogen-sulfide-seleetivt membrane, the most preferred membranes
have
hydrophilic, polar elastomeric selective layers. T'he mobility selectivity of
such materials, although it
favors hydrogen sulfide and carbon dioxide over methane, is modest compared to
glasry materials.
Bocat>,sc the membrane is hydrophilic and polar, however, the sorption
selectivity strongly favors hydrogen
sulfide, carbon dio~tide and water vapor over non-polar hydrophobic gases such
as hydrogsn, ,
propane, bumne, etc. Although the silxtivity of such materials is affected by
swelling in the presence of
conc~sable components, we have discovered that hydrogen sulGdelmethane
selectivities of at least 30 or
35, sometimes at last 40 and sometimes 50, 60 or about can be maintained, even
with gas mixtwes
containing high acid gas concentrations, even at high relative humidity, and
even at high fend pressures
up to 3530 kPa (500 psig), 5621 kPa (800 psig), 7000 kPa (1,000 psig) or
above. These are unusual and
very useful properties. Those properties rarda the membranes unusually
suitable for treating natural gas,
which offer cattair>s multiple companarts, has high humidity and is at high
Preferred merrrbrarte
materials are those that exhibit water sorption greater than 5'/0. more
preferably greater than 10'/., when
exposed to liquid water at room temperatwc. Particularly preferred arc
segrsKnted or block copolymers
that form two-domain structures, one domain being a Bolt, rubbery, hydrophilic
region, the other being
harder and glassy or more glassy. Without wishing to be bound by any
particular theory of gas transport,
we believe that the soft, rubbery domains provide a preferential pathway for
the hydrogen sulfide and
carbon dioxide components; the harder domains provide mahanical strength and
prevent excessive
swilling, and hence loss of selectivity, of the soft domains. Polyetha blocks
are prefernd for forming the
colt flexible domains; most preferably these blacks incorporate polyethylene
glycol, polyte;cramethylene
glycol or polypropylene glycol, to irtcreasc the sorption of polar molecules
by the membrane material.
One specific acample of the most preferred membrane materials that could be
used for the more
hydrogen-sulfide selective membrane is polyamide-polyctlrer block copolymers
having the general formula
HO-~C-PA-C-O-PE-C ~--H
~~ ~~ n
O O
where PA is a polyamide segment, PE is a poiyelher segment and n is a positive
integer. Such polymers
are available coerrmereially as Pebsc~ from Atocixm Inc., Gkn Rock, New Jersey
or as Vestamid~ from
CA 02174341 2004-04-19
75136=9
19
T4
Nuod~c Inc., Piscataway, New Jcrsty. The po!yamide block gives strength and is
believed to prevent the
membrane swelling excessively in the pr~esettet of water vapor and/or carbon
dioxide.
thher specific examples include polyether- and polyester-based polyurethanes.
Iteprescntativc
polymer formulations and recipes are given, !err example, in U.S. Patent
5,096,592, in which the
oopolymas ate made by first pctparing a pr~epolytnet by combining simple diols
and aliphatic or aromatic
dicarboxylie acids with an exerss of diacid to prepare diacid-terminated
blocks, then chain-extending these
with appropriately selected polypropylene or polyethylase glycol segments.
Usually, rubbery materials do not have enough mechanical strength to be formed
as integral
asymmetric membranes, but are instead incorporated into composite membt~anes,
in which the rubbery
selective layer is supported on a microporous substrate, otlcn made from a
glassy polymer. The
prcparatiort of composite membranes is also well latown in the art. It is
commonly thought that rubbery
composite manbrarxs do not withstand high-pressure operation well, and to
date, such membranes have
not boon ge~ally used in natural gas treatment, whore fend gas pressura are
often as high as 3550 kPa
(300 psig) or 7000kPa (1,000 psig). We have Cound, however, that composite
membranes, with thin
enough rubbery scioctivc layers to provide a transmembrane mcthans flux of at
least
1 x 10~ em'(STP)km~~s~cmHg, can be used satisfactorily at high food pressures
and not only maintain
their integrity but continue to exhibit high selectivity for hydrogtn sulfide
over methane.
In their most basic embodiments, the processes of the invention make use of a
one-stage
membrane design if a single membrane type is indicated, and a two-step
membrane design, in which the
residue from the first step becomes tbc feed for the second step, if a
combination of tnanbratte types is
indicated, It will be apparent to those of ordinary skill in the art that more
sophisticated embodiments are
possible. For example, a two-stage (or more oompiicatod) membrane
configuration, in which the pamtate
from the fast stage bocames the feed for the second, may be used to further
enrich the acid gas content oC
the patruatc stream and to reduce methane losses. It is envisaged that a two-
stage msmbrane
configuration, using like or unlike membrane types in the two stages will
ofiut be used_ In such
arrangements, the residue stream from the second stage may be rocirculated for
further treatment in the
fast stage, or may be passed to the gas pipeline, for example.
M important aspoct of the invrntiat is that the manbrane process is often
combined with one or
more non-mernbranc processes, to provide a "hybrid" treatment scl>eme that
dciivers pipeline quality
methane, on the one hand, and that concentrates and disposes of the acid-gas-
laden waste stream, in as
environmentally acceptable manna, on the other. Given the diversity of flow
rates, coenposilions and
locations of natural gas wells, it is envisioned that the membrane separation
process will often form part
CA 02174341 2004-04-19
~513s-9
of a hybrid trtatma~t schane that includes multiple treatment steps in an
integrated tratmrnt train. Such
schenxs might gma~ally be described as having four components, any subset of
which may be needed in
a specific situation, namely:
1. Primary bulk separation of acid gas components from.the feed gas stream.
5 2. Additional treatment of the swoeteaod product gas stream to melt pipeline
specifications.
3. Additional trcatmait of the waste gas stream to canoartratc the by&ogcn
sulfide and to reduce methane
losses.
4. Disposallcanversioa of the hydrogen sulfide.
In the processes of the invention, the first component of the scheme, primary
bulk separation, is
10 accornplishod by membrane separation. Depending on the feed composition,
configuration of the
membrane system and operating conditioru, additional non-membrane treatment of
the sweetened product
gas strrram may or may not be necessary. If a non-membrane treatment process
is used, it may be of arty
appropriate type, such as absorption, adsorption, chanical reactiocs a the
like. Absorption processes using
alkanolamines are widely used in the gas industry at present. The reactivity
and relatively low cost,
IS particularly of MEA (monoethanolamine) and DEA (diethanolamine), has made
them the workhorse
sorbrnts of the industry. The absorption process involves passing the acid-gas-
laden stream into an
aqueous solution oC the amine of choice, which reacts with the hydrogen
sulfide and carbai dioxide in the
stream. The amine solution is regenerated for further use by heating.
Alternatively, other sacbent solutions, such as hot potassium carbonate, may
be used, particularly
20 if the gas stream contains a large amount of acid gas. Potassium carbonate
solutions may be regenerated
by steam stripping. Pmmotcrs or activators, for example DEA (8e~eld process),
arsenic trioxide,
selenous acid and tcllurous acid (Giammarco-Vetrocoke process), can be added
to the basic potassium
TIA
carbonate solution. In applications for the removal of hydrogen sulGdc,
tripotassium phosphate (Shell
Development Canpany) may be used.
As yet another aliernativc, physical sorbcnts may be used. Representative
absorption processes
TM 1AA
that make use of physical sorbents include the Selexol process f,Norion
Comparry), which uses dimethyl
1Y 111
ether of polyethylene glycol, the Rectisol and Purisol pivoccsscs (,Lurgi
Gesdlschait f-ur Warmetoclrnik),
TY TV
Estasolven proctss (Friedrich Uhde GmbI~ and the Sulfinol process (Shell
International Research).
A few representative examples of the other types of non-membrane process
inchrde specialized
,M ,w >r
3o scavenging or sulfur recovery processes, such as Sulfa-Scrub, Sulfa.Chock,
ChemsWreet, Supatron 600,
solid iron sponge or solid rinc oxide.
The manbrane process itself can usually provide the additional treatment
netded as the third of
CA 02174341 2004-04-19
75136-9
21
the four components in the procsss scheme listed above, namely to achitvc
sufficient conetntratia~n of
hydrogen sulfide, and to reduce methane loss. This is typically accomplished
by adding a second stage
to the membrane unit, so that the permeate from the first bulk separation
stage is subjected to a second
treatment.
The fourth compmtertt of the proaxs train is disposal or conversion of the
hydrogen sulfide
concentrated stream. Preferably, the hydrogen sulfide is concentrated rnough
for treatment by a sulfur-
fixing process. The most preferred p<ooas is the Claus process, which
cossverts hydrogen sulfide to high-
quality, saleable sulfur. The basic steps in the process involve burnirsg the
acid gas with stoichiometric
amounts of air so that about 113 of the hydrogen sulfide is oxidized to sulfur
dioxide. The incinerated
stream a passed through a waste heat boiia and over a bauxite catalyst at
about 370-400°C(700-750°I~.
Unc~r these conditions, the sulfur dioxide and hydrogen sulfide react to fornt
elemental sulfur, which is
condensed at about 160°C (320°F). The process can be repeated in
second and third stages to increase
the sulfur yield With a two-stage plant, sulfur removal cfTicicncics of 95%
are typical. The tail-gas frmtt
the plant can be treated to meet environmental standards before discharge. For
efficient operation of the
I 5 Claus plant, the hydrngm sulfide content of the incoming stream should be
above about 8 vol%, and most
preferably should be higher, such as above 10 vol°/. or above 20
vol°/..
