U.S. patent application number 13/556183 was filed with the patent office on 2012-11-15 for automated sulfur recovery loop.
Invention is credited to Daniel Hage, Robert A. McLauchlan, Frederick J. Siegele.
Application Number | 20120285863 13/556183 |
Document ID | / |
Family ID | 41431504 |
Filed Date | 2012-11-15 |
United States Patent
Application |
20120285863 |
Kind Code |
A1 |
McLauchlan; Robert A. ; et
al. |
November 15, 2012 |
AUTOMATED SULFUR RECOVERY LOOP
Abstract
A method operable to remove contaminants from a contaminated
fluid stream is provided. The process includes receiving the fluid
stream containing contaminants. A first portion of the contaminants
are removed from the fluid stream with a first scrubbing vessel. A
first alkaline solution reacts with the contaminants such that the
contaminants enter a contaminant solution. A remaining portion of
the contaminants from the fluid stream is then removed with a at
least one additional scrubbing vessel, wherein a second alkaline
solution reacts with the contaminants such that part of the
remaining portion of the contaminants enter a second solution.
Water content is then removed from the fluid stream with a
desiccating module, wherein the desiccating module outputs a clean
fluid stream.
Inventors: |
McLauchlan; Robert A.;
(Austin, TX) ; Siegele; Frederick J.; (Austin,
TX) ; Hage; Daniel; (Paducah, KY) |
Family ID: |
41431504 |
Appl. No.: |
13/556183 |
Filed: |
July 23, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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12209202 |
Sep 11, 2008 |
8226893 |
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13556183 |
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61075231 |
Jun 24, 2008 |
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Current U.S.
Class: |
208/178 ;
196/14.52 |
Current CPC
Class: |
C01B 17/04 20130101;
G05D 21/02 20130101; B01D 53/52 20130101; B01D 2251/306 20130101;
B01D 2257/304 20130101; B01D 53/78 20130101; Y10T 137/7761
20150401; B01D 53/26 20130101; C01B 17/0404 20130101; B01D 53/77
20130101; B01D 53/75 20130101; B01D 53/1468 20130101; B01D 2257/80
20130101; B01D 53/1425 20130101 |
Class at
Publication: |
208/178 ;
196/14.52 |
International
Class: |
C10G 19/02 20060101
C10G019/02; B01D 11/04 20060101 B01D011/04 |
Claims
1. A scrubber comprising: an inlet operable to receive and meter a
fluid feed stream comprising hydrogen sulfide (H.sub.2S); at least
one scrubbing stage coupled to the inlet operable to receive the
fluid feed stream comprising H.sub.2S; a scrubbing solution
distribution system coupled to the at least one scrubbing stage,
the scrubbing solution distribution system operable to meter
alkaline solutions within the scrubber based on: the chemical
composition and concentration of the alkaline solutions; the
chemical composition and concentration of H.sub.2S within the fluid
stream; an outlet operable to meter and output a substantially
H.sub.2S free stream from the scrubbing stages; a process monitor
system operable to monitor physical parameters, fluid chemical
compositions, the fluid chemical compositions comprising the
concentration of H.sub.2S within the fluid stream and flow rates,
and alkaline solution chemical compositions and flow rates at at
least one point within the scrubber; and a control system coupled
to the process monitor system operable to control fluid flows,
alkaline solution flows and physical parameters within the
multistage scrubber based on the monitor physical parameters, fluid
chemical compositions and flow rates, and alkaline solution
chemical compositions.
2. The scrubber of claim 1, wherein the process monitor system is
operable to monitor chemical concentrations of fluid components
within the fluid stream.
3. The scrubber of claim 1, further comprising: a desiccating stage
operable to remove H2O from the fluid feed stream.
4. The scrubber of claim 1, whereby: the process monitor system is
operable to monitor the concentration of H.sub.2S within the
substantially H.sub.2S free stream.
5. The scrubber of claim 1, wherein a byproduct is black
liquor.
6. The scrubber of claim 5, further comprising: a black liquor
processing module operable to process the black liquor and produce
substantially elemental sulfur.
7. The scrubber of claim 1, wherein the alkaline solutions comprise
an aqueous KOH solution.
8. The scrubber of claim 1, wherein the alkaline solutions within
each of the at least one scrubbing stages are monitored and metered
at each stage individually.
9. The scrubber of claim 8, wherein a concentration of the alkaline
solutions within each of the at least one scrubbing stages
differ.
