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Patent 2548071 Summary

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(12) Patent: (11) CA 2548071
(54) English Title: A CATALYST USEFUL FOR H2S REMOVAL FROM GAS STREAM PREPARATION THEREOF AND USE THEREOF
(54) French Title: CATALYSEUR UTILE POUR L'ELIMINATION DE SULFURE D'HYDROGENE CONTENU DANS UN FLUX GAZEUX, SA PREPARATION ET SON UTILISATION
Status: Expired and beyond the Period of Reversal
Bibliographic Data
(51) International Patent Classification (IPC):
  • B01D 53/86 (2006.01)
  • B01J 23/745 (2006.01)
  • C01B 17/04 (2006.01)
(72) Inventors :
  • AYYER, JAYALEKSHMY (India)
  • SHAH, PRADIPKUMAR MAHESHCHANDRA (India)
  • PATEL, VIRENDRA BHIKHABHAI (India)
(73) Owners :
  • JAYALEKSHMY AYYER
  • PRADIPKUMAR MAHESHCHANDRA SHAH
  • VIRENDRA BHIKHABHAI PATEL
(71) Applicants :
  • JAYALEKSHMY AYYER (India)
  • PRADIPKUMAR MAHESHCHANDRA SHAH (India)
  • VIRENDRA BHIKHABHAI PATEL (India)
(74) Agent: SMART & BIGGAR LP
(74) Associate agent:
(45) Issued: 2009-10-20
(86) PCT Filing Date: 2003-12-05
(87) Open to Public Inspection: 2005-06-23
Examination requested: 2006-09-25
Availability of licence: N/A
Dedicated to the Public: N/A
(25) Language of filing: English

Patent Cooperation Treaty (PCT): Yes
(86) PCT Filing Number: PCT/IB2003/005687
(87) International Publication Number: WO 2005056164
(85) National Entry: 2006-06-02

(30) Application Priority Data: None

Abstracts

English Abstract


The present invention relates to a catalyst useful for removal of hydrogen
sulphide from gas streams and its conversion to sulphur, a process for
preparing such catalyst and a method for removing of hydrogen sulphide using
said catalyst.


French Abstract

L'invention concerne un catalyseur utile pour l'élimination de sulfure d'hydrogène contenu dans des flux gazeux et sa conversion en soufre, son procédé de préparation et une méthode pour l'élimination de sulfure d'hydrogène à l'aide dudit catalyseur.

Claims

Note: Claims are shown in the official language in which they were submitted.


23
WE CLAIM
1. A catalyst useful for removal of hydrogen sulphide from gas streams
containing the same and its conversion to elemental sulphur, the said catalyst
comprising 0 to 95% by weight clay, 5 to 95% by weight gypsum and 0 to 95% by
weight alumina and 5 to 60% by weight hydrated iron oxide and heated to
temperatures between 100 and 650°C for activation.
2. A catalyst as claimed in claim 1, wherein said catalyst comprising 5 to 60%
by weight clay, 5 to 80% by weight gypsum and 5 to 40% by weight alumina and 6
to 40% by weight hydrated iron oxide.
3. A catalyst as claimed in claim 1, wherein clays are selected from Kalonite,
Montomorillonite /Semectite, Illite and Chlorite.
4. A catalyst as claimed in claim 3, wherein clays are selected from the
Semectite group.
5. A catalyst as claimed in claim 4, wherein clay used is bentonite clay.
6. A catalyst as claimed in claim 1, wherein said catalyst contains ferric
ions as
active sites, which chemisorbs hydrogen sulphide present in the gas stream and
converts the same into elemental sulphur.
7. A catalyst as claimed in claim 1, wherein said catalyst has pH value in the
range of 8.0 to 10Ø
8. A catalyst as claimed in claim 1, wherein 100 gm of said catalyst
chemisorbs
2860 to 28600 mg of hydrogen sulphide from said gas stream in one cycle.
9. A catalyst as claimed in claim 1, wherein spent catalyst containing
sulphides
of iron is regenerated by passing air through the same at ambient temperature.

24
10. A catalyst as claimed in claim 1, wherein regenerated catalyst treats and
removes hydrogen sulphide, from the gas stream and converts the same to
elemental sulphur in the subsequent cycles of chemisorption and regeneration.
11. A catalyst as claimed in claim 1, wherein the catalyst is used in at least
15
chemisorption and regeneration cycles during its use.
12. A catalyst as claimed in claim 1, wherein sulphides of iron present in
spent
catalyst is converted to Fe2O3 during regeneration thereby producing elemental
sulphur and regenerating the catalyst.
13. A catalyst as claimed in claim 1, wherein the elemental sulphur recovered
has purity more than 99%.
14. A catalyst as claimed in claim 1, wherein said catalyst is used in fixed
bed
reactors or fluidized bed reactors.
15. A catalyst as claimed in claim 1, wherein said catalyst is divided into
fine
particles having particle size in the range of 100 µm to 2000 µm for use
in a
fluidized bed reactor.
16. A catalyst as claimed in claim 1, wherein said catalyst is pelletized or
granulated to obtain pellets/granules having diameter in the range of 0.5 mm
to
10.0 mm for use in fixed bed reactors.
17. A process for preparing a catalyst useful for removing hydrogen sulphide
from a gas stream and recovering elemental sulphur therefrom, said process
comprising the steps of:
a) mixing of 0 to 95% by weight clay, 5 to 95% by weight gypsum, 0 to 95% by
weight lumina and 5 to 60% by weight hydrated iron oxide.
b) granulating, pelletizing or pulverizing the mixture of step (a) and heating
the

25
same at temperature in the range of 100°C to 650°C to obtain the
catalyst.
18. A process as claimed in claim 17 wherein in step (a), the hydrated iron
oxide
is prepared from commonly available salts of iron selected from ferric
nitrate, ferric
chloride, and ferric sulphate and commonly available alkali selected from
ammonium hydroxide, sodium hydroxide and potassium hydroxide.
19. A process as claimed in claim 17, wherein 100 gm of the catalyst thus
obtained chemisorb 2860 to 28600 mg of hydrogen sulphide gas from the gas
stream.
20. A process as claimed in claim 17, wherein the catalyst thus obtained has
pH
value in the range of 8.0 to 10Ø
21. A process as claimed in claim 17, wherein the catalyst thus obtained is
used
in fixed bed reactor or fluidized bed reactor.
22. A process as claimed in claim 17 wherein catalyst thus obtained contain
ferric
ions as active sites.
23. A process as claimed in claim 17, wherein the catalyst thus obtained is
pulverized into fine particles for use in fluidized bed reactors.
24. A process as claimed in claim 17 wherein in step (b), the mixture of step
(a) is pelletized or granulated to obtain pellets/granules having diameter in
the
range of 0.5 mm to 10 mm for use in fixed bed reactors.
25. A method for removal of sulphur compounds from a gas stream comprising
the same and recovery of elemental sulphur therefrom, said method comprising
the
steps of:
a) mixing moist air/water with the gas stream comprising the sulphur compounds
for converting the sulphur compound to hydrogen sulphide.