Alternatively, camersion of th: hydrogen sulfide to elemental sulfur can be
carried out using s
redox process. Such processes arc usually based on bringing the hydrosen
sulfide into contact with a
liquid suspension of oxidants such as polythionate, iron-cyanide complexes,
iron oxide, lhioarsenates or
organic catalysts. After several reaction steps, elemental sulfur
precipitates. The solvent can then be
tooxidizod and rwsed Various corrrmemial rodac prooasas are available,
including Manchester, Stretford
n
A.D.A., Takaha.~~ Thylox, Giammarco-Vetrocoke and Shell Sulfolane. Typically,
rodox processes are
mane applicable to the recovery of small tautages of sulfur than the Claus
process. The sulfur quality is
poser than that fran a Claus plant and furiha refuting is needed to make it
saleable. Such processes can,
houreva, be run with relatively low inlet hydrogen sulfide concrntrations,
such as about 2 vol% or more
preferably above 4 vol'/°. As a less preferred alternative, the waste
stream containing hydrogen sulfide
may be flared or used as fuel gas.
A gata~al scharmtic of a process in which both the membrane residue stream and
the membrane
permeate svrcam are subjected to further non-membrane treatments is shown in
Figure I2. Referring to
this figure, feed stream 51 enters the membrane unit 50 for treatment. The
membrane unit rosy contain
one or more barks of membrane modules, of the same a ditlareat types, arranged
in any desired
oonGgurution, such as ano-stage, multistage, multistep and variations thereof.
As just a few n~-limiting
r ~ ;.
E ... ,~. : ~~ ~ ~ 7 4 3 41
WO 95/11739 PCT/US94/12100
22
examples, the arrangements shown in Figures 5, 6, 7 or 8 could be used.
Partially sweetened residue
stream 52, depleted in acid gas content compared with feed stream 51, passes
to an non-membrane
treatment process 53 far additional acid gas removal. This process may be any
appropriate process known
in the art, such as absorption and the other processes discussed above.
Treated stream 54 exits the process
and passes to a pipeline or other destination. Stream 55, which is enriched in
acid gas content compared
with stream 5 l, passes to non-c~nbrane treatment process 56. This process may
also be any appropriate
process known in the art, but is preferably a process such as a redox process
or a Claus process that
produces sulfur as a useable product. In this case, stream 57 indicates the
sulfur product stream.
Otherwise, the process may treat, fix or contain the acid gases in some other
fashion, so that stream 57 is
simply the discharge stream from that process.
In the zone calculations, the target pipeline specification for the treated
gas was assumed to be
no more than about 2 vol% carbon dioxide and 4 ppm hydrogen sulfide, which is
typical pipeline
specification. However, depending on the destination of the gas and s~cific
standards to which the gas
is subject, it is believed that a carbon dioxide content below about 3 vol%
and a hydrogen sulfade content
below about 20 ppm will be acceptable in many situations.
The processes of the invention exhibit a number of advantages compared with
previously
available acid gas treatment technology. First, provision of a membrane with
much higher selectivity for
hydrogen sulfide over methane makes it possible, for the fast time, to apply
membrane treatment
efficiently to gas streams characterized by relatively high concentrations of
hydrogen sulfide compared to
carbon dioxide. This expands the range of utility of membrane separation
substantially. Since membrane
systems are light, simple and low-maintenance compared with amine plants, the
enhanced ability to use
membranes as a treatment option facilitates the exploitation of gas fields off
shore or in remote locations.
Secondly, the processes are much better at handling gas streams of high
relative humidity, so that less
pretreatment of the raw gas stream is necessary. Thirdly, it is sometimes
possible to bring a natural gas
stream into pipeline specifications for all three of carbon dioxide, hydrogen
sulfide and water vapor with
a single membrane treatment. Fourthly, overprocessing of the gas stream by
removing the carbon dioxide
to a mph greater extent than is actually nary, simply to bring the hydrogen
sulfide content down, can
be avoided. Fifthly, much greater flexibility to adjust membrane operating and
performance parameters
is provided by the availability of two types of membranes. Sixthly, the
process can be optimized for any
chosen process attribute by calculating the appropriate membrane mix to use.
The invention is now further illustrated by the following examples, which are
intended to be
illustrative of the invention, but are not intended to limit the scope or
underlying principles of the invention
CA 02174341 2004-04-19
75136=9
23
in any way.
EXAMPLES
The examples arc in five seas.
SET 1
Examples 1-10 are comparative examples that illustrate the performance of
various glasry and rubbery
polymers exposed to acid gases undo a variety of conditions.
example 1. Pure gas measurements. Po1 n~m~ membranes of two erades
(a) A thret-layer composite manbrane was prrpared, using a microporous
polyvinylidene fluoride
(PVDF) support layer. The support was first coated with a thin, high-Ilex,
scaling Iayu, then with a
TN
selective layer of polyimide (Matrimid Grade 5218, Ciba-Geigy, Hawthornc, N~.
Membrane stamps
were mounted in a test cell and the permeation properties of the membrane were
tested with pure carbon
dioxide and with pure n>ethane at a Coed pressure of 448 l:Pa (50 psig). The
results are listed in Table 1.
(b) A three-layer composite membrane was prepared, using a microporous
polyvirrylidene fluwide
IS (PVDF) support layer. The support was first coated with a thin, high-flux,
sealing layer, then with a
selective layer of polyimidc (custom-made 6FDA-IPDA). Membrane stamps were
mounted in a test cell
and the permeation properties of the membrane were tested with pure carbon
dioxide and with pure
methane at a feed presswe of 448 kPa (50~ prig). The results are listed in
Table 1.
Example 2 Mi~ccd~a,~measuremcnts Polyimide~,membranes of twos
(a) Throe-layer composite membranes as in Example I (a) were tested with a gas
mixture consisting of
800 ppm hydrogai sulfide, 4 vol°/r carbon dioxide, the balsna mdhane.
The food pressure was 2,793 kPa
(390 prig). The results are listed in Table 1.
(b). Thrx-layer compasitc membranes as in Example 1 (b) were tested with a gas
mixture consisting of
800 ppm hydrogen sulfide, 4 vol'/. carbon dioxide, the balance methane. Two
feed pressures, 2,807 kPa
(392 prig) and 4,890 kPa (694 prig), were used. The rrsults arc listed in
Table 1.
Example 3 Pwe ear mcaswements PTMSP membrane
A composite membrane was prepared by coating a polytrimelhyl-silyflxOpync
(PTMSP) layer
onto a polyvinylidcnc fluoride (PVD~ support membrane. Membrane stamps were
momttod in a test cell
and the permeation properties of the membrane was tested with port carbon
dioxide and with pure
methane at a feed pressure of 448 kPa (50_ prig). The results are listed in
Table 1.
, r. ~ ~ >., ° '
WO 95!11739 2 ~ 7 4 3 41 PCT/US94/12100
24
F~xamgle 4 Mixed eas measurements PTMSP membrane
Composite membranes as in Example 3 were tested with a gas mixture consisting
of 800 ppm
hydrogen sulfide, 4 vol% carbon dioxide, the balance methane. The feed
pressure was 2,793 kPa
(390 psig). The results are listed in Table 1.
Example 5 Pure eas -measurements Silicone rubber membrane
A composite membrane was prepared by coating a silicone rubber layer onto a
microporous
support membrane. Membrane stamps were mounted in a test cell and the
permeation properties of the
membrane were tested with pure carbon dioxide and with pure methane at a feed
pressure of 448 kPa
(50 psig). The results are listed in Table 1.
Example 6 Mixed has measurements Silicone rubber membrane
Composite membranes as in Example 5 were tested with a gas mixture consisting
of 650 ppm
hydrogen sulfide, 4 vol% carbon dioxide, the balance methane. The feed
pressure was 759 kPa (95 psig).
The results are listed in Table 1.
Example 7 Pure gas measurements Pol~utadiene membrane
A c~nposite membrane was prepared by coating a polybutadiene (Scientific
Polymer Products,
Ontario, NIA layer onto a PVDF support membrane. Membrane stamps were mounted
in a test cell and
the permeation properties of the membrane were tested with pure carbon dioxide
and with pure methane
at a feed pressure of 448 l:Pa (50 psig). The results are listed in Table 1.
E~ple 8 Mixed g_as measurements. Polybutadiene membrane
Composite membranes as in Example 7 were tested with a gas mixture consisting
of 800 ppm
hydrogen sulfide, 4 vol% carbon dioxide, the balance methane. The feed
pressure was 2,821 kPa
(394 psig). The results are listed in Table 1.
CA 02174341 2004-04-19
~513s=9
a
TABLE 1
is
The higl~st selectivity for hydrogen sulfide ova nwas only 10.5, which was
achievod wi
th
a poiyimide membrane at about2,862 kPa ( 400 prig) fad pressum,
_ _ ." . ..a cr va
This comparative e.~campic is from the report by N.N. Li et al. to the
("Membnme S ~p~nt of Enemy
epin the P~ ~° ~ n Final Report, Septaaber 1987).
Li et al. acamined the e~~ of water vapor in a fend gas stream of carbon
dioxide on trans~b~
flw4
F~~e 3~ ~~ ~ ~ art summarizes their data. For relative humidity of 10% ~ )~ ~
is
appreciabk effort ors the carbon dioxide ilu.~c For relative humidifies in the
range 18 23'/e, the !>vac
30'/e compared to the dry gas ilu~c, but recovered when the feed was switci~
b~ to as.
~Yg
~~ h~~~es of 3D'/o and higher, the flux declirK was found to be large, rapid
end irrcv~.ble.
x~plc 0 Bc~vi~r ~rr.n..m_ . __. . _ . _
V~oar
This example is also taken fi,~m the Li et al. report. Figure 4 ~ the data.
Hydrogen
Permeation Proputies of Various Glassy and Rubbery Polymer Membranes
75136=9
CA 02174341 2004-04-19
26
sulfide has a negligible effect on membrane performance if the feed gas is
dry. if both hydrogen sulfide
and water vapor arc present, horveva, the trarLSmmembrane ihnc is
substantially reduced. Li et al. conclude
that the processing of streams containing both high concentrations of hydrogen
sulfide and water vapor
must be avoided with cellulose acetate membranes.