10. The scrubber of claim 2, wherein the alkaline solutions exiting
a subsequent at least one scrubbing stage is metered to a at least
one prior scrubbing stage, the at least one prior scrubbing stage
operable to remove H2S from an inlet fluid stream with the alkaline
solutions exiting a subsequent at least one scrubbing stage.
11. The scrubber of claim 1, wherein the alkaline solutions exiting
the at least one scrubbing stage is processed by a recovery module
operable to regenerate the alkaline solutions exiting the at least
one scrubbing stage.
12. A method comprising: providing a fluid feed stream comprising
hydrogen sulfide (H.sub.2S); determining a chemical composition and
concentration of H.sub.2S within the fluid feed stream; metering
the fluid feed stream to a scrubber, the scrubber comprising at
least one stage; metering an alkaline solution to the scrubber,
based on: the chemical composition and concentration of the first
alkaline solution; the chemical composition and concentration of
H.sub.2S within the fluid stream; mixing the fluid feed stream with
the first alkaline solution within the scrubber to produce a fluid
stream having a reduced H.sub.2S content; removing a solution
containing the sulfide ions from the first scrubber and directing
the solution containing the sulfide ions to a sulfur recovery
process wherein a byproduct of the sulfur recovery process is a
regenerated alkaline solution; and determining a chemical
composition and concentration of H.sub.2S within the fluid stream
having a reduced H.sub.2S content; and outputting the fluid stream
having a reduced H.sub.2S content.
13. The method of claim 12, further comprising: determining a
chemical composition and concentration of contaminants within the
fluid stream after removing a first portion of the contaminants
from the fluid stream; metering the concentrated alkaline solution
to a second scrubbing stage based on the chemical composition and
concentration of contaminants within the fluid stream after
removing a first portion of the contaminants; and removing a
remaining portion of the contaminants from the fluid stream with at
least one additional scrubbing stage, wherein the concentrated
alkaline solution reacts with the contaminants such that part of
the remaining portion of the contaminants enter a second alkaline
solution.
14. The method of claim 13, further comprising: determining a base
concentration of the second alkaline solution, wherein the first
alkaline solution comprises the reacted second alkaline
solution.
15. The method of claim 11, further comprising: determining a base
concentration of the concentrated alkaline solution, wherein the
first alkaline solution comprises the concentrated alkaline
solution.
16. The method of claim 11, wherein the contaminates comprise
sulfur containing compounds.
17. The method of claim 11, wherein the contaminates comprise
hydrogen sulfide (H.sub.2S).
18. The method of claim 11, further comprising: extracting
contaminates from the contaminate solution; and regenerating the
contaminant solution, wherein the first alkaline solution comprises
regenerated contaminant solution.
19. A fluid stream comprising: hydrocarbons and hydrogen sulfide
(H.sub.2S), wherein: a first portion of the H.sub.2S is removed
within an automated H.sub.2S scrubber comprising at least one
stage, the automated H.sub.2S scrubber operable to: monitor in real
time the chemical composition and concentration of H.sub.2S within
the fluid stream; adjust chemical processes within the H.sub.2S
scrubber based on the real time the chemical composition and
concentration of H.sub.2S within the fluid stream; and produce a
substantially H.sub.2S free fluid stream.
20. The fluid stream of claim 19, the scrubber comprising: an inlet
operable to receive and meter the fluid feed stream comprising
H.sub.2S; at least one scrubbing stage coupled to the inlet
operable to receive and process the fluid feed stream comprising
H.sub.2S; a scrubbing solution distribution system coupled to the
at least one scrubbing stage scrubbing stage, the scrubbing
solution distribution system operable to meter alkaline solutions
within the scrubber based on: the chemical composition and
concentration of the alkaline solutions; the chemical composition
and concentration of H.sub.2S within the fluid stream; an outlet
operable to meter and output a substantially H.sub.2S free stream
from the scrubbing stages; a process monitor system operable to
monitor physical parameters, fluid chemical compositions and flow
rates, and alkaline solution chemical compositions and flow rates
within the scrubber; and a control system coupled to the process
monitor system operable to control fluid flows, alkaline solution
flows and physical parameters within the scrubber based on the
monitor physical parameters, fluid chemical compositions and flow
rates, and alkaline solution chemical compositions.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present U.S. Utility Patent Application claims priority
pursuant to 35 U.S.C. .sctn.120, as a continuation, to the
following U.S. Utility Patent Application which is hereby
incorporated herein by reference in its entirety and made part of
the present U.S. Utility Patent Application for all purposes:
[0002] 1. U.S. Utility Application Serial No. 12/209,202, entitled
"AUTOMATED SULFUR RECOVERY LOOP," (Attorney Docket No. GNG
P001USC1), filed Sep. 11, 2008 which claims priority pursuant to 35
U.S.C. .sctn.119(e) to the following U.S. Provisional Patent
Application which is hereby incorporated herein by reference in its
entirety and made part of the present U.S. Utility Patent
Application for all purposes:
[0003] a. U.S. Provisional Application Ser. No. 61/075,231,
entitled "HYDROGEN SULFIDE SCRUBBER," (Attorney Docket No. GNG
P001USP), filed Jun. 24, 2008.