26
b) contacting the gas stream containing hydrogen sulphide with a catalyst
comprising to 0 to 95% by weight clay, 5 to 95% by weight gypsum, 0 to 95% by
weight alumina and 5 to 60% by weight hydrated iron oxide to remove hydrogen
sulphide by chemisorption, and
c) regenerating the spent catalyst by passing an oxygen containing gas through
or
over the same spent catalyst to converge iron sulphides to iron oxides and
elemental sulphur.
26. A method as claimed in claim 25, wherein compounds of sulphur are
hydrogen sulphide, carbonyl sulphide (COS), and carbon disulphide (CS2) and
mixtures thereof.
27. A method as claimed in claim 25, wherein the gas streams containing
hydrogen sulphide from trace level to 100% level is treated to get outlet gas
stream free of the same.
28. A method as claimed in claim 25, wherein the color of the catalyst changes
from reddish brown to black during step (b) chemisorption and it changes back
to
reddish brown on regeneration, this property being useful in visually
monitoring the
progress of the chemisorption and regeneration cycles respectively.
29. A method as claimed in claim 25, wherein the oxygen containing gas is air.
30. A method as claimed in claim 25, wherein removal of the sulphur compound
from the gas stream and regeneration of catalyst are optionally carried out
simultaneously.
31. A method as claimed in claim 25, wherein removal of the sulphur compound
from the gas stream and regeneration of catalyst are simultaneously carried
out by
contacting gas stream containing sulphur compounds & an oxygen containing gas
simultaneously with the catalyst.

27
32. A method as claimed in claim3l, wherein the rate of simultaneous reaction
and regeneration of catalyst depends on the flow rates of gas stream, and
ratio of
gas stream and oxygen containing gas as well as the hydrogen sulphide content
of
the gas stream.
33. A method as claimed in claim 25, wherein the percentage of regeneration of
spent catalyst is 100% when oxygen containing gas is passed through or over
the
spent catalyst.
34. A method as claimed in claim 25, wherein the method is carried out in
fluidized bed reactors or fixed bed reactors.
35. A method as claimed in claim 25, wherein the elemental sulphur obtained
has purity more than 99%.
36. A method as claimed in claim 25, wherein 100 gm of said catalyst
chemisorbs 2860 to 28600 mg of hydrogen sulphide from said gas stream in one
cycle.

Description

Note: Descriptions are shown in the official language in which they were submitted.


CA 02548071 2006-06-02
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1
A CATALYST USEFUL FOR HZS REMOVAL FROM CAS STREAM
PREPARATION THEREOF AND USE THEREOF
FIELD OF THE INVENTION
The invention relates to a catalyst comprising 0 to 95 % by weight clay, 0 to
95 % by
weight gypsum and 0 to 95 % by weight alumina and 5 to 60 % by weight hydrated
iron
oxide and heated to temperatures between 100 and 650°C for enhanced
activity for
removal of hydrogen sulphide from gas streams and its conversion to sulphur, a
process for
preparing such catalyst and a method for removing hydrogen sulphide using said
catalyst
BACKGROUND AND PRIOR ART REFERENCES
Hydrogen sulphide is a highly toxic and corrosive environmental pollutant with
an
obnoxious smell which needs to be removed for pollution control as well as
process
requirements in industries. Natural gas processing complexes, refineries,
sulphur
processing chemicals industries, pharmaceutical industries, sugar industries,
sewage
I S treatment plants and bio-gas generating units are some of the major
industries which need
an economically viable solution for HZS removal and its safe disposal.
A number of processes have been known and are in commercial use for removing
hydrogen sulphide from gas streams. However, these processes have some
inherent
limitations. The processes used for removal of HZS and there disadvantages are
described
in detail hereafter.
Claus process is used for removing hydrogen sulphide from gases containing
typically high
concentration of HzS (more than 20% by vol of HZS). Liquid Redox process is
used for
removing hydrogen sulphide from gases containing typically low concentration
of HZS.
Both the aforesaid processes have the disadvantages of high capital and
operating cost.
Processes using iron sponges as catalyst have been in use wherein iron oxide
deposited on
wood shaving is used for removing hydrogen sulphide from gases. The major
disadvantage
with such a catalyst that these can be used as only once-through catalyst i.e.
the catalyst
after being used for removal of H2S can not be regenerated and hence has to be
disposed
as waste. Therefore, the cost of such treatment is high due to the use of
stoichiometric
quantities of chemicals and also disposal of the used materials. Further,
loading capacity
i.e. the extent upto which the wood shavings can be loaded with the iron oxide
is low, due
to which, the hydrogen sulphide removal capacity in a single pass is limited.
Also, safe
disposal of the used catalyst is major problem.
In yet another process for hydrogen sulphide removal, a hot zinc oxide bed is
used. Zinc
oxide is costlier than iron oxide. Another limitation of the process is that
the bed gets
CONFIRMATION COPY

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2
exhausted after treating stoichiometric quantity of hydrogen sulphide once
through the bed.
The need of higher temperature for effective removal is another disadvantage
as the gas
needs to be preheated prior to treatment. Zinc oxide gets converted to zinc
sulphide which
is disposed off after the bed gets exhausted.
From the above descriptions of prior art, it is clear that there is a need for
a more
economical and simple process for hydrogen sulphide removal and its conversion
to
elemental sulphur using a solid bed incorporating inexpensive chemicals which
can be
regenerated and reused multiple times. This is the main objective of the
present invention.
OBJECTIVE'OF INVENTION
The objective of the present invention is to provide an iron oxide based
catalyst which can
be used multiple times for removal of hydrogen sulphide from gas streams
containing the
same and its conversion to elemental sulphur.
Another objective of the present invention is to provide process for preparing
aforesaid
catalyst.
One another objective of the present invention is to provide a method for
removal of
sulphur compounds from a gas stream comprising the same and recovery of
elemental
sulphur therefrom using aforesaid catalyst.
STATEMENT OF INVENTION
The present invention relates to a catalyst useful for removal of hydrogen
sulphide from
gas streams containing the same and its conversion to elemental sulphur, the
said catalyst
comprising 0 to 95 % by weight clay, 0 to 95 % by weight gypsum and 0 to 95%
by weight
alumina and 5 to 60 % by weight hydrated iron oxide and heated to temperatures
between
100 and 650°C for enhanced activity and
The present invention further relates to a process for preparing a catalyst
useful for
removing hydrogen sulphide from a gas stream and recovering elemental sulphur
therefrom, said process comprising the steps of:
a) mixing of 0 to 95 % by weight clay, 0 to 95 % by weight gypsum, 0 to 95 %
by
weight alumina and 5 to 60 % by weight hydrated iron oxide; and
b) granulating, pelletizing or pulverizing the mixture of step (a) and heating
the same
at temperature in the range of 100°C to 650°C to obtain the
catalyst.
The present invention also relates to a method for removal of sulphur
compounds from a
gas stream comprising the same and recovery of elemental sulphur therefrom,
said method
comprising the steps of:

CA 02548071 2006-06-02
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3
a) mixing moist air/ water with the gas stream comprising the sulphur
compounds for converting the sulphur compound to hydrogen sulphide.
a) Contacting the gas stream containing hydrogen sulphide with a catalyst
comprising to 0 to 95 % by weight clay, 0 to 95 % by weight gypsum, 0
to 95 % by weight alumina and 5 to 60 % by weight hydrated iron oxide
to remove hydrogen sulphide by chemisorption, and
a) regenerating the spent catalyst by passing air through or over the same
to oxides of iron and converting iron sulphides to iron oxides and
elemental sulphur.
SUMMARY
The solid material used for hydrogen sulphide is made by an inventive method
to enable
loading of the active content to high levels as well as improve its activity
by a unique heat
treatment method. The process also is designed to render the medium porous for
greater
gas penetration and availability of reactive sites. The repeated ability to
regenerate the
active chemical entity in the system renders the process catalytic in nature.
The chemical reactions which enable the process of hydrogen sulphide removal
and
regeneration of the active content of the solid medium are given below:
A. Hydrogen Sulphide Removal Reactions .
1. Fe203 + 3 HzS Fe2S3 + 3 H20
2. Fe2S3 2 FeS + S
3. 2 FeS + 1 '/2 OZ Fe203 + 2S
4. 3HZS + 1 %2 OZ 3S + 3 H20
B. Carbonyl Sulphide Removal Reactions
5. 3COS + 3 H20 ~ 3 COZ + 3 HzS
C. Carbon Disulphide Removal Reactions
6. CSz + 2 HZO --~ COz + 2 HZS
Carbonyl sulphide and carbon disulphide are converted to hydrogen sulphide by
reaction
with water present with the treating gas or in the bed and the hydrogen
sulphide produced
is then converted into elemental sulphur as given above in equations 1 to 4.
Iron oxide in the medium which is in the ferric oxide form reacts with
hydrogen sulphide
to form ferric sulphide as shown in the first equation. Ferric sulphide being
unstable gets
converted to the more stable ferrous sulphide and sulphur (Eq. 2). During this
process, iron

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4
gets reduced to ferrous form and hydrogen sulphide gets oxidized partially to
sulphur. The
ferrous sulphide on contacting with air gets oxidized as shown in the equation
3 to
elemental sulphur and ferric oxide, thus regenerating the same for another
cycle of reaction
with hydrogen sulphide.
This is thus a catalytic redox process wherein the ferric and ferrous forms of
iron are
formed during the reaction and regeneration cycles. The product of the
reaction is
elemental sulphur. The net result of the reaction cycle is the oxidation of
hydrogen
sulphide to elemental sulphur by the oxygen in the air as shown in the
equation 4.
Also, other sulphur containing compounds such as carbonyl sulphide and carbon
disulphide are also converted into hydrogen sulphide as shown in reaction 5 &
6 and
subsequently to elemental sulphur as given in Equations 1 to 4.
DETAIL DESCRIPTION OF THE INVENTION
The Present invention relates to a catalyst useful for removal of hydrogen
sulphide from
gas streams containing the same and its conversion to elemental sulphur, the
said catalyst
comprising 0 to 95 % by weight clay, 0 to 95 % by weight gypsum and 0 to 95 %
by
weight alumina and 5 to 60 % by weight hydrated iron oxide and heated to
temperatures
between 100 and 650°C for enhanced activity.
Yet another embodiment of the present invention, wherein the weight
percentages of clay,
gypsum and alumina are not simultaneously equal to zero.
Yet another embodiment of the present invention, wherein said catalyst
comprising 5 to 60
% by weight clay, 5 to 80 % by weight gypsum and 5 to 40 % by weight alumina
and 6 to
40 % by weight hydrated iron oxide.
Yet another embodiment of the present invention, wherein clays are selected
form the
group comprising Kalonite, Montomorillonite /Semectite, Illite and Chlorite.
Yet another embodiment of the present invention, wherein clays are selected
form the
Semectite group.
Yet another embodiment of the present invention, wherein clay used is
bentonite clay.
Yet another embodiment of the present invention, wherein said catalyst
contains ferric ions
as active sites, which chemisorbs hydrogen sulphide present in the gas stream
and converts
the same into elemental sulphur.
Yet another embodiment of the present invention, wherein said catalyst has pH
value in the
range of 8.0 to 10.0
Yet another embodiment of the present invention, wherein said catalyst is heat
treated at
temperature in the range of 100° C to 650° C before use for
activating the same.

CA 02548071 2006-06-02
WO 2005/056164 PCT/IB2003/005687
Yet another embodiment of the present invention, wherein 100 gm of said
catalyst
chemisorbs 2860 to 28600 mg of hydrogen sulphide from said gas stream in one
cycle.
Yet another embodiment of the present invention, wherein said spent catalyst
containing
sulphides of iron is regenerated by passing air through the same at ambient
temperature.
S Yet another embodiment of the present invention, wherein regenerated
catalyst treats and
removes hydrogen sulphide, from the gas stream and converts the same to
elemental
sulphur in the subsequent cycles of chemisorption and regeneration.
Yet another embodiment of the present invention, wherein the catalyst is used
in at least 15
chemisorption and regeneration cycles during its use.
Yet another embodiment of the present invention, wherein sulphides of iron
present in the
spent catalyst is converted to Fe203 during regeneration thereby producing
elemental
sulphur and regenerating the catalyst.
Yet another embodiment of the present invention, wherein the elemental sulphur
recovered
has purity more than 99 %.
Yet another embodiment of the present invention, wherein said catalyst is used
in fixed bed
reactors or fluidized bed reactors.
Yet another embodiment of the present invention, wherein said catalyst is
divided into fine
particles having particle size in the range of 100 p.m to 2000 pm for use in
the fluidized
bed reactor.
Yet another embodiment of the present invention, wherein said catalyst is
pelletized or
granulated to obtain pellets/ granules having diameter in the range of 0.5 mm
to 10.0 mm
for use in fixed bed reactors.
A further embodiment of the present invention relates to a process for
preparing a catalyst
useful for removing hydrogen sulphide from a gas stream and recovering
elemental
sulphur therefrom, said process comprising the steps of:
a) mixing of 0 to 95 % by weight clay, 0 to 95 % by weight gypsum, 0 to 95 %
by
weight alumina and 5 to 60 % by weight hydrated iron oxide.
b) granulating, pelletizing or pulverizing the mixture of step (a) and heating
the same
at temperature in the range of 100°C to 650°C to obtain the
catalyst.
Still further embodiment of the present invention, wherein in step (a), the
hydrated iron
oxide is prepared from commonly available salts of iron such as ferric
nitrate, ferric
chloride, ferric sulphate and commonly available alkali ammonium hydroxide,
sodium
hydroxide and potassium hydroxide.