SET 2
Examples 11 and 12 show the performance of polyamide-polycther membranes
exposed to pure
gases. These ~camples are Cran curlier work at Membrane Technology and
Research, as already reported
in U.S. Patent 4,963,165, since we were not able to make measurements with
pure hydrogen sulf~dc.
Exam,~le 11. P~,vamide-~yether membranes. Pure as data
A multilaya composite membrane was prepared by coating a polysuifone support
membrane first
TM
with a thin high-flax, scaling layer, then with a 1 wt% solution of Pebax
grade 401 I in i-butarrol. The
membrane was t~ with ptuc gases at a temperature of 20°C and a feed
pressure of 448 kPa (50 psig).
The results are shown in Table 2.
Examnle 12. Polvamide-polvether membranes. Pure eas data
A sxond membrane was prepared using the same materials and technique as in
Example I 1. The
results oCpure gas tuts with this manbrane are also shown in Table 2. That is
good agreement between
the sets of results from Examples I 1 and 12.
TABLE 2
TM
Permeation Properties of Pcbax 4011 Composite Membranes
Tested with Pure Gases
r :4 rr.~ ~,C~ ~9u:... o.~ '~4 .~~tE ~j 4
H .tq ~y. ~5.: ~ :.._
' ~~ '~ ~~ i
~ % Y
L Sf o-c ~
~ 1 ~ . '''
t9 '~
'~
~
a n..? ... ?6
:.,R;:.:::... , .,..Z-_.5;,.,. 4
,.3:..a.2 .:.. .::t' ,?.g, .
~:;.r,:,k~:5t;..... d: ~..:.. e
;:Y:ai '...v.v,:,:.,&z.:.:r~~... ::::??.... :a"~~
:%~ sF . .
.t ;; ~..:. ::. ~~
::??a. ~~~~~;a
.: .>:
' ~
~L.a i. ~,K:h,~~
~~~C :(~
~ . . . I-r
2'v. . ? d ~ ~
- ?1a ''~ ~F~ '~ 4~
~~' r9~? '
x' ~
' S'
' ~
t ~,y
o~ l?W'ezcoal; ~~ W .VSS
S2 a, w i }s?
::..o:?.. ..r ::.%Y :~',i
~ '. C : ~ :c r .r' ~~. tir~~.~?~
Wa _ .. ..s: '2 ~.?
' ..::af~:. ~. r.
~ ..yfo..: . ~ ~.
_?li'i.: ' _ .y,::;,'/'i(~ ...
':~%.F. . Z : ;
~~..SFarF,.. , p .
~ .. ~ '
~ ,:...,, ~
~kyxiY~~ ~
~~
~
:
:
.
'
...
..
: . ..
ZS ~:. i . .~% a:.:~ _.r
~:: .f.:; . y~
uv.\ , :: ::::h,
v:J%V.ww:..:: .;~ : r::
.W ~'.::.3..~ t: F ~ ::.j.
i:v;; ...~'. : ...:
:;: ..'. ?. z
.. ..: . . . ':
:..::r:::.:~... .......:
.. a\:~:.'.?. .:% : ::. ~''
.:
t%::r.;::;:_-;. ... ..<w?
:. r. ':St
:..,,~ ......... : ;
:::::%::::::, .. ..
~ ':S: '
..... ............ a~ .'.:?i . . ..i
... . . R N:,?~....... . i. ~:
:;'y~.:a...L.c::: .fb'
.,r.... >7: ~ :::;,;... :~:v
.....~a:.......,:??v:'% .:...,.::...:.::.,..::. :u: . . : . .
:...:..:.;. . ,_ ::
...;;..".,r.:..........:~:::.:.............,......5:..........:i.:y..F?
.,.,.5~?)f...:.~~~~...f.'~<.vF.;.
....... ,'.~:
.......... r.;~.v
':.
....
w:.
.:
,........
..2...
.
~::.
...:...
.:....:
......,.Fs..........:7~..
.,.5>K.>.<:....
11 448 (50 1,650 219 11.9 139 18
prig)
I2 448 (50 I,750 185 9.19 190 20
psig)
Exam_yles 13-1$ show the performance of polyamide-polyether membranes exposed
to gas
mixtures under a variety of conditions.
Ex ie
A composite membrane was prepared by coating a layer of a polyamide-polyethcc
copolyrrxr
TM
(Pebax grade 4011) onto n polyvirtylidene fluoride (PVDF) support membrane
using the same g~naal
techniques as in Example 11. The membrane was tested with a two-component gas
mixture c~taining
< <. r, r,- ~ ; 1,7 4 3 41
~WO 95/11739 PCT/US94/12100
27
4 vol% carbon dioxide, 96 vol% methane at three different feed pressures:
2,807 kPa
(392 psig), 4,165 kPa (589 psig) and 6,724 kPa (960 psig). In all cases the
permeate side of the
membrane was at, or close to, atmospheric pressure and the membrane was at
room temperature (23 ° C).
The penmeation results are listed in Table 3.
Example 14
The same type of membrane as in Example 13 was prepared and tested with a two-
component gas
mixture consisting of 970 ppm hydrogen sulfide, 99.9 vol% methane at three
different feed
pressures:2,779 kPa (388 psig), 4,159 kPa (588 psig) and 6,793 kPa (970 psig).
In all cases the permeate
side of the membrane was at, or close to, atmospheric pressure and the
membrane was at room temperature
(23 °C). The permeation results are listed in Table 3.
Example 15
The same type of membrane as in Example 13 was prepared and tested with a
three_component
gas mixture consisting of 870 ppm hydrogen sulfide, 4.12 vol% carbon dioxide
and
95.79 vol% methane at three different fend pressures: 2,765 kPa (386 psig),
4,165 kPa (589 psig) and
6,821 kPa (974 psig). In all cases the permeate side of the membrane was at,
or close to, atmospheric
pressure and the membrane was at room temperature (23 °C). The
penmeation results are listed in Table
3.
Example 16
The same type of membrane as in Example 13 was prepared and tested with a
three-component
gas mixture consisting of 0.986 vol% hydrogen sulfide, 4.12 vol% carbon
dioxide and 94.90 vol%
methane at three different feed pressures: 2,786 kPa (389 psig), 4,145 kPa
(586 psig) and 6,800 kPa
(971 psig). In all cases the permeate side of the membrane was at, or close
to, atmospheric pressure and
the membrane was at room temperature (23 °C). The permeation results
are listed in Table 3.
Example 17
The same type of membrane as in Example 13 was prepared and tested with a
three_component
gas mixture consisting of 1.83 vol% hydrogen sulfide, 10.8 vol% carbon dioxide
and 87.34 vol% methane
at a feed pressure of 6,759 kPa (965 psig). The permeate side of the membrane
was at, or close to,
atmospheric pressure and the membrane was at room temperature (23 °C).
The permeation results are
listed in Table 3.
xam le 18
The same type of membrane as in Example 13 was prepared and tested with a
three-component
gas mixture consisting of 950 ppm hydrogen sulfide, 8.14 vol% carbon dioxide
and
CA 02174341 2004-04-19
75136=9
28
9L77 vol% methane at three diffcrcrtt fled pressures: 2,800 kPa (391 psig),
4,138 kPa (585 psi~ and
6,793 kPa (970 psig). In all cases the permeate side of the membrane was at,
or close to, atmospheric
prGSSiac and the membrane was at room temperature (23 ° C). The
permeation results are listed in Table
3.
TABLE 3
Permeation Properties of a Pebax~ 401 I Composite Membrane
with Various Food Gas Compositions at Thret Feed Pressures
x ' ...~:':.'>' .: ?~,~.,.:~b. ,.°'~ . . :ri'a ., ~ ~.: .#~'w..~ s' ,
y. ~_ ~"lennx'~~'i#',
~':.~1&~f~...c..: >r05 r~ <: ~ TA o-
:: ~,>': .:. . ..: i». :: :: :. . '~.u.~. . ':'x:.. %:x ..5:~ ~ 6..:.'. ,t.,<.
: f:;.p~y.,~~y.;:~' .. ':~:srR::: ' ~ :~ ,~q , .
c;:in.. ..~';'.;.::...:.,.., t ..eo-., :..~ :a! ..k1 : _ n. , ~ _.
::~-'~ .. .. it : ".fi' ~. ~F :.
~:2:._ 'qty .!;~....;::..'.\.,,t: : .. 't. :.:
},a .,.>:~ ~~a.~ S
::..:.~lCr::..:., :.. : . . . .:'a~ ::.; .:...:::.: C~~ ) ~~:,;, ::.... .: ..
~ .: , .: . . . ;.
.'~Y~' 'A. 'x:n..'Tti:<'.fkk:
S -:i>."~
.;~ ,Si
~.::Mn:/'
iy: , v~
,.W
".'~~ .'
:_X .,S n
~i::~;
'j: "'.,..' .:.:2k~ '':t
.: ~ ;:
5....
ta~:Y... 'r'' Y .':,
1. s'N ' '.r~'n . .5:. : n
.. .:
:, x...... °', ~,Y ~' ~'~'
: :: ..a~ ,:.~.w.4: .
..... ..
1 ':..<::~1...........
.::.''': . ;;:. :..
,.. :...:: ~ .:.::
~i
.:~.~.. X
n%a~... .i .(?'c.. _ ~ 2. '' .
v. :.'.\ _.
:: vv-s~
. . r~:,:.::y . '~'.. .. .::>. -~ ~~ :~'.r''c.: ::
.,. $:,:..,.. ..: . :~. ,.',a~ . .. :. a.~..... '"':.w.'...':... :'y: :.::.
a...... ;.: s ve': ~..
:,. ~.:..~,~:-:;h<.... S~.~. ~C .. >. .. . .CN .. :..~W
..:.~.::. ~? v o S .
s -~.au~o .~ ~Y a.<: sax ~< .. ,'. ~<~ ~~~~'' 1$ 3,~ '~4" 't"~'xi~ . st ~h<
f~r~ :.:~
S, .... x .,<.~~~.. ~. r. :.;~."~ ~ . < w . ~ .,.,.: :~.e.sr~,l~'~ ., ...; ,~.