TECHNICAL FIELD OF THE INVENTION
[0004] The present invention relates generally to an improved
method for removing contaminants from fluid streams. More
specifically, the present invention relates to a method for
removing sulfur and sulfur containing compounds from fluids.
BACKGROUND OF THE INVENTION
[0005] Hydrogen Sulfide (H.sub.2S) is a toxic gas that places
restrictions on the materials than can be used for piping and other
equipment handling sour gas, as many metals are sensitive to
sulfide stress cracking. The presence of H.sub.2S in gas causes
lower quality burning and the production of sulfur dioxide, and so
is regulated in commercially sold gas.
[0006] H.sub.2S has an offensive odor of "rotten eggs" at
concentrations as low as 50 parts per billion by volume (ppbv) and
is toxic at concentrations above 1000 parts per million by volume
(ppmv). H.sub.2S is a health and safety hazard, and when combined
with carbon dioxide (CO.sub.2) and water vapor (H.sub.2O), corrodes
plant equipment such as boilers and piping, and can ruin
power-generating equipment. Energy production is hampered if
H.sub.2S gas is present. This is especially true as the cost of
energy increases.
[0007] Sour gas is natural gas or any other gas containing
significant amounts of H.sub.2S. Natural gas is usually considered
sour if there are more than 5.7 milligrams of H.sub.2S per cubic
meter of natural gas, which is equivalent to approximately 4 ppm by
volume.
[0008] Although the terms acid gas and sour gas are used
interchangeably, strictly speaking, a sour gas is any gas that
contains H.sub.2S in significant amounts, whereas an acid gas is
any gas that contains significant amounts of acidic gases such as
carbon dioxide (CO.sub.2) or H.sub.2S. Thus, carbon dioxide by
itself is an acid gas but it is not a sour gas.
[0009] Before a raw natural gas containing H.sub.2S and/or carbon
dioxide can be used, the raw gas must be treated to remove those
impurities to acceptable levels, commonly by an amine gas treating
process. The removed H.sub.2S is most often subsequently converted
to by-product elemental sulfur in a Claus process.
[0010] Processes within oil refineries or natural gas processing
plants that remove mercaptans and/or H.sub.2S are commonly referred
to as sweetening processes because they result in products which no
longer have the sour, foul odors of mercaptans and H.sub.2S.
BRIEF SUMMARY OF THE INVENTION
[0011] Embodiments of the present invention are directed to systems
and methods that are further described in the following description
and claims. Advantages and features of embodiments of the present
invention may become apparent from the description, accompanying
drawings and claims.
[0012] An embodiment of the present invention provides a method to
remove contaminants such as hydrogen sulfide (H2S) from a
contaminated fluid stream such as but not limited to natural gas.
This method involves receiving the fluid stream or natural gas
containing contaminants. A determination is made of the chemical
composition and concentration of contaminants and hydrocarbons
within the fluid stream. A first-base solution may be metered to a
first scrubbing stage based on the chemical composition and
concentration of the contaminants and hydrocarbons within the fluid
stream. A first portion of the contaminants are removed from the
fluid stream with a first scrubbing stage to produce a resultant
fluid stream having reduced contaminants and a contaminant
solution. Water may be desiccated or removed from the resultant
fluid stream to produce a substantially contaminant-free fluid
stream. The water reacts within the desiccating process to form a
concentrated base solution which may be metered (with water if
necessary) within the scrubbing stages to provide the first base
solution.