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6
Yet another embodiment of the present invention, wherein 100 gm of the
catalyst thus
obtained chemisorb 2860 to 28600 mg of hydrogen sulphide gas from the gas
stream.
Yet another embodiment of the present invention, wherein the catalyst thus
obtained has
pH value in the range of 8.0 to 10Ø
Yet another embodiment of the present invention, wherein the catalyst thus
obtained is
used in fixed bed reactor or fluidized bed reactor.
Yet another embodiment of the present invention, wherein catalyst thus
obtained contain
ferric ions as active sites.
Yet another embodiment of the present invention, wherein the catalyst thus
obtained is
l0 pulverized into fine particles for use in fluidized bed reactors.
Yet another embodiment of the present invention wherein in step (b), the
mixture of step
(a) is pelletized or granulated to obtain pellets/ granules having diameter in
the range of 0.5
mm to 10 mm for use in fixed bed reactors.
Still further embodiment of the present invention relates to a method for
removal of
I S sulphur compounds from a gas stream comprising the same and recovery of
elemental
sulphur therefrom, said method comprising the steps of
a) mixing moist air/ water with the gas stream comprising the sulphur
compounds for converting the sulphur compound to hydrogen sulphide.
b) Contacting the gas stream containing hydrogen sulphide with a catalyst
20 comprising to 0 to 95 % by weight clay, 0 to 95 % by weight gypsum, 0 to 95
by weight alumina and 5 to 60 % by weight hydrated iron oxide to remove
hydrogen sulphide by chemisorption, and
c) regenerating the spent catalyst by passing air through or over the same to
oxides of iron and converting iron sulphides to iron oxides and elemental
25 sulphur.
In yet another embodiment of the present invention, wherein compounds of
sulphur are
hydrogen sulphide, carbonyl sulphide (COS), and carbon disulphide (CSz) and
mixtures
thereof.
Yet another embodiment of the present invention, wherein the gas streams
containing
30 hydrogen sulphide from trace level to 100% level is treated to get outlet
gas stream free of
the same.
Yet another embodiment of the present invention, wherein the color of the
catalyst changes
from reddish brown to black during step (b) chemisorption and it changes back
to reddish

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7
brown on regeneration, this property being useful in visually monitoring the
progress of
the chemisorption and regeneration cycles respectively.
Yet another embodiment of the present invention, wherein the spent catalyst is
regenerated
by passing an oxygen containing gas through or over the same.
Yet another embodiment of the present invention, wherein removal of the
sulphur
compound from the gas stream and regeneration of catalyst are optionally
carried out
simultaneously.
Still another embodiment of the present invention, wherein removal of the
sulphur
compound from the gas stream and regeneration of catalyst are simultaneously
carried out
by contacting gas stream containing sulphur compounds & an oxygen containing
gas
simultaneously with the catalyst.
Yet another embodiment of the present invention, wherein the rate of
simultaneous
reaction and regeneration of catalyst depends on the flow rates of gas stream
and ratio of
gas stream and oxygen containing gas as well as the hydrogen sulphide content
of the gas
stream.
Yet another embodiment of the present invention, wherein the percentage of
regeneration
of spent catalyst is 100% when oxygen containing gas is passed through or over
the spent
catalyst.
Yet another embodiment of the present invention, wherein the process is
carried out in
fluidized bed reactors or fixed bed reactors.
Yet another embodiment of the present invention, wherein the elemental sulphur
obtained
has purity more than 99 %.
Yet another embodiment of the present invention, wherein 100 gm of said
catalyst
chemisorbs 2860 to 28600 mg of hydrogen sulphide from said gas stream in one
cycle.
The invention is different from the ones reported so far as that a solid
medium
incorporating iron hydroxide in the bulk of the same is prepared by mixing the
ingredients
which are naturally occurring, non toxic and non hazardous in nature with iron
hydroxide
and heat treating the same to get high activity for hydrogen sulphide removal
and its
conversion to elemental sulphur. The iron hydroxide is prepared from any
common iron
salts such as iron chloride, iron sulphate and iron nitrate by treatment with
alkalis such as
sodium hydroxide, potassium hydroxide or ammonium hydroxide. The mixture of
iron
hydroxide and the support medium is converted to granules or pellets for easy
packing
(filling) in a column and treated to temperatures between 100 to 600°C
to increase the

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8
reactivity of the iron oxide towards hydrogen sulphide as well as to make the
regeneration
of the same with oxygen containing gases possible. The granules help to reduce
pressure
drop across the column through allowing easy passing of the gas through the
same. This
eliminates requirement of high pressure for the gas being treated.
The iron hydroxide in the medium is converted to iron oxide by a process of
heat treatment
of the granules / pellets. Preparation of the solid medium incorporating the
iron salt is done
at relatively low temperatures as compared to the one reported recently (ref.
US Patent
6500237) wherein a calcined material is used for impregnation of the active
matter wherein
the iron hydroxide adheres to the exposed surfaces of the medium. The total
hydrogen
sulphide treatability is also found to be higher as compared to the prior art.
Another advantage of the process is that the sulphur deposited on the solid
medium can be
recovered by extraction with a suitable solvent like carbondisulphide or
carbon
tetrachloride or other organic solvents in which sulphur is soluble. Sulphur
can also be
extracted by heating the medium above sulphur melting temperature as a solid
or
1 S alternately by slurring in water and heating the slurry to above the
melting point of
sulphur. The molten sulphur can be separated from the slurry containing the
support
medium. The recovered sulphur is of high quality and can be used for
downstream
applications. In cases where the user is not interested in extraction of
sulphur the bed can
be disposed off safely without further treatment due to the non- toxic nature
of the medium
and its contents.
We thus report here an improved process for hydrogen sulphide removal from gas
streams
using a novel solid bed made by incorporating iron oxide in a mixture of
materials and
heating the same to a temperature high enough to make it chemically active and
porous for
easy availability of the reactive sites in the solid. The material can be
regenerated using a
simple process and reused multiple number of times to convert hydrogen
sulphide to
elemental sulphur. The sulphur thus deposited on the bed can be recovered
using methods
known in prior art.
Accordingly, the present invention provides a novel catalytic process for
hydrogen
sulphide removal from sour gas streams and its conversion to sulphur using
regenerative
solid bed consisting of finely divided iron oxide or its hydrated form made
from common
salts of iron such as chloride, sulphate and nitrate and an alkali such as
hydroxides of
sodium, potassium or ammonium and incorporated in a support medium consisting
of
naturally occurring clays and minerals singly or as mixture to impart
stability to the