..
'x.~:~~xs rxx ~::;x
2,807 (392 prig) - 31 1.9 - 17
13 4,165 (589 psig) - 30 1.9 - 16
6,724 (960 psig) - 29 2.0 - 15
2,779 (388 psig) 91 - 1.8 5t
15 14
4,159 (588 psig) 74 - 1.8 41
6,973 (970 psig) 73 - 1.8 41
2,765 (386 psig) 140 31 1.9 70 16
4,165 (589 psig) 115 30 2.0 Sb 15
6,821 (974 psi ) I 10 29 2.2 52 14
2,786 (389 psig) 113 32 2.0 55 16
16
4,145 (586 psig) 103 31 2.0 51 15
6,800 (971 psig) 97 29 2.0 48 14
17 6,739 (965 prig) 121 34 2.4 50 14
2,800 (391 prig) 93 26 1.6 58 16
18 _ _
4,138 (585 psig) 108 32 2.0 52 15
~- , 6,793 (970 psig) ! 93 ~ 28 i 1.9 48 14~
The following observations can be made from the data of Examples 13-18:
1 _ The prcsa~ce of carbon dioxide in the food gas appears to increue the
fluxes of both hydrogen
sulfide and nx;thanc through the membrane. Far example, a comparison oC the rr-
salts of Exampk 14, in
which the food micame did not contain any carbon dioxide, with those of
Examples IS-18, shows that the
CA 02174341 2004-04-19
75136-9
29
hydrogen sultide !)axes are about 25% Iowa and the methane fluxes are about
15% lower in Example 14.
The increased flux may be due to swelling of the manbrane by dissolved carbon
dioxide.
2, In general, the pressure-normalizod fluxes of hydrogen sulfide and carbon
dioxide decrease
with inaeasing feed pressure, whereas those of methane increase. The decrease
in the hydrogen sulfide
and carbon dioxide fluxes may be due to compciitivc sorption, which results in
a lower solubility
coe~cient (the ratio of concenaation in the polymer to partial pressure) for
each component. At the sane
time, the polymer swells, rauiling in a higher diffusivity for all components,
including methane. The net
result is an increase in the methane ilaK and a decrease in the fluxes of the
acid gases (hydrogen sulfide
and carbon dioxide).
3. The hydrogen sulfiddmcthane scicctivity for three-component mixtures varies
from a low of
48 to a high oC70, although all of the measura>ients were made at fairly high
feed prcssurcs. The carbon
dioxidclmethane selectivity, also at high pressure, is about 14-16.
Example 19. Gas streams containing water vapor
The trpaiments oCExamplc 15 were rapeatod using Toed gas streams saturated
with water vapor
i 5 by bubbling the fend gas through a water reservoir. The acpaiments were
carried out at food prasures
of 2,772 kPa (387 psig), 4,159 kPa (588 psig) and 6,793 kPa (970 psig). The
pctmcate side of the
membrane was at, or close to, atmospheric pressure and the membrane was at
room icmperature (23 °C).
The permeation results are listed in Table 4.
TABLE 4
Permeation Properties of Pebax 4011 Composite Membranes Tested
with Water-Sattuatod Gas Mixtures
~\ ~\Ci :G-' ~~'o fov y,,~. -aC' '.'-
-:. ~<1 Y.\': f".6 ~. . . < ~..'
1 ~ ~ ' .Ct ~.~~. T:;~~rf
? .'?'~ ~ '
~.. ~
r
5
~
'S
, ~ahxrd Flu~c ,
.' .. . : xv0s . : ~rlembtvattaw.c
~ .~,.: . . lecti: .
. ': . .yg:
n , .
:; .
Fccd ..:.
.
': s s.
.
.
;ssf :::
.
,.
,
,
:.
'
. :. r. . W
..:<4. . . a~\ ..
\\'a.,~ > ..T > :
.fi.:;~H r ice. ~;;>:c: ..~~ K
~ ..:." ..G . .~ ' : ..
x.'; . ' ' :k~'.~: Fy .. r4
,: ~:. ~r 1. '
~e rnrtt $ ~~~~~
; r Yfc ~.'
: :~~ : ' - M
:. \,:.. ~ B:~
'. ,.:7!..>.~...f:\ ~f
:: . ~
..~..:~W
a.:~:..a~~?:
x'
\ "~,:.i
~ ~~~
Fw . : ,
;: : ~ : :
s S?:,.1''..,.,;s~e~,.-~.~i,..x:;,'s:"~....
,.s;N..:.:~..~~~'~:~ ~ .; ,yC
:::::::;J:::::.:>:~: :a . .. .:.,.~ :. :;~'~,....,.~.,::
.. ..~ ..,..,~: . ?:..,
:: v!v,,~: ;;.; :F9..H 2.
:~ , i... ... k...~~:i..~; i
~.:o,.::~:o::::::;:. . .~f#.'.
:: i? . ~ .
;.,.. :n~... . y:::i. y. .:..sR ~.'~>4.~
.: :>:..:.., >v'~~' ~i,.
~......;...:..:...., . ~::i .. :~33~.?~..,..
............::$: .:.. . ~.. :..
n. .C. .,.: :~ :. .. ::.~.:. . ./!;'.
;. ........ ... : ':~? ,
p.. ..7.. ~ . ' :'<:,
. . :~.: .. .. . ' .... ' .. (:
...f.. ..;;.;.Y :%:::::::~ . .:,i. .
::'o:':'c::.c::..::.... f 2 . :.:.:::.. : :
.. .. :' .. .. . :. . . .. ..
......,.::.'?:f n ' : .:: .. ...
~: . . te
. :..s s
. :.~', ,. '
r .., ~
Y. ~ ~
..r..... ~ ?
r.
:..y
.::::
.
..,
~
~5
:~fs:;:;:?. ' ,
.:::i'v:, . . ' :~(3"~:...
iy4,i.'S:, . ,. .. :
\ ... . ~ . ! :
v. : , .. , n1 '
.:...::.. i,'~,in'.'Y . .... ~: : ~ .
:..;,.... iYF .:...:'?..! '..
....\.. .. ~. ._ f ~~ . .~
. v . . . .
. :::::r:a i::.:
~~. x::> :..::> ..:. '
' .. : F
. ..::R..ia.. . iS
' :.,s.._:; :Y "' ~
' Y ~ :
.. M..v'.. ' ; '
" _. ;'~:::\' '
w: ~-S~'' ~'
.; .~ t~s ~~
~ . ~:YS,~~i ~
.~. ; .~c>.
x~, ....
;.... ..::.:,
", .:.rt>-~.,?.
;...
.3W....:
>
;-s..
0
:i::
:
.... . . .
. :: : .
:.. y .. . , .
k . :.
.,a r: ,r :..,>;':,..
.:::;;......R....a :~.::::.:. . :
5, r i .:
.::: ~..:n: ;: ':~f';;i:a:-X::
:':";,:..: ..... ;;n ,-:.: . '' :df~ ?
.. .. .:..is?'...... . .,.a;~ '.
: x::: . . . .. .. . ".xi~
... .....~.... . ......r::', ~~ : :>.~
. ........::... :v"%.. .i0..u..y ~.
. . ...v .:x: . 25..:3i.
f.
2,772 (387 77.0 18.9 1.03 ?4.9 18.4
psig)
I9
4,159 (588 73.5 20.1 1.20 61.4 16.9
psig)
b,793 (970 68.6 18.1 1.17 58.8 15.5
psig)
Comparing these results with those of Table 3, it can be seen that the fluxes
are considerably
lower (about 40-45°/. lower) than those obtained in the absence of
water vapor. Neither the hydrogen
sulfrdeJrnetharte nor the carbon dioxidrhn«hane scbctivitics, howevsr, change
significantly. Furthermore,
whrn the membranes were retested with a dry gas strew the fluxes returned to
the original values.
w-.v-<<vw~~ 274341
WO 95111739 PCT/US94112100
SET 3
Examples 20-24 show calculations of the performance of representative membrane
processes
using the more hydrogen-sulfide-selective membrane only. Any of these could be
combined with
additional non-membrane treatment of the residue or permeate streams.
5 Example 20
A very simple one-stage membrane process was designed to handle a gas stream
containing
100 ppm hydrogen sulfide, 0.1 vol% water vapor, 4 vol% carbon dioxide and the
remainder methane, at
a feed pressure of 6,897 kPa (1,000 psia). A basic schematic of the process is
shown in Figure 2, where
numeral 1 indicates the bank of membrane modules, and the feed, residue and
permeate streams are
10 indicated by numerals 2, 3 and 4 respectively. The process was assumed to
use one bank of more
hydrogen-sulfide-selective membranes having the following characteristics:
Hydrogen sulfide/methane selectivity: 80
Water vapor/methane selectivity: 1,000
Carbon dioxide/methane selectivity: 12
20
Methane flux: 1 x 10'~ cm'(STP)/cm2~s~cmHg
The compositions and slow rates of the permeate and residue streams were
calculated and are
given in Table 5.
TABL E 5
STREAM FEED RESIDUE PERMEATE
Flow rate (Nm'/min) 28.3 (1,000 25.6 (903 2.7 ( 97 scfm)
scfm) scfm)
CH4 conc. (vol%) 95.9 98.1 75.6
COZ conc. (vol%) 4.0 1.9 23.2
HZS conc. (ppm) 100 ~ 4 995
Water vapor conc. (vol%)0.1 2 ppm 1.0
The membrane area used to perform such a separation was calculated to be about
70 m2. The
stage cut was just under 10% and the methane loss into the permeate was 7.5%.