[0013] Another embodiment provides a process for removing
contaminants such as H2S from a petroleum fluid feed stream. This
process involves providing a fluid feed stream such as that
provided at a well or petroleum distribution network. This fluid
feed stream includes or contains H2S in varying amounts. Real time
monitoring may be performed to determine a chemical composition and
concentration of H2S within the fluid's feed stream. This fluid
feed stream may be metered to a multi-stage scrubbing system.
Additionally an alkaline solution or base solution may be metered
to the multi-stage scrubber as well. The alkaline solution may be
metered based on the chemical composition and concentration of the
first alkaline solution, the chemical composition of the fluid
stream, and the concentration of H2S within the fluid feed stream.
Additionally the fluid feed stream as previously stated may be
metered within the multi-stage scrubber. The fluid feed stream
mixes with the first alkaline solution within the first scrubber to
produce a fluid stream having a reduced H2S content. A solution
containing sulfide ions that was produced during the mixing of the
fluid feed stream with the first alkaline solution may be removed
from the first scrubber. The solution containing sulfide ions may
be directed to a sulfur recovery process. A byproduct of the sulfur
recovery process may be a regenerated alkaline solution which may
again be metered within the multi-stage scrubber. A chemical
composition and concentration of H2S within the fluid stream having
a reduced H2S content may then be determined. Based on this
information, the fluid stream may be metered and outputted to a
distribution network. Additionally the fluid having a reduced H2S
content may be processed by additional scrubbing stages or
desiccated. In either case an alkaline solution may be produced as
well as a substantially H2S free fluid stream. The concentrated
alkaline solution may be mixed or metered with the regenerated
alkaline solution and delivered within the multi-stage scrubber to
produce an alkaline solution of a desired or controlled
concentration in order to affect the removal of H2S from the fluid
stream.
[0014] Another embodiment of the present invention provides a
multi-stage scrubber operable to remove contaminants such as H2S
from a petroleum fluid stream. This multi-stage scrubber includes
an inlet, a first scrubbing stage, at least one additional
scrubbing stage, a scrubbing solution distribution system, a
process monitor system and a control system. The inlet may receive
and meter the fluid stream having H2S therein. The first scrubbing
stage couples to the inlet to receive the fluid feed stream. The
additional in-stage scrubbing stages may be available to further
process a fluid stream having H2S in either series or parallel
based on the measured concentration. A scrubbing solution
distribution system couples to the various scrubbing stages and
meters alkaline solutions within the scrubber based on the chemical
composition and concentration of the alkaline solutions and their
sources and the chemical composition and concentration of H2S
within the fluid stream. An outlet meters and outputs a
substantially H2S-free stream from the scrubbing stages. A process
monitor system monitors various physical parameters such as but not
limited to pressure, temperature volume flow rates fluid chemical
compositions of the petroleum fluid stream, alkaline solution
chemical compositions and flow rates within the multi-stage
scrubber, as well as contaminant concentrations within the
petroleum fluid streams. A control system couples to the process
monitor to control petroleum fluid flows, alkaline solution flows,
and the physical parameters within the various stages of the
multi-stage scrubber based on the monitored physical parameters,
fluid chemical compositions and flow rates, and alkaline solutions
and chemical compositions.
[0015] Yet another embodiment provides a fluid stream compromising
H2S and hydrocarbons. A first portion of the H2S is removed within
an automated multi-stage H2S scrubber. This automated multi-stage
.sub.H2S scrubber is operable to monitor in real time the chemical
composition and concentration of H2S within the fluid stream,
adjust the chemical processes within the multi-stage H2S scrubber
based on the real time chemical composition and concentration of
H2S within the petroleum fluid stream and produce a substantially
H2S-free petroleum fluid stream. This multi-stage scrubber may also
monitor the H2S concentration of the substantially H2S free stream
and supply this information to downstream processes such as
downstream processes may be configured based on that chemical
composition.