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9
granules or pellets made from the mixture followed by heating the granules or
pellets to a
temperature high enough to enhance its reactivity towards hydrogen sulphide as
well as
enabling the regeneration of the iron oxide by conversion of the iron sulphide
formed to
sulphur and iron oxide on treatment with oxygen containing gas, the size of
the pellets or
granules being not limiting in the hydrogen sulphide removal characteristics
of the solid
bed medium.
The Applicant surprisingly found that in the composition of the catalyst, the
amount of iron
oxide incorporated plays a vital role in determining the suitability of the
catalyst in the
process of removal of hydrogen sulfide from the gaseous stream. More
particularly, the
applicants noticed that if the amount of iron oxide is incorporated in the
catalyst
composition was less than 5 % by weight , the catalyst did not efficiently
remove HZS from
the gaseous stream. The applicants were of the opinion that increasing the
amount of
.hydrated iron oxide in the catalyst composition would increase its efficacy
in removing
HZS from the gaseous stream. However, surprisingly the applicants above
hypothesis were
found to be wrong. The applicants surprisingly noticed that increasing the
amount of
hydrated iron oxide incorporated in the catalyst composition beyond a certain
range
adversely affected other properties of the catalyst and made it unsuitable for
use in the
process. More particularly, increasing the amount of the hydrated iron oxide
incorporated
in the catalyst composition beyond 60 % adversely affected the pelletization
and
granulizing properties of the catalyst. As the main aim of the present
invention is to
provide catalysts which are stable enough for regeneration, any adverse effect
on the
pelletization and granulization properties of the catalyst rendered the same
unsuitable for
even a single regeneration.
The applicants would also like to emphasis here that in step of heating the
catalyst prior to
use plays a vital role on the efficacy of the process for removal of HzS from
the gaseous
state. The applicant noticed that if the catalyst is used without prior
heating, the removal of
HZS content from a gaseous stream is not significant. This is due to the fact
that pore
formation in the catalyst does not take place and hence very less contact
surface area is
available for the absorption of HZS gas. Applicant also noticed that if the
catalyst is heated
prior to use, pores are developed in the catalyst and enhance the absorption
of the H2S gas
by providing more contact surface area.
Applicant also noticed that if the catalyst is heated prior to use, some iron
oxide present in
the interior part of the catalyst, come out on the outer surface and provide
enhanced
activity to the catalyst.

CA 02548071 2006-06-02
WO 2005/056164 PCT/IB2003/005687
Applicants also noticed that heating the catalyst continuously and above a
certain
temperature adversely affects the activity of the catalyst. More particularly,
the applicants
notice that the heating the catalyst above 600°C destroy the catalytic
activity.the applicants
found that when the catalyst is heated above the 600 °C the iron oxide
undergoes a
5 transformation in the state and and the transformed state does not provide
any catalytic
activity.
Hence, the amount of iron oxide included in the catalyst and the temperature
up to which
the catalyst is heated are critical and non-obvious aspects of the present
invention. None of
the document available , teach or suggest the these critical and non-obvious
features.
10 This invention is described in detail in the following examples which are
provided by way
of illustration only and therefore should not be construed to limit the scope
of the
invention.
BRIEF DESCRIPTION OF TABLES
Table 1 shows the results obtained of hydrogen sulphide removal from a gas
stream at
various gas flow rate.
Table 2 compares the result obtained of hydrogen sulphide removal from a gas
stream for a
heat treated catalyst with non heat treated catalyst.
Table 3 shows the result obtained of hydrogen sulphide removal from a gas
stream mix
with N 2, or COZ or CH 3 and air.
Table 4 shows oxygen content in outlet gas stream after passing through said
catalyst.
Table 5 shows number of regeneration cycle performing for hydrogen sulfide
removal with
said catalyst.
Table 6 shows result obtained of hydrogen sulphide removal from a gas stream
having
various HZS :OZ ratio.
EXAMPLES
Example 1
A solution of iron (III) nitrate (1000 g) in water is prepared and was treated
with sodium
hydroxide solution (20 g in 100 g water) in an agitated vessel to precipitate
iron hydroxide.
The precipitated iron hydroxide was allowed to settle, the supernatant clear
liquid was
discarded and the solid recovered by filtration and washed with water to
remove dissolved
salts.
The iron hydroxide (250 gm) thus isolated was mixed thoroughly with the solid
support
material bentonite clay (250 gm), alumina ( 125 gm) and gypsum (700 gm) and
converted

CA 02548071 2006-06-02
WO 2005/056164 PCT/IB2003/005687
11
to granules (3mm diameter) in a granulating drum or pellets in a pelletiser (4
mm
diameter).
The granules/pellets were dried, treated at temperature of 450 to 550
°C and used for
removal of hydrogen sulphide and other toxic gases contained in gas streams as
given in
the following examples.
Example 2
A solution of iron (III) nitrate (1000 g) in water is prepared and was treated
with sodium
hydroxide solution (20 g in 100 g water) in an agitated vessel to precipitate
iron hydroxide.
The precipitated iron hydroxide was allowed to settle, the supernatant clear
liquid was
discarded and the solid recovered by filtration and washed with water to
remove dissolved
salts.
The wet hydrated iron hydroxide obtained above (560 gm, corresponding to 1
I.50 % ferric
hydroxide on dry basis) was mixed thoroughly with the solid support material
bentonite
clay (250 gm), alumina (125 gm) and gypsum (700 gm) and converted to granules
(3mm
diameter) in a granulating drum or pellets in a pelletiser (4 mm diameter).
The granules/pellets were dried, treated at temperature of 450 to 550
°C and used for
removal of hydrogen sulphide and other toxic gases contained in gas streams as
given in
the following examples. The pellets thus obtained had iron content of 6.0 % by
wt. and
good granule integrity and crushing strength.
Example 3
The wet hydrated iron hydroxide obtained above ( 1500 gm, corresponding to 68
% ferric
hydroxide on dry basis in the mixture) was mixed thoroughly with the solid
support
material bentonite clay ( 100 gm), alumina (SO gm) and gypsum ( 125 gm). The
material
was granulated in a granulator, however, it could not be formed into granules
of good
crushing strength. Attempts at pelletisation also failed.
Example 4
The solid bed medium (225 gms), reddish brown in colour prepared as given in
Example 1
above was packed in a glass column of 32 mm diameter and 3S0 mm height. Gas
containing a mixture of hydrogen sulphide (1.14 % by volume), and rest
nitrogen was
passed through the bed at the flow rate of 0.30 liter per minute. The outlet
gas was found to
be free from hydrogen sulphide. The bed became black in colour as the hydrogen
sulphide
reacted with it and when the bed was exhausted, the material became totally
black as
shown by the presence of hydrogen sulphide in the outlet gas. Heat generation
was
observed during the chemisorption cycle.