The process produces
a residue stream that simultaneously meets pipeline specification for carbon
dioxide, hydrogen sulfide and
water vapor. The low grade permeate gas could be sent to the foul gas line.
xample 21 ~
The simple design of Example 20 is only possible for certain cases where the
raw stream to be
. . treated contains an appropriate balance of hydrogen sulfide and carbon
dioxide. In many cases, a more
WD 95/11739 ; ~~ ~ ~-'
s 21 ~ 4 3 ~ ~ PG"T/US94/12100
31
complicated, optimized design is needed to improve the methane recovery and
meet pipeline specifications
without overprocessing.
A process was designed to handle a 28.3 Nm'/min (1,000 scfm) gas stream
containing
1,000 ppm hydrogen sulfide, 0.1 vol% water vapor and the remainder methane, so
as to keep methane loss
in the permeate stream below 2%. The process uses a two-stage membrane
separation system in which
the permeate from the first bank of membrane modules becomes the feed for the
second bank. A basic
schematic of the process is shown in Figure 5, where numeral 10 indicates the
first stage bank of
membrane modules and numeral 18 indicates the second stage bank of membrane
modules. The incoming
gas stream 9 is at 6,897 kPa (1,000 psia) and is mixed with the residue stream
20 from the second stage
to form the feed gas stream 21 to the first membrane stage. The permeate
stream 12 from the first stage
is mcompressed to 6,897 kPa (1,000 psia) in compressor 13. The compressed
stream 14 passes to chiller
15, where water vapor is condensed and water is removed as liquid stream 16.
The non-condensed stream
17 enters the second membrane stage 18, where further separation of hydrogen
sulfide takes place. The
residue stream from this stage is recirculated within the process. Both
membrane stages were assumed
to use more hydrogen-sulfide-selective membranes having the following
characteristics:
Hydrogen sulfide/methane selectivity: 50
Water vapor/methane selectivity: 1,000
Methane flux: 7.5 x 10~ cm'(STP)/cmz-s-cmHg
The compositions and flow rates of the first and second stage permeate and
residue streams were
calculated and are given in Table 6.
~reur~c
STREAM FEED RESIDUE PERMEATE
FIRST STAGE
Flow rate (Nm'/min)34.0 (1,200 27.9 (985 6.1 (215 scfm)
CH4 cone. (vol%) scfm) scfm) 98.99
99.82 99.99
Water vapor conc. 0.08 0.0 0.45
(vol%)
H2S conc. (vol%) 0.10 4 ppm 0.55
SECOND STAGE
Flow rate (Nm'/min)6.1 (215 scfm)5.7 (202 scfm)0.4 (13 scfm)
CH,, conc. (vol%) 99.42 99.89 92.12
Water vapor conc. 330 21 5,015
(ppm)
HZS conc. (vol%) 0.55 0.1 7.4
~' r e' a '' ' ~ 2 ~ l 4 3 41 pCT~S94/12100
WO 95111739 . . .
32
The membrane area used to perform such a separation was calculated to be about
280 m2 total,
265 m2 in the first stage and 1 S m2 in the second stage. The residue stream
11 from the first stage meets
pipeline specifications. The permeate stream 19 from the second stage contains
a high enough
concentration of hydrogen sulfide to be Passed to a Claus plant foc sulfur
recovery unit, or to a liquid redox
process, such as LO-CAT, Sulfemac, Hypeaion or Strotfard The overall methane
loss into the second stage
permeate is very low, at just about 1%.
~ple 22
A process was designed to handle a 28.3 Nm'lmin (1,000 scfm) gas stream
containing
1,000 ppm hydrogen sulfide, 4 vol% carbon dioxide and the remainder methane.
The process uses a two
stage membrane separation system in which the permeate from the first bank of
membrane modules
becomes the feed for the second bank. The process schematic is as shown in
Figure 5, except that no
condenser 15 is used. Numeral 10 indicates the first stage bank of membrane
modules and numeral 18
indicates the second stage bank of membrane modules. The incoming gas stream 9
is at 6,897 kPa
( 1,000 psia) and is mixed with the residue stream 20 from the second stage to
form the feed gas stream
21 to the first membrane stage. In this case, the permeate stream 12 from the
first stage as recompressed
to 6,897 kPa (1,000 psia) in compressor I3, then passed without any
condensation taking place as
compressed stream 17 to the second membrane stage 18, where further separation
of hydrogen sulfide
takes place. The residue stream from this stage is rccirculated within the
process. Both membrane stages
were assumed to use more hydrogen-sulfide-selective membranes having the
following characteristics:
Hydrogen sulfide/methane selectivity: 50
Carbon dioxide/methane selectivity: 13
Methane flux: 7.5 x 10'~ cm'(STP)/cmZ~s~cmHg
The c~npositions of the first and second stage permeate and residue streams
were calculated and
are given in Table 7.
CA 02174341 2004-04-19
75136=9
33
TABLE 7
STREAM FEED RESIDUE PERMEATE
FIRST STAGE
Flow rate (Nm'Imin)34.6 (1,220 27.3 (964 7.3 (256
scam) sefm) scam)
CH, coot. (vol%) 93.0 98.86 71.8
CO= coot. (vo1/.)G.9 1.14 28.3
H,S cone. (ppm) 1,000 4 4,733
SECOND STAGE
Flow talc (Nm'/min)7.3 (25G scfm)G.2 (220 1.1 (3G
scfm) scfm)
CH, coot. (vol%) 71.8 80.0 19.6
CO, coot. (vol%) 28.3 19.9 77.7
H,S cone. (voP/o)0.47 0.1 2.7
The membrane urea used to perform such a separation was calculated to be about
244 m' total,
232 m~ in the first stage and 12 ms in the second stage, The residue stream 11
from the first stage moots
pipeline specifications. The permeate stream 19 from the second stage contains
a high cr~tgh
oancattration of hydrogen sutlde to be passod to a Claus plant far sulfur
rocovery unit, or to a liquid re~oc
process, such as LO-CAT, Sulfcroc, Hyperion or Stn:tford. The overall methane
loss into the second stage
permeate is very low, at about 0.7°/..
Example 23
The calculations of Example 22 were repeated with a 28.3 I3m'/cnin (1,000
scfm) gas stream
containing 10,000 ppm hydrogen sulfide, 4 vol% carbon dioxide and the
remainder methaae. The results
arc given in Table 8.
~~ 7~3~-1
WO 95!11739 ' ' PCTIUS94/12100
+~ ~ _.
34
TABLE 8
STREAM FEED RESIDUE PERMEATE
FIRST STAGE '
Flow rate (Nm'/min)37.7 (1,330 26.9 (950 10.8 (380 scfm)
scfm) scfm)
CHI conc. (vol%) 91.0 99.4 70.0
COZ conc. (vol%) 8.0 0.6 26.5
HZS conc. (ppm) 10,000 4 3.5 vol%
SECOND STAGE
Flow rate (Nm'/min)10.8 (380 sefm)9.4 (330 scfm)1.4 (50 scfm)
CH, conc. (vol%) 70.0 78.6 16.2
COZ cone. (vol%) 26.5 20.4 64.6
HzS conc. (vol%) 3.5 1.0 19.2
The membrane area used to perform such a separation was calculated to be about
353 m2 total,
339 m2 in the first stage and 14 m2 in the second stage. The residue stream 11
from the first stage meets
pipeline specifications. The permeate stream 19 from the second stage contains
a very high hydrogen
sulfide concentration. The methane loss is less than 1%.
Examples 21-23 illustrate the benefits of two-stage processes in both reducing
methane loss and
raising the hydrogen sulfide tration of the waste stream. In Examples 21-23,
the feed composition,
both raw and after mixing with recycle stream 20, is in zone B.
Example 24
A process was designed to handle a 28.3 Nm'/min (1,000 sefm) gas stream
containing
1,000 ppm hydrogen sulfide, the remainder methane. The process uses a membrane
separation system as
shown in Figure 8. Numerals 38, 44 and 47 indicate the three banks of membrane
modules: all contain
the more hydrogen-sulfide-selective membrane. The incoming gas stream 36 is at
6,897 kPa (1,000 psia)
and is mixed with the residue stream 49 from modules) 47 to form the feed gas
stream 37 to the first
membrane stage. The permeate stream, 40, from the first stage is recompressed
in compressor 42.
Compressor 42 drives two membrane units, the second stage unit, 44, and an
auxiliary module or set of
modules, 47, that are connected on the permeate side either directly or
indirectly to the inlet side of the
compressor, so as to form a loop. Thus, permeate stream 48 may be merged with
permeate stream 40 to
fpm c~nbined stream 41. The recompressed; combined stream, 43, passes as feed
to membrane unit 44,
and the residue stream, 46, from membrane unit 44 passes as feed to membrane
unit 47. Permeate is
a ~, ~ ~ :, ~ t'. r
WO 95/11739 PCT/US94/12100
35 2114341
withdrawn from the loop as stream 45 and the treated residue exits as stream
39. This system
configuration is particularly useful in situations where the hydrogen sulfide
content of the raw stream is
relatively low, yet flaring is not an option and the stream has to be brought
up to a viable concentration
for sulfur recovery. A series of calculations was carried out by keeping the
area of membrane unit 38
constant, but varying the relative areas of membrane units 44 and 47. The
characteristics of the membrane
were assumed to be as in Example 22. The results of the calculations are given
in Table 9.
TABLE 9
Membrane Permeate conc
Area
(m2)
.
Unit Unit 44 Unit 47 Total (vol%)
38
242 0 18 260 2.65
242 10 11 263 4.26
242 15 8 265 5.77
242 20 6 268 8.92
242 35 2 279 19.7
242 50 0.4 292.4 55.0
The residue stream 39 from the fu~t stage meets pipeline specifications. A
high concentration of hydrogen
sulfide in the waste permeate stream can be achieved with an appropriate
choice of membrane areas.
This type of design could also be used in situations where combinations of the
two membrane
types are indicated.
ET 4
Examples 25-28 deal with streams in which the feed composition is in zone D,
so that a
combination of membrane types is indicated. Again, any of these membrane
processes could be combined
with a non-membrane treatment of the residue and/or permeate streams.