[0016] An embodiment provides a scrubber comprising: an inlet
operable to receive and meter a fluid feed stream comprising
hydrogen sulfide (H.sub.2S); at least one scrubbing stage coupled
to the inlet operable to receive the fluid feed stream comprising
H.sub.2S; a scrubbing solution distribution system coupled to the
at least one scrubbing stage, the scrubbing solution distribution
system operable to meter alkaline solutions within the scrubber
based on: the chemical composition and concentration of the
alkaline solutions; the chemical composition and concentration of
H.sub.2S within the fluid stream; an outlet operable to meter and
output a substantially H.sub.2S free stream from the scrubbing
stages; a process monitor system operable to monitor physical
parameters, fluid chemical compositions, the fluid chemical
compositions comprising the concentration of H.sub.2S within the
fluid stream and flow rates, and alkaline solution chemical
compositions and flow rates at at least one point within the
scrubber; and a control system coupled to the process monitor
system operable to control fluid flows, alkaline solution flows and
physical parameters within the multistage scrubber based on the
monitor physical parameters, fluid chemical compositions and flow
rates, and alkaline solution chemical compositions. The process
monitor system can monitor chemical concentrations of fluid
components within the fluid stream. The embodiment may further
include a desiccating stage that can remove H2O from the fluid feed
stream. The process monitor system can monitor the concentration of
H.sub.2S within the substantially H.sub.2S free stream. A byproduct
can be black liquor, wherein the black liquor can be processed by a
processing module to produce substantially elemental sulfur. In an
embodiment, the alkaline solutions can comprise an aqueous KOH
solution. In an embodiment, the alkaline solutions within each of
the at least one scrubbing stages can be monitored and metered at
each stage individually, wherein a concentration of the alkaline
solutions within each of the at least one scrubbing stages differ.
In an embodiment, the alkaline solutions exiting a subsequent
scrubbing stage is metered to a prior scrubbing stage, the prior
scrubbing stage operable to remove H2S from an inlet fluid stream
with the alkaline solutions exiting a subsequent scrubbing stage.
The alkaline solutions exiting the at least one scrubbing stage can
be processed by a recovery module operable to regenerate the
alkaline solutions exiting the at least one scrubbing stage.
[0017] Another embodiment provides a method comprising: providing a
fluid feed stream comprising hydrogen sulfide (H.sub.2S);
determining a chemical composition and concentration of H.sub.2S
within the fluid feed stream; metering the fluid feed stream to a
scrubber, the scrubber comprising at least one stage; metering an
alkaline solution to the scrubber, based on: the chemical
composition and concentration of the first alkaline solution; the
chemical composition and concentration of H.sub.2S within the fluid
stream; mixing the fluid feed stream with the first alkaline
solution within the scrubber to produce a fluid stream having a
reduced H.sub.2S content; removing a solution containing the
sulfide ions from the first scrubber and directing the solution
containing the sulfide ions to a sulfur recovery process wherein a
byproduct of the sulfur recovery process is a regenerated alkaline
solution; determining a chemical composition and concentration of
H.sub.2S within the fluid stream having a reduced H.sub.2S content;
and outputting the fluid stream having a reduced H.sub.2S content.
The method may further comprise: determining a chemical composition
and concentration of contaminants within the fluid stream after
removing a first portion of the contaminants from the fluid stream;
metering the concentrated alkaline solution to a second scrubbing
stage based on the chemical composition and concentration of
contaminants within the fluid stream after removing a first portion
of the contaminants; and removing a remaining portion of the
contaminants from the fluid stream with at least one additional
scrubbing stage, wherein the concentrated alkaline solution reacts
with the contaminants such that part of the remaining portion of
the contaminants enter a second alkaline solution. In an embodiment
the method may further comprise determining a base concentration of
the second alkaline solution, wherein the first alkaline solution
comprises the reacted second alkaline solution. In an embodiment
the method may further comprise determining a base concentration of
the concentrated alkaline solution, wherein the first alkaline
solution comprises the concentrated alkaline solution. In an
embodiment, the contaminates comprise sulfur containing compounds
such as hydrogen sulfide (H.sub.2S). In an embodiment the method
may further comprise extracting contaminates from the contaminate
solution; and regenerating the contaminant solution, wherein the
first alkaline solution comprises regenerated contaminant
solution.