CA 02548071 2006-06-02
WO 2005/056164 PCT/IB2003/005687
12
Through the medium in the column which was now black in colour, ambient air
was
passed. Slowly the column restored to its original reddish brown colour, thus
indicative of
its regeneration. Heat generation was observed during the regeneration cycle.
Through the above regenerated medium, hydrogen sulphide containing gas was
again
passed as above and the outlet gas was found to be free from the sour gas. The
reaction -
regeneration cycle was repeated 20 times in this manner and the column was
found to be
reactive to hydrogen sulphide removal without significant reduction in
hydrogen sulphide
removal capacity.
Example 5
As described in example 2 above, gas containing a mixture of hydrogen sulphide
(4.7 %,
47000 ppm by volume) and rest nitrogen was passed through the bed at the flow
rate of
0.140 litre per minute. The outlet gas was found to be free from hydrogen
sulphide. The
bed became black in colour as the hydrogen sulphide reacted with it and when
the bed was
exhausted, the material became totally black as evident by the presence of
hydrogen
l 5 sulphide in the outlet gas.
Example 6
The solid bed medium 100 g-as prepared in example 1 was taken in a glass
column of 32
mm diameter. Catalyst bed height measured which was 14 centimeters. Moist Gas
containing a mixture of hydrogen sulphide ( 15.4 % by volume) and rest
nitrogen was
passed through the bed at the flow rate of 0.230 liter per minute. The mixture
was passed
till hydrogen sulphide concentration in the outlet gas stream reached 100 ppm.
Example 7
The solid bed medium ( 150 gms), reddish brown in colour, prepared as given in
Example
1 above, was packed in a glass column of 32 mm diameter and 235 mm height.
Pure
hydrogen sulphide was passed through the bed at the flow rate of 0.04 liter
per minute. The
bed became black in colour as the hydrogen sulphide reacted with it. Outlet of
the column
was passed through a cadmium acetate solution (1 gm cadmium acetate dissolved
in 100
gms of water) to detect hydrogen sulphide presence in the treated gas.
(Hydrogen sulphide
reacts with cadmium acetate to form yellow precipitate of cadmium sulphide).
Hydrogen
sulphide was not detected in column outlet until last 2 cms of unexhausted bed
was
available for reaction with hydrogen sulphide as per the visual indication.
Heat generation
was observed during the chemisorption cycle.

CA 02548071 2006-06-02
WO 2005/056164 PCT/IB2003/005687
13
Example 8
The solid bed medium, 100 g, as prepared in Example 1 was filled in a glass
column of 32
mm diameter to a height 14.5 centimeters. Gas containing a mixture of hydrogen
sulphide
(3 % by volume) and rest methane was passed through the bed at the flow rate
of 0.20 litre
per minute. The results of outlet stream hydrogen sulphide concentration noted
and are as
given below.
After passing 37 liters of gas in 185 min, 100 ppm of hydrogen sulphide was
observed in
the outlet gas and the column was taken for regeneration. After passing
ambient air
through the bed, it regained its original colour and became active for next
cycle of
chemisorption.
Example 9
The solid bed medium ( 100 g), reddish brown in colour prepared as given in
Example 1
above was packed in a glass column of 32 mm diameter. Gas containing a mixture
of
hydrogen sulphide (9.1 % by volume), and rest carbon dioxide was passed
through the bed
at the flow rate of 0.05 liter per minute. As the hydrogen sulphide reacts
with the ferric
ions to form iron sulphide, the colour of the bed changes from reddish to
black. Hydrogen
sulphide in treated stream was found to be below traceable level until 15.86
liters of gas
mixture was passed. The experiment was continued till hydrogen sulphide
concentration in
treated gas stream and inlet gas stream became same. Total 40.26 liters of gas
was treated
in this manner.
Through the solid bed in the column which was now black in colour, ambient
moist air was
passed till it regained its original colour, indicative of its regeneration.
Heat generation was
observed during the regeneration cycle.
Example 10
The solid bed medium (100 g), reddish brown in colour prepared as given in
Example I
above is packed in a glass column of 32 mm diameter. Gas containing a mixture
of
hydrogen sulphide (4.75 % by volume) with nitrogen was passed through the
column. The
experiment was repeated under identical conditions with fresh bed, but with
different gas
flow rates. In all cases gas was passed till hydrogen sulphide level in outlet
gas stream
reached 100 ppm level. Quantity of gas treated and hydrogen sulphide removed
were
measured. Results are as given in Table 1 below.