Example 25
A process was designed to handle a 28.3 Nm'/min (1,000 scfm) gas stream
containing 60 ppm
hydrogen sulfide, 15 vol% carbon dioxide and the remainder methane, a
composition that falls in Zone D
of Figure 1, but close to the boundary between zones C and D. The process uses
a membrane separation
system as shown in Figure 7. NurneraLs 23, 26 and 32 indicate the three banks
of membrane modules; 23
contains the more hydrogen-sulfide-selective membrane; 26 and 32 contain the
more carbon-dioxide-
selective membrane. The incoming gas stream 22 is at 6,897 kPa (1,000 psia)
and is mixed with the
residue stream 34 from the second stage to form the feed gas stream 35 to the
first membrane stage. The
2174341
WO 95111739 PCT/US94/12100
-a g ;~ 36
-.
residue stream, 24, from the first bank of modules passes as feed to the
second bank of the first stage, 26.
In this case, the permeate streams 25 and 28 from the two steps of the first
stage are combined as stream
29 to be re~npressed in compressor 30, then passed as compressed stream 31 to
the second membrane
stage 32. It will be apparent to those of ordinary skill in the art that two
separate compressors could be
used and the stream combined after compression. Also, in cases where the
stream to be treated contains .
water vapor, the system could include a condenser as in Figure 5 to condense
permeating water vapor.
The composition of stream 31 was in Zone C, so that the more carbon-dioxide-
selective membrane was
chosen for the second stage. The characteristics of the two types of membrane
were assumed to be as
follows:
More hydrogen-sulfide-selective membrane:
Hydrogen sultide/methane selectivity: 50
Carbon dioxide/methane selectivity: 13
Methane flux: 7.5 x 10'~ cm'(STP)/cmz~s~cmHg
More carbon-dioxide-selective membrane:
Hydrogen sulfide/methane selectivity: 25
Carbon dioxide/methane selectivity: 20
Methane flux: 7.5 x 10'~ cm'(STP)/cmz~s~cmHg
The compositions of the various streams were calculated and are given in Table
10.
Stream CH, conc. (vol%)HZS conc. (ppm)COz cone. (vol%)
#
22 85.0 60 15.0
35 84.0 60 16.0
24 90.2 10 9.8
27 98.0 1 2.0
25 36.1 456 63.9
28 52.3 51 47.7
31 45.5 223 54.5
33 7.5 407 92.5
34 78.6 60 21.4
TABLE 10
,~,rf~.; ~'.
~WO 95/11739 21 T 4 3 41 p~~S94/12100
37
The membrane areas required were as follows: 66 m2 for membrane 23, 120 m2 for
membrane 26 and 22
m2 for membrane 32. The residue stream 27 from the first stage meets pipeline
specifications. The
permeate stream 33 from the second stage contains about 400 ppm hydrogen
sulfide and the overall
methane loss is about 1%.
xam le 26
A process was designed to handle a 28.3 Nm'/min (1,000 scfm) gas stream
containing 200 ppm
hydrogen sulfide, 15 vol% carbon dioxide and the remainder methane, a
composition that falls in Zone D
of Figure 1. The process uses a membrane separation system as shown in Figure
7. Numerals 23, 26 and
32 indicate the three banks of membrane modules; 23 and 32 contain the more
hydrogen-sulfide-selective
membrane; 26 contains the more carbon-dioxide-selective membrane. The incoming
gas stream 22 is at
6,897 kPa ( 1,000 psia) and is mixed with the residue stream 34 from the
second stage to form the feed gas
stream 35 to the first membrane stage. The residue stream, 24, from the first
bank of modules passes as
feed to the second bank of the first stage, 26. As in Example 25, the permeate
streams 25 and 28 could
be combined before or after recompression, and a condenser to remove water
vapor could be included.
1 S The characteristics of the two types of membrane were assumed to be as
follows:
More hydrogen-sulfide-selective membrane:
Hydrogen sulf ide/methane selectivity: 50
Carbon dioxide/methane selectivity: 13
Methane flux: 7.5 x 10'~ cm'(STP)/cm2-s~cmHg
More carbon-dioxide-selective membrane:
Hydrogen sulfide/methane selectivity: 25
Carbon dioxide/methane selectivity: 20
Methane flux: 7.5 x 10'~ cm'(STP)lcm2~s~cmHg
The compositions of the various streams were calculated and are given in Table
I 1.
1 X4341
WO 95111739 ' '', ' ~ 'Y ~ ;~' PCT/US94/12100
38
TABLE 11
Stream # CH, conc. (vol%) H2S cane. (ppm)C02 conc. (vol%)
22 85.0 200 15.0
35 64.0 200 36.0
24 68.0 130 32.0
27 98.0 4 2.0
25 13.2 1,443 86.7
28 26.7 294 73.3
31 25.2 427 74.8
33 3.0 1,447 97.0
34 29.9 200 70.1
The membrane areas required were as follows: 21 m2 for membrane 23, 248 m2 for
membrane 26
and 17 m2 for membrane 32. The reside stream 27 from the first stage meets
pipeline specifications. The
permeate stream 33 from the second stage contains about 1,500 ppm hydrogen
sulfide and the overall
methane loss is about 0.4%. The feed stream to the second stage bank of
modules, 32, contains 427 ppm
hydrogen sulfide and 75 vol% carbon dioxide, a composition that falls in the
more carbon-dioxide-
selective membrane zone of the zone diagram. However, since it is not required
to meet pipeline
specification for the residue stream from the second stage, an optimized
design provides better hydrogen
sulfide recovery if the more hydrogen-sulfide-selective membrane is used.
Example 27
A process was designed to handle a 28.3 Nm'/min (1,000 sefm) gas stream
containing 1,000 ppm
hydrogen sulfide,15 vol% carbon dioxide and the remainder methane, a
composition that falls in Zone 1)
of Figure 1, but close to the boundary of Zone B. The process uses a membrane
separation system as
shown in Figure 7. Numerals 23, 26 and 32 indicate the three banks of membrane
modules; 23 and 32
contain the more hydrogen-sulfide-selective membrane; 26 contains the more
carbon-dioxide-selective
membrane. The incoming gas stream 22 is at 6,897 kPa (1,000 psia) and is mixed
with the residue stream
34 from the second stage to form the feed gas stream 35 to the first membrane
stage. The residue stream,
24, from the first bank of modules passes as feed to the second bank of the
first stage, 26. As in Examples
25 and 26, the permeate streams 25 and 28 could lx combined before or after
recompression, and a
condenser to remove water vapor could be included. The characteristics of the
two types of membrane
"';~ '~ ~~. ~ ~ 2174341
WO 95/11739 PCT/US94/12100
39
were assumed to be as follows:
More hydrogen-sulfide-selective membrane:
Hydrogen sulfide/methane selectivity: 50
Carbon dioxide/methane selectivity: 13
Methane flux: 7.5 x 10'~ cm'(STP)/cm2-s-cmHg
More carbon-dioxide-selective membrane:
Hydrogen sulfidelmethane selectivity: 25
Carbon dioxide/methane selectivity: 20
Methane flax: 7.5 x 10~ cm'(STP)/cmz~s-cmHg
The compositions of the various streams were calculated and are given in Table
I2.
TABLE 17
Stream CHI cone. (vol%)HZS cone. COZ cone. (vol%)
# (ppm)
22 84.9 1,000 15.0
35 63.9 1,000 36.0
24 79.7 70 20.3
27 98.0 4 2.0
17.0 3,770 82.7
28 37.4 221 62.6
25 31 26.6 2,084 73.2
33 3.1 7,390 96.2
34 31.5 1,000 68.4
The membrane areas required were as follows: 119 mz for membrane 23, 188 m2
for membrane
2G and 17 m2 for membrane 32. The residue stream 27 from the first stage meets
pipeline specifications.
The permeate stream 33 from the second stage contains about 0.7 vol% hydrogen
sulfide and the overall
methane loss is about 0.4%.
As with Example 25, an optimized design uses the more hydrogen-sulfide-
selective membrane for the
second stage.
.. ' ~' 2 ~ 7 4 3 41 pCT/US94/121()0
WO 9SI11739
~,Xample 28
A process was designed to handle a 28.3 Nm'/min ( 1,000 scfm) gas stream
containing 100 ppm
hydrogen sulfide, 4 vol% carbon dioxide and the remainder methane, a
composition that falls in Zone B
of Figure 1, but so close to the bouc~dary of Zone D that the composition is
just within Zone D after mixing
5 with the recycle stream from the second membrane stage. The process uses a
membrane separation system
as shown in Figure 7. Numerals 23, 26 and 32 indicate the three banks of
membrane modules; 23 and 32
contain the more hydrogen-sulfide-selective membrane; 26 contains the more
carbon-dioxide-selective
membrane. The incoming gas stream 22 is at 6,897 kPa (1,000 Asia) and is mixed
with the residue stream
34 from the second stage to form the feed gas stream 35 to the first membrane
stage. The residue stream,
10 24, from the fast bank of modules passes as feed to the second bank of the
first stage, 26. As in Examples
25-27, the permeate streams 25 and 28 could be combined before or after
recompression, and a condenser
to remove water vapor could be included. The characteristics of the two types
of membrane were assumed
to be as follows:
More hydrogen-sulfide-selective membrane:
15 Hydrogen sulGde/methane selectivity: ~0
Carbon dioxide/methane selectivity: 13
Methane flux: 7.5 x 10'~ cm'(STP)/cm2~s~cmHg
20 More carbon-dioxide-selective membrane:
Hydrogen sulfide/methane selectivity: 25
Carbon dioxide/methane selectivity: 20
25 Methane flux: 7.5 x 10'~ cm'(STP)/em2~s~cmHg
The compositions of the various streams were calculated and are given in Table
13.