[0018] An embodiment provides a fluid stream comprising:
hydrocarbons and hydrogen sulfide (H.sub.2S), wherein: a first
portion of the H.sub.2S is removed within an automated H.sub.2S
scrubber comprising at least one stage, the automated H.sub.2S
scrubber operable to: monitor in real time the chemical composition
and concentration of H.sub.2S within the fluid stream; adjust
chemical processes within the H.sub.2S scrubber based on the real
time the chemical composition and concentration of H.sub.2S within
the fluid stream; and produce a substantially H.sub.2S free fluid
stream. The scrubber comprises an inlet operable to receive and
meter the fluid feed stream comprising H.sub.2S; at least one
scrubbing stage coupled to the inlet operable to receive and
process the fluid feed stream comprising H.sub.2S; a scrubbing
solution distribution system coupled to the at least one scrubbing
stage scrubbing stage, the scrubbing solution distribution system
operable to meter alkaline solutions within the scrubber based on:
the chemical composition and concentration of the alkaline
solutions; the chemical composition and concentration of H.sub.2S
within the fluid stream; an outlet operable to meter and output a
substantially H.sub.2S free stream from the scrubbing stages; a
process monitor system operable to monitor physical parameters,
fluid chemical compositions and flow rates, and alkaline solution
chemical compositions and flow rates within the scrubber; and a
control system coupled to the process monitor system operable to
control fluid flows, alkaline solution flows and physical
parameters within the scrubber based on the monitor physical
parameters, fluid chemical compositions and flow rates, and
alkaline solution chemical compositions.
BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS
[0019] For a more complete understanding of the present invention
and the advantages thereof, reference is now made to the following
description taken in conjunction with the accompanying drawings in
which like reference numerals indicate like features and
wherein:
[0020] FIG. 1 provides a process flow diagram of a process operable
to remove sulfur containing compounds from a gas stream in
accordance with embodiments of the present invention;
[0021] FIG. 2 provides a process flow diagram of a process operable
to remove sulfur containing compounds from a gas stream in
accordance with embodiments of the present invention that
explicitly shows sulfur recovery loop coupled to the process;
[0022] FIG. 3 provides a process flow diagram of a process operable
to remove sulfur containing compounds from a gas stream with
potassium hydroxide (KOH) in accordance with embodiments of the
present invention;
[0023] FIG. 4 provides a process flow diagram of a N-stage process
operable to remove sulfur containing compounds from a gas stream in
accordance with embodiments of the present invention;
[0024] FIG. 5 provides a process flow diagram of an N-stage process
operable to monitor various process parameters and optimize
processes to remove sulfur containing compounds from a gas stream
in accordance with embodiments of the present invention;
[0025] FIG. 6 provides an automated and controlled process to
remove sulfur-containing compounds from a fluid stream in
accordance with embodiments of the present invention;
[0026] FIG. 7 provides a block diagram of an aqueous iron scrubber
in accordance with the embodiments of the present invention;
[0027] FIG. 8 provides a block diagram of a H.sub.2S removal
process in accordance with embodiments of the present
invention;
[0028] FIG. 9 provides a logic flow diagram of a method to remove
contaminants from a contaminated fluid stream; and
[0029] FIG. 10 provides a process flow diagram of a process
operable to remove contaminants from a contaminated fluid stream,
such as a petroleum stream, in accordance with embodiments of the
present invention.
DETAILED DESCRIPTION OF THE INVENTION
[0030] Preferred embodiments of the present invention are
illustrated in the FIGs., like numerals being used to refer to like
and corresponding parts of the various drawings.
[0031] Embodiments of the present invention provide a scrubber or
scrubbing process for removal of hydrogen sulfide (H.sub.2S) gas
and particulate matter, as well as other contaminates from gas
streams such as natural gas or a biogas as it is produced.
Embodiments may provide automated H.sub.2S removal and recovery
within a closed or partially closed loop where raw materials are
regenerated and recycled. Measurement and control systems allow the
automated H.sub.2S removal process to efficiently operate over a
wide range of variables (gas flows, contaminates, H.sub.2S
concentrations etc.) The H.sub.2S may be converted to elemental
sulfur or black liquor which may be sold.
[0032] Petroleum is a complex mixture of organic liquids consisting
of a complex mixture of hydrocarbons of various molecular weights,
plus other organic compounds. Petroleum is often referred to as
crude oil and natural gas. Crude oil and natural gas vary from well
to well, oilfield to oilfield, and over time in color and
composition, from a pale yellow low viscosity liquid to heavy black
`treacle` consistencies. Crude oil and natural gas are extracted
from beneath the earth's surface using wells and are then
transported to refineries where their components are processed into
refined products. These products may include but are not limited to
fuels, gasoline or petrol, diesel, lubricating oil, fuel oil,
bitumen, lubricating oils, waxes, asphalt, petrochemicals and
pipeline quality natural gas. Natural gas from the well, while
principally methane, contains quantities of other
hydrocarbons--ethane, propane, butane, pentane and also carbon
dioxide and water. These components are separated from the methane
at a gas fractionation plant.