CA 02548071 2006-06-02
WO 2005/056164 PCT/IB2003/005687
14
Table 1
Gas Flow Gas VelocityTotal volumeVolume of Residence
Rate of gas treatedhydrogen sulphideTime,
ml/min M/min Litres removed, Litres Seconds
100 0.12 19.53 0.93 62.70
I SO 0.18 22.275 1.06 41.80
300 0.36 18.36 0.87 21.70
400 0.48 7.20 0.34 16.64
As the volume of gas that could be treated remained nearly same upto a flow
rate of 300
ml/ min, the above example has shown that the residence time required for
reaction was
about 21 secs.
Example 11
The solid bed medium (100 g), reddish brown in colour prepared as given in
Example 1
above was packed in a glass column of 32 mm diameter. Gas containing a mixture
of
Hydrogen sulphide (5 % by volume) with nitrogen was passed through the column.
Keeping the gas mixture same, experiment was conducted for following
conditions.
i. Solid bed medium treated with ambient moist air for 1 hour before treatment
with
gas. Moist gas was passed through the catalyst bed till hydrogen sulphide
concentration in the outlet gas stream reached above 100 ppm.
ii. Solid bed medium treated with ambient moist air for 1 hour before
treatment with
gas. Dry gas was passed through the solid bed till hydrogen sulphide
concentration
in the outlet gas stream was more than 100 ppm.
iii. The catalyst was not given any treatment prior to experiment. Dry gas
mixture was
passed through the solid bed till hydrogen sulphide concentration in the
outlet gas
stream was more than 100 ppm.
The results of above three cases are given in Table 2 below.
Table 2
Hydrogen Sulphide Concentration: 5 % by volume
Gas VelocityResidence Total gas treatedTotal HZS
Cm/Second Time Secondsuntil outlet removed
HZS
concentration Litres
reached 100 ppm
Litres
Case 0.41 31.36 18.00 0.90
I
Case 0.41 31.36 18.90 0.945
II
Case 0.41 31.36 14.40 0.72
III

CA 02548071 2006-06-02
WO 2005/056164 PCT/IB2003/005687
The results show that in case where the bed was pre treated with moist ambient
air, higher
hydrogen sulphide removal capacity was observed compared to the bed which was
not
given pre treatment with moist ambient air. Moisture content in the bed and /
or moisture
in the gas were found to improve hydrogen sulphide removal efficiency.
5 Example 12
The solid bed medium (225 g), reddish brown in colour prepared as given in
Example 1
above was packed in a glass column of 30 mm diameter, bed height of 34
centimeters. Gas
containing a mixture of carbon disulphide, (35 ppm by volume) with carbon
dioxide was
passed through the column at a flow rate of 50 ml per minute. Carbon
disulphide (CSZ)
10 concentration in the treated gas was measured and found to be below
traceable levels.
Example 13
The solid bed medium, reddish brown in colour prepared as given in Example 1
above was
packed in a glass column of 15 mm diameter, catalyst bed height of 25cm. Gas
containing
a mixture of carbonyl sulphide, COS (5 ppm by volume) with nitrogen was passed
15 through the column at ambient temperature. Carbonyl sulphide (COS) was not
traceable in
the treated gas.
Example 14
The solid catalyst (25g) which underwent 8 chemisorption and regeneration
cycles was
taken in a closed vessel and was mixed with 75g of water. The mixture was
heated at 125°
C for 30 minutes. It was found that sulphur contained in the catalyst melted
and separated
out from the rest of the solid under these conditions. The vessel was cooled
down and
lumps of sulphur were recovered.
Example 15
Through the solid catalyst bed (25 g) which had undergone 8 chemisorption and
regeneration cycles packed in a glass column, Carbon disulphide (CSZ) was
passed from
the top at the flow rate of 20 ml per minute. As CSZ passed through the
column, it
dissolved the sulphur and the sulphur containing solution was collected at the
bottom.
Sulphur extraction was continued for I hour in this manner. From the CSZ
solution
containing sulphur, CS2 was distilled out and sulphur, bright yellow
crystalline, was
isolated. Sulphur thus obtained had a purity of 99.99%.
Example 16
The solid bed medium ( 100 g), reddish brown in colour prepared as given in
Example 1
above is packed in a glass column of 32 mm diameter and 130 mm height. The
following

CA 02548071 2006-06-02
WO 2005/056164 PCT/IB2003/005687
16
gas mixtures were passed through fresh columns of identical dimensions with
gas flow rate
of 0.2 litres per minute in all cases, monitoring the outlet gas quality.
i. Hydrogen sulphide (4.4 % by volume) with Carbon dioxide,
ii. Hydrogen sulphide ( 5.1 % by volume) with nitrogen,
iii. Hydrogen sulphide ( 4.26 % by volume) with methane and
iv. Hydrogen sulphide (4.25 % by volume) with air
It was found that in all cases, the hydrogen sulphide concentration , in
outlet was below
detectable limits. Gas was passed until hydrogen sulphide concentration in
outlet gas
stream reached 100 ppm by volume. The quantity of gas treated in the first
pass is given in
the table below with other parameters.
Quantity of gas treated and hydrogen sulphide removed is given in Table 3
below.
Table 3
Sr.No.Gas Mixture Duration Gas FlowTotal Gas Total H2S
Minutes 1 per treated, Removed,
min 1
Litres
l Nitrogen 100 0.20 18 0.92
+
HZS(5.11
%)
2 Methane + 125 0.20 22.5 0.96
HZS(4.26%
3 Carbon 115 0.20 20.7 0.9'1
Dioxide +
HZS( 4.40%
4 Air + 835 0.30 225.5 9.58
HZS(4.25%)
Above data W dicates that hydrogen sulphide removal capacity is not
significantly affected
by the presence of carbondioxide, nitrogen and methane. In case of air,
chemisorption and
regeneration were found to take place simultaneously and the bed could be used
continuously, thus resulting in the treatability of about 10 times the gas
that could be
treated in one pass in the absence of air.
Example 17
The solid bed medium (229 g) which was treated with hydrogen sulphide (black
in colour)
was packed in a glass column of 30 mm dia. Height of the catalyst bed was 300
mm.
Catalyst which was black in color was treated with ambient air for
regeneration. Air at the
rate of 0.1 Litres per minute was passed through the column. Catalyst color
started
changing from black to grayish and ultimately to reddish brown with yellow
tinge. Color
change started from the bottom portion and moved up as bottom layer of
catalyst got
regenerated. Outlet air samples were analyzed for oxygen content. The results
are given in
Table 4 below.

CA 02548071 2006-06-02
WO 2005/056164 PCT/IB2003/005687
17
Table 4
Sr.No. Time ( Minutes) Oxygen Content
1 0 20.8
2 30 4.84
3 60 5.32
4 90 8.46
S 150 17.35
6 200 20.5
Regeneration was found to be complete after 200 minute and the bed regained
hydrogen
sulphide removal activity. During regeneration, heat generation was observed
and moisture
was found deposited on the walls of the column.
S Example : 18
The solid bed medium (225 g), reddish brown in colour prepared as given in
Example 1
above is packed in a glass column of 32 mm diameter. Catalyst bed height was
3l0 mm.
Gas containing hydrogen sulphide and carbon dioxide was passed from the bottom
of the
column. After exhaustion of the catalyst bed, the same was regenerated with
ambient air.
Regenerated catalyst bed was again used for hydrogen sulphide removal.
Reaction and
regeneration cycles were carried out on the same column 20 times even after
which the bed
maintained its hydrogen sulphide removal capacity. The colour of the bed
became
yellowish due to presence of elemental sulphur. Results of the different runs
are given in
Table 5 below.
Table 5
Run No. 1 2 3 4 5 6 7 8 9 10
HZS Treated,4.013.913.59 3.642.75 3.384.354.87 3.553.99
lit
Run No 11 12 13 14 15 16 17 18 19 20
HZS Treated,3.924.463.73
lit
Example 19
The solid bed medium (100 g), reddish brown in colour, prepared as given in
Example 1
above, was taken in the glass column of 32 mm dia. and the following
experiments were
conducted with gas and air mixtures.
Case 1. A gas mixture containing hydrogen sulphide ( 1 % by volume in
carbondioxide) and
air were mixed in the ratio of 1 : 0.075 ( .075 liter air per liter of gas)
and the mixture at a
flow rate of 0.30 liters per minute was passed through the column, to enable
concurrent