:- . ~. 2I 74341
~V0 95/11739 ~ w '- ' ' PCT/US94/12100
41
TABLE 13
Stream CH4 cone. (vol%)HZS cone (ppm)COZ cone. (vol%)
#
22 96.0 100 4.0
35 94.0 100 6.0
24 98.0 4 2.0
27 98.1 4 1.9
25 70.3 741 29.7
28 75.7 57 24.3
31 70.3 737 29.7
33 20.0 3,680 79.6
34 I 81.2 I 99 I 18.8
The membrane areas required were as follows: 131 mz for membrane 23, 1 m2 for
membrane 26 and 9 m2
for membrane 32. The residue stream 27 from the first stage meets pipeline
specifications. The permeate
stream 33 from the second stage contains about 0.4 vol% hydrogen sulfide and
the overall methane loss
is about 0.5%.
xam le 29
Example 29 also deals with streams in which the feed composition is in zone D,
so that a
combination of membrane types is indicated, but in this case a simple, one-
stage, two step, membrane
process is used. The gas stream was assumed to contain 100 ppm hydrogen
sulfide, 10 vol% carbon
dioxide,1,200 ppm water vapor and the remainder methane, at a feed pressure of
6,897 kPa (1,000 psia).
The process uses a combination process design as in Figure 6, where numeral 23
indicates a more
hydrogen-sulfide-selective bank of membrane modules and numeral 26 indicates a
more carbon-dioxide-
selective bank of membrane modules. The incoming gas stream 22 is at 6,897 kPa
(1,000 psia). The
residue stream 24 from the first bank of modules forms the feed to the second
bank.
The more hydrogen-sulfide-selective membrane was assumed to have the following
characteristics:
Hydrogen sulfide/methane selectivity: 50
Water vapor/methane selectivity: 200
Carbon dioxide/methane selectivity: 13
Methane flux: 7.5 x 10'~ cm'(STP)/cmZ~s~cmHg
The more carbon-dioxide-selective membrane was assumed to have the following
characteristics:
n a ~'; ;. '.'"
WO 95111739 ~ 2 ~ ~ ~ 3 41 PCT/US94/12100
42
Carbon dioxide/methane selectivity: 20
Hydrogen sulfide/methane selectivity: 25
Water vapor/methane selectivity: 200
Methane flux: 7.5 x 10'~ cm'(STP)/cm2~s~cmHg
The compositions and flow rates of the permeate and residue streams from each
bank of modules .
were calculated and are given in Table 14.
TABLE
14
STREAM ~ FEED ~ RESIDUE ~ PERMEATE
FIRST MODULE BANK
(more hydrogen-sulfide-selective
membrane)
Flow rate (Nm'/min)28.3 (1,000 25.5 (900 sefm)2.8 (101 scfm)
scfm)
CH4 conc. (vol%) 89.9 94.38 50.35
COZ conc. (vol%) 10.0 . 5.62 49.0
HZO conc. (ppm) 1,200 4 1.18 vol%
HZS conc. (ppm) 100 14 866
SECOND MODULE
BANK (more carbon-dioxide-selective
membrane)
Flow rate (Nm'/min)25.5 (900 scfm)23.0 (811 scfm)2.5 (88.7 scfm)
CHI conc. (vol%) 94.38 97.98 61.47
C02 conc. (vol%) 5.62 2.01 38.53
H20 conc. (ppm) 4 0 40
HZS conc. (ppm) 14 4 105
The total membrane area used is about 135 mz. Residue stream 27 from the
second stage meets
pipeline specification. If the permeate streams 25 and 28 from the two banks
of membrane modules are
pooled, the pemxate compositi~ is 507 ppm hydrogen sulfide, 44 vol% carbon
dioxide, 0.62 vol% water
vapor and 55.5 vol% methane. The methane loss in the pooled permeates is about
12%. This loss could
be reduced if the process were optimized.
SET 5
The examples in Set 5 show s~cific representative combinations of membrane and
non-
membrane treatment.
Example 30 Membrane plus scav~nrain~ process
A process was designod to handle a gas stream contammg 1,000 ppm hydrogen
sulfide, 0.1 vol%
water vapor, 4 vol% carbon dioxide and the remainder methane, at a feed
pressure of 6,897 kPa
WO 95/11739 t t~ ~ '' x~. 1 ~ 217 4 3 41 pCT~S94/12100
43
(1,000 psia). The process inclu~s a one-stage membrane separation step,
followed by a scavenging step
to bring the hydrogen sulfide concentration down further to 4 ppm. The
scavenging step could be carried
out using an iron sponge, for example. The process was assumed to use one bank
of more hydrogen-
sulfide-selective membranes having the following characteristics:
Hydrogen sulfidelmethane selectivity: 80
Water vapor/methane selectivity: 1,000
Carbon dioxide/methane selectivity: 12
Methane flux: 1 x 10~ cm'(STP~cmZ~s~cmHg
The compositions and flow rates of the permeate and residue streams were
calculated and are
given in Table 15.
TABLE 15
STREAM FEED RESIDUE PERMEATE
Flow rate (Nm'/min)2.8 ( 100 scfm)2.5 (90.3 scfm)0.3 (9.7 scfm)
CHI conc. (vol%) 95.8 98 74.9
COZ conc. (vol%) 4.0 1.9 23.1
H2S conc. (ppm) 1,000 40 990
Water vapor conc. 0.1 2 ppm 1.0
(vol%)
The membrane area used was calculated to be about 70 mz. The stage cut was
just under 10% and
the methane loss into the permeate was 7.6%. The process produces a residue
stream that meets pipeline
specification for carbon dioxide and water vapor, but needs further polishing
to remove hydrogen sulfide.
Example 31 Process includin amine plant for hyd--~ro yen sulfide removal
A process was designed to handle a gas stream containing 0.5 vol % hydrogen
sulFde, 20 vol%
droxide and the remainder' rr>ethar~, at a foetl pressure of 6,897 kPa ( 1,000
psia). The process uses
a one-stage membrane separation step to carry out a first separation of carbon
dioxide and hydrogen
sulfide, followed by an amine plant to bring the stream to pipeline
specification. The process was assumed
to use one bank of more hydrogen-sulfide-selective membranes having the
following characteristics:
Hydrogen sulfide/methane selectivity: 50
Carbon dioxide/methane selectivity: 13
Methane flux: 7.5 x 10'~ cm'(STP)/cm2~s~cmHg
The compositions and flow rates of the permeate and residue streams were
calculated and are
given in Table 16.
. . . ~ ... . ;-.
WO 95/11739 2 ~ 7 4 3 41 PCT/US94112100
44
TAALE 16
STREAM FEED RESIDUE PERMEATE
Flow rate (Nm3/min)28.3 (1,000 23.8 (840 scfm)4.5 (160 scfm)
scfm)
CH, cone. (vol%) 79.5 88.8 30
COZ cone. (vol%) 20 11.1 67
HZS cone. (vol%) 0.5 0.05 2.9
The membrane area used was calculated to be about 70 m2. The stage cut was
just under 16% and
the methane loss into the permeate was 6%. The process produces a residue
stream from which 90% of
the hydrogen sulfide and about 50% of the carbon dioxide has been removed.
This residue stream passes
to the amine plant for additional treatment to bring it within specification
for carbon dioxide and hydrogen
sulfide.
Example 32
A process was designed to handle a 28.3 Nm'/min (1,000 scfm) gas stream
containing 2 vol%
hydrogen sulfide, 5 vol% carbon dioxide,1,200 ppm water vapor and the
remainder methane. The process
uses a two-stage membrane separation system in which the permeate from the
first bank of membrane
modules becomes the feed for the second bank. The basic schematic of the
process is as shown in Figure
5, except that in this case, no condenser 15 is used. Both merzbrane stages
were assumed to use more
hydrogen-sulfide-selective membranes having the following characteristics:
Hydrogen sulfide/methane selectivity: 50
Water vapor/methane selectivity: 500
Carbon dioxide/methane selectivity: 15
Methane flux: 7.5 x 10'~ cm'(STP)/cm2~s~cmHg
The compositions and flow rates of the product residue (first stage) and
product permeate (second
stage) streams were calculated and are given, together with the raw (unmixed)
feed figures, in Table 17.
TABLE 17
STREAM FEED RESIDUE PERMEATE
Flow rate (Nm'lmin)28.3 (1,000 26.4 (932 scfm)1.9 (68 sefm)
scfm)
HZS cone. (vol%) 2.0 50 ppm 29.3
COZ cone. (vol%) 5.0 1.0 59.3
Water vapor cone. 1,200 0.0 1.76 vol%
(ppm)
CHI cone. (vol%) 92.9 99.0 9.6
~~~341
W. _c, ~.' r .~
WO 95111739 - ~ ~ -° PCT/US94/12100
The membrane area used to perform such a separation was calculated to be about
250 mz total,
240 mz in the first stage and 10 m2 in the second stage.
The membrane system was considered to be part of a process as shown in Figure
12. Residue
stream 52, which, after the membrane treatment meets pipeline specification
for carbon dioxide and water
5 vapor, but is still over spec. for hydrogen sulfide at SO ppm, is passed to
an iron sponge, 53. The iron
sponge removes the remainder of the hydrogen sulfide down to below 4 ppm.
Stream 54 emerging from
the iron sponge unit meets pipeline specification for all gases. Permeate
stream 55 contains 29.3 vol%
hydrogen sulfide and has a slow rate of 1.9 Nm'/min (68 scfm). This stream is
passed to a Claus plant,
56, for conversion to sulfur. Based on the stream content and flow rate, the
typical yield, 57 is
10 1,100 kg/day of elemental sulfur. The overall methane loss from the total
process is only 0.7%.