CA 02548071 2006-06-02
WO 2005/056164 PCT/IB2003/005687
18
reaction and regeneration cycles. As oxygen is the regeneration agent, the gas
mixture was
prepared such that hydrogen sulphide to oxygen ratio was around 1: 1.5. The
treated gas
was tested for the presence of hydrogen sulphide. Hydrogen sulphide in out let
gas stream
was not traceable. The results and observations are given in the Table 6
below.
Case II : A gas mixture containing hydrogen sulphide ( 1.5 % by volume in
carbondioxide)
and air were mixed in the ratio of l: 0.30 ( 0. 30 liter air per liter of gas)
and the mixture at
a flow rate of 0.30 liters per minute was passed through the column, to enable
concurrent
reaction and regeneration cycles. As oxygen is the regeneration agent, the gas
mixture was
prepared such that hydrogen sulphide to oxygen ratio was around 1: 4. The
treated gas was
tested for the presence of hydrogen sulphide. Hydrogen sulphide in out let gas
stream was
not traceable. The results and observations are given in the Table 6 below.
Table 6
HZS Conc.% HZS: OZ Gas Flow RateTotal Gas
Ratio Lit/Minutes Treated,
1
Case 1 1 : 1.5 0.300 64.23
I
Case I.5 1 : 4 0.300
II
Results of the above experiments indicate that with HZS to oxygen ratio higher
than 1: 4,
the hydrogen sulphide removal and its conversion to sulphur can be carried out
in a single
step without separate reaction and regeneration cycles. This is particularly
useful for cases
where the gas containing hydrogen sulphide has no downstream applications,
hence can be
treated for its removal and then vented to air.

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Event History

Description Date
Time Limit for Reversal Expired 2013-12-05
Letter Sent 2012-12-05
Grant by Issuance 2009-10-20
Inactive: Cover page published 2009-10-19
Inactive: Final fee received 2009-07-31
Pre-grant 2009-07-31
Small Entity Declaration Request Received 2009-07-31
Notice of Allowance is Issued 2009-03-26
Letter Sent 2009-03-26
Notice of Allowance is Issued 2009-03-26
Inactive: Approved for allowance (AFA) 2009-03-23
Amendment Received - Voluntary Amendment 2009-03-18
Amendment Received - Voluntary Amendment 2009-01-23
Inactive: S.30(2) Rules - Examiner requisition 2008-09-03
Inactive: IPRP received 2008-02-05
Small Entity Declaration Determined Compliant 2007-11-22
Letter Sent 2006-12-18
Reinstatement Requirements Deemed Compliant for All Abandonment Reasons 2006-12-06
Deemed Abandoned - Failure to Respond to Maintenance Fee Notice 2006-12-05
Letter Sent 2006-11-03
Request for Examination Received 2006-09-25
Request for Examination Requirements Determined Compliant 2006-09-25
All Requirements for Examination Determined Compliant 2006-09-25
Inactive: Cover page published 2006-08-16
Inactive: Notice - National entry - No RFE 2006-08-14
Inactive: Inventor deleted 2006-08-14
Application Received - PCT 2006-06-28
Inactive: IPRP received 2006-06-03
National Entry Requirements Determined Compliant 2006-06-02
National Entry Requirements Determined Compliant 2006-06-02
Application Published (Open to Public Inspection) 2005-06-23

Abandonment History

Abandonment Date Reason Reinstatement Date
2006-12-05

Maintenance Fee

The last payment was received on 2008-08-27

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Fee History

Fee Type Anniversary Year Due Date Paid Date
MF (application, 2nd anniv.) - small 02 2005-12-05 2006-06-02
Basic national fee - small 2006-06-02
Request for examination - small 2006-09-25
Reinstatement 2006-12-06
MF (application, 3rd anniv.) - small 03 2006-12-05 2006-12-06
MF (application, 4th anniv.) - small 04 2007-12-05 2007-11-22
MF (application, 5th anniv.) - small 05 2008-12-05 2008-08-27
Final fee - small 2009-07-31
MF (patent, 6th anniv.) - small 2009-12-07 2009-10-07
MF (patent, 7th anniv.) - small 2010-12-06 2010-09-23
MF (patent, 8th anniv.) - small 2011-12-05 2011-11-01
Owners on Record

Note: Records showing the ownership history in alphabetical order.

Current Owners on Record
JAYALEKSHMY AYYER
PRADIPKUMAR MAHESHCHANDRA SHAH
VIRENDRA BHIKHABHAI PATEL
Past Owners on Record
None
Past Owners that do not appear in the "Owners on Record" listing will appear in other documentation within the application.
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Document
Description 
Date
(yyyy-mm-dd) 
Number of pages   Size of Image (KB) 
Description 2006-06-02 18 926
Claims 2006-06-02 10 390
Abstract 2006-06-02 1 51
Cover Page 2006-08-16 1 30
Claims 2006-06-03 4 204
Claims 2009-01-23 5 168
Claims 2009-03-18 5 166
Cover Page 2009-09-24 1 30
Notice of National Entry 2006-08-14 1 193
Acknowledgement of Request for Examination 2006-11-03 1 178
Courtesy - Abandonment Letter (Maintenance Fee) 2006-12-18 1 175
Notice of Reinstatement 2006-12-18 1 166
Commissioner's Notice - Application Found Allowable 2009-03-26 1 163
Maintenance Fee Notice 2013-01-16 1 170
PCT 2006-06-02 7 236
PCT 2006-06-03 9 415
Fees 2006-12-06 1 30
Fees 2007-11-22 3 106
Fees 2007-11-22 1 29
PCT 2006-06-05 9 430
Fees 2008-08-27 1 37
Correspondence 2009-07-31 1 41
Fees 2009-10-07 1 42
Fees 2010-09-23 1 38