Bxample 33
A process was designed to handle a 28.3 Nm'/min (1,000 scfm) gas stream
containing 1,000 ppm
hydrogen sulFde, 1,200 ppm water vapor, 10 vol% carbon dioxide and the
remainder methane. The
process uses a membrane separation system as shown in Figure 8. Numerals 38,
44 and 47 indicate the
15 three banks of membrane modules: all contain the more hydrogen-sulfide-
selective membrane. The
incoming gas stream 36 is at 6,897 kPa (1,000 psia) and is mixed with the
residue stream 49 from
modules) 47 to form the feed gas stream 37 to the first membrane stage. The
permeate stream, 40, from
the first stage is racompressed in compressor 42. Compressor 42 drives two
membrane units, the second
stage unit, 44, and an auxiliary module or set of modules, 47, that are
connected on the permeate side
20 either directly or indirectly to the inlet side of the axnpressor, so as to
form a loop. Thus, permeate stream
48 may be merged with penmeate stream 40 to form combined stream 41. The
recompressed, combined
stream, 43, passes as feat to membrane unit 44, acid tl~ residue stream, 46,
from membrane unit 44 passes
as fend to membrane unit 47. Permeate is withdrawn from the loop as stream 45
and the treated residue
exits as stream 39.
25 The characteristics of the membrane were assumed to be as follows:
Hydrogen sulfide/methane selectivity: SO
Carbon dioxide/methane selectivity: 15
Water vapor/methane selectivity: 500
30 Methane flux: 7.5 x 10'~ cm3(STP)/cm2~s~cmHg
The compositions and flow rates of the product residue (first stage) and
product permeate (second
stage) streams were calculated and are given, together with the raw (unmixed)
feed figures, in Table 18.
T k. 1 ~'. ~:.
a s '.
WO 95111739 21 l 4 3 41 PCTlUS94/12100
46
TART.R 18
STREAM FEED RESIDUE PERMEATE
Flow rate (Nm'/min)28.3 (1,000 27.8 (983.5 0.5 (16.5 sefm)
scfm) scfm)
HZS conc. (ppm) 1,000 400 3.7 vol%
COZ cone. (vol%) 10.0 8.7 86.9
Water vapor cone. 1,200 50 6.6 vol%
(ppm)
CHI conc. (vol%) 89.8 91.3 2.8
The membrane area used to perform such a separation was calculated to be about
36 m2 total, 31
m2 in the first stage, 2 m2 in the second stage and 3 mz in the auxiliary
stage.
The membrane system was considered to be part of a process as shown in Figure
12. Residue
stream 52, which, after the membrane treatment is still substantially over
spec. for both hydrogen sulfide
and carbon dioxide is sent to an amine absorption unit, 53. The absorber
removes the remainder of the
hydrogen sulfide to 4 ppm and the carbon dioxide to 2 vol%, and produces a
small stream containing
0.5 vol% hydrogen sulfide, the remainder carbon dioxide, which can be flared.
Permeate stream 55
contains 3.7 vol% hydrogen sulfide and has a flow rate of 0.5 Nm'/min (17
scfm). This stream has a flow
rate and concentration that is on the low side for a Claus plant. The stream
is passed to a redox unit, 56,
for conversion to sulfur. Based on the stream content and flow rate, the
typical yield, 57 is 35 kg/day of
sulfur. The total methane loss is essentially zero, at about 0.05%.
Example 34
A calculation as in Example 33, using the membrane design of Figure 8 and the
overall design of
Figure 12 was performed. The process was again designed to handle a 28.3
Nm'/min (1,000 scfm) gas
stream containing 1,000 ppm hydrogen sulfide, 1,200 ppm water vapor, 10 vol%
carbon dioxide and the
remainder methane. In this case, however, more membrane area was used and the
system was run at a
slightly higher stage cut to extract more hydrogen sulfide and carbon dioxide
into the permeate stream.
The characteristics of the membrane were assumed to be as follows:
Hydrogen sulfideJmethane selectivity: 50
Carbon dioxide/methane selectivity: 15
Water vapor/methane selectivity: 500
Methane flux: 7.5 x 10'~ cm'(STP)/cm2~s~cmHg
The c~npositions and flow rates of the product residue (first stage) and
product permeate (second
stage) streams were calculated and are given, together with the raw (unmixed)
feed figures, in Table 19.
- 35
2 ~ 14341
WO 95/11739 PCT/US94/12100
47
TABLE 19
STREAM FEED RESIDUE PERMEATE
Flow rate (Nm'/min)28.3 (1,000 27.5 (970 scfm)0.8 ( 30 scfm)
scfm)
HZS cone. (ppm) 1,000 100 3.0 vol%
COZ cone. (vol%) 10.0 7.5 90.7
Water vapor cone. 1,200 0 4.0 vol%
(ppm)
CH, cone. (vol%) 89.8 92.5 2.3
The membrane area used to perform such a separation was calculated to be about
93 m2 total,
80 m2 in the first stage, 3 mz in the second stage and 10 m2 in the auxiliary
stage.
The membrane system was considered to be part of a process as shown in Figure
12. Residue
stream 52, which, after the membrane treatment is still substantially over
spec. for both hydrogen sulfide
and carbon dioxide is sent to an amine absorption unit, 53. The absorber
removes the remainder of the
hydrogen sulfide to 4 ppm and the carbon dioxide to 2 vol%, and produces a
small stream containing
0.1 vol% hydrogen sulfede, the remainder carbon dioxide, which can be flared.
Permeate stream 55
contains 3 vol% hydrogen sulfide and has a flow rate of 0.8 Nm'/min (30 scfm).
This stream has a flow
rate and concentrntion that is on the low side for a Claus plant. The stream
is passed to a redox unit, 56,
for c~version to sulfur. Based on the stream content and flow rate, the
typical yield, 57 is 52 kg/day of
sulfur. Comparing this example with Example 33, it may be seen that the sulfur
yield is much higher in
this case. The methane loss is still very small, at 0.08%.
Example 35
A calculation as in Examples 33 and 34, using the membrane design of Figure 8
and the overall
design of Figure 12 was performed. This time, the process was again designed
to handle a 28.3 Nm'/min
(1,000 scfm) gas stream containing 5 vol% hydrogen sulfide, 1,200 ppm water
vapor, 10 vol% carl~n
dioxide and the remainder methane. The characteristics of the membrane were
assumed to be as follows:
Hydrogen sulfide/methane selectivity: 50
Carbon dioxide/methane selectivity: 15
Water vapor/methane selectivity: 500
Methane flux: 7.5 x 10~ cm'(STP)/cm2~s-cmHg
The compositions and flow rates of the product msidue (first stage) and
product permeate (second
stage) streams were calculated and are given, together with the raw (unmixed)
feed figures, in Table 20.
'. ' A , ~ ~~ ~ 174341
PCT/US94/12100
WO 95/11739
48
TABLE 20
STREAM FEED RESIDUE PERMEATE
Flow rate (Nm'/min)28.3 ( 1,000 26.3 (927 sefin)2.0 (73 scfm)
scfm)
HZS cone. (vol%) 5.0 0.5 62.4
COZ cone. (vol%) 10.0 8.0 35.2
Water vapor cone.1,200 0 1.6 vol%
(ppm)
CH, cone. (vol%) 84.9 91.5 0.8
The membrane area used to perform such a separation was calculated to be about
91 m2 total,
76 m2 in the first stage, 4 m2 in the second stage and 11 m2 in the auxiliary
stage.
The membrane system was considered to be part of a process as shown in Figure
12. Residue
stream 52, which, after the membrane treatment is still substantially over
spec. for both hydrogen sulfide
and carbon dioxide is sent to an amine absorption unit, 53. The absorber
removes the remainder of the
hydrogen sulfide to 4 ppm and the carbon dioxide to 2 vol%, and produces a
small stream containing
5.8 vol% hydrogen sulfide, the remainder carbon dioxide, which can be flared
or sent to further treatment
or conversion. Permeate stream 55 contains 62.4 vol% hydrogen sulfide and has
a flow rate of
2.0 Nm'/min (73 scfm). This stream is sent to a Claus plant, 56, for
conversion to sulfur. Based on the
stream content and flow rate, the typical yield, 57 is 2364 kg/day (2.6
ton/day) of sulfur.
Example 36
A process was designed to handle a 28.3 Nm'/min (1,000 scfm) gas stream
containing 5,004 ppm
hydrogen sulfide, 5 vol% carbon dioxide and the remainder methane. The process
uses a two-stage
membrane separation system as in Example 32. Both membrane stages were assumed
to use more
hydrogen-sulfide-selective membranes having the following characteristics:
Hydrogen sulfidelmethane selectivity: 50
Water vapor/methane selectivity: 500
Carbon dioxidelmethane selectivity: 15
Methane flux: 7.5 x 10'~ cm3(STP)/cm2~s~cmHg
The compositions and flow rates of the product residue (first stage) and
product permeate (second
stage) streams were calculated and are given, together with the raw (unmixed)
feed figures, in Table 21.
~_ ~! ~.
WO 95111739 , PCT/US94/12100
49
TABLE 21
STREAM FEED RESIDUE PERMEATE
Flow rate (Nm'/min)28.3 (1,000 27.0 (954 1.3 (46 scfm)
scfm) scfm)
HZS conc. (ppm) 5,000 50 10.6 vol%
COZ canc. (vol%) 5.0 . 1.5 76.7
CHI conc. (vol%) 94.5 98.5 12.7
The membrane area used to perform such a separation was calculated to be about
192 m2 total,
182 m2 in the fn~st stage and 10 mz in the second stage.
The membrane system was considered to be part of a process as shown in Figure
12. Residue
stream 52, which, aittr the membrane treatment meets pipeline specification
for carbon dioxide, but is still
over spec. for hydrogen sulfide at 50 ppm, is passed to an iron sponge, 53.
The iron sponge removes the
remainder of the hydrogen sulfide down to below 4 ppm. Stream 54 emerging from
the iron sponge unit
meets pipeline specification for all gases. Permeate stream 55 contains 10.6
vol% hydrogen sulfide and
has a flow rate of 1.3 Nm'/min (46 scfm). This stream is passed to a redox
plant, 56, for conversion to
sulfur. Based on the stream content and flow rate, the typical yield, 57 is
288 kg/day of elemental sulfur.
The overall methane loss from the total process is only 0.6%.