[0033] A refinery (distillation and gas fractionation plants)
provides an organized and coordinated arrangement of manufacturing
processes designed to produce physical and chemical changes in
crude oil. As petroleum (crude oil and natural gas) is extracted
from the ground, the extracted fluids include a mixture of
hydrocarbon compounds and quantities of other materials such as
oxygen, carbon dioxide, H.sub.2S, nitrogen, sulfur, salts and
water. These other materials may vary in volume and concentration
over time. Most of these non-hydrocarbon substances are currently
removed at the refineries where the petroleum is broken down into
its various components, and blended into useful products. Handling
toxic materials such as H.sub.2S place a burden on the refinery and
the networks used to transport the petroleum. Embodiments of the
present invention allow problems with H.sub.2S to be substantially
addressed in the field prior to transportation to the refinery.
[0034] Sulfur and H.sub.2S content range from traces to more than
90 percent and vary over time. Crude oil or natural gas containing
appreciable quantities of sulfur it is called sour, if it contains
little or no sulfur it is called sweet. H.sub.2S often results from
the bacterial break down of sulfates in organic matter in the
absence of oxygen, such as in swamps and sewers (anaerobic
digestion). It also occurs in volcanic gases, natural gas,
petroleum and some well waters.
[0035] A number of contaminants are found in crude oil. As the
fractions travel through the refinery processing units, these
impurities, such as H.sub.2S, can damage the equipment, the
catalysts and the quality of the products. There are also legal
limits on the contents of some impurities, like sulfur, in
products.
[0036] Hydrotreating is one way of removing many of the
contaminants from many of the intermediate or final products. In
the hydrotreating process, the entering feedstock is mixed with
hydrogen and heated to 300-380.degree. C. The oil combined with the
hydrogen then enters a reactor loaded with a catalyst which
promotes several reactions:
H.sub.2+S.fwdarw.H.sub.2S eq. 1
[0037] Nitrogen (N) compounds are converted to ammonia (NH3);
[0038] The H.sub.2S created is a toxic gas that needs further
treatment. The usual process involves two steps: [0039] (1) the
removal of the H.sub.2S gas from the hydrocarbon stream; and [0040]
(2) the conversion of H.sub.2S to elemental S, a non-toxic and
useful chemical.
[0041] In one instance solvent extraction, using an amine solution
such as but not limited to diethanolamine (DEA) dissolved in water,
may be applied to separate the H.sub.2S gas from the process
stream. The hydrocarbon gas stream containing the H.sub.2S is
bubbled through a solution of DEA under high pressure, such that
the H.sub.2S gas dissolves in the DEA. The DEA and hydrogen mixture
is the heated at a low pressure and the dissolved H.sub.2S is
released as a concentrated gas stream which is sent for conversion
into Sulfur. This process is further discussed with reference to
FIG. 6.
[0042] The Claus process provides for the conversion of the
concentrated H.sub.2S gas into elemental sulfur in two stages.
First, part of the H.sub.2S stream is combusted in a furnace,
producing sulfur dioxide (SO.sub.2) water (H.sub.2O) and sulfur (S)
as shown in equation 2.
2H.sub.2S+2O.sub.2.fwdarw.SO.sub.2+S+2H.sub.2O eq. 2
Reaction of the remainder of the H.sub.2S occurs in the presence of
a catalyst. The H.sub.2S reacts with the SO.sub.2 to form
sulfur.
2H.sub.2S+2O.sub.2.fwdarw.3S+2H.sub.2O eq. 3
As the reaction products are cooled the sulfur drops out of the
reaction vessel in a molten state. Sulfur can be stored and shipped
in either a molten or solid state.
[0043] FIG. 1 provides a process flow diagram of a process operable
to remove sulfur containing compounds from a gas stream in
accordance with embodiments of the present invention. Process 100
includes a multiple stage scrubber having a first stage scrubber
102, a second stage scrubber 104 and a desiccating module 106. A
gas stream containing sulfur compounds 112 may be provided to a
first stage scrubber 102. This gas stream may contain H.sub.2S. The
first stage scrubber 102 may be an aqueous scrubber that allows the
gas feed stream to interact with a first alkaline solution in order
to form black liquor and a partially cleaned wet gas stream
114.
[0044] The scrubber may be a gas-liquid contactor that has as its
basis an impeller-shroud mixing device or other like device known
to those having skill in the art. The scrubber removes H.sub.2S
from a gas stream using a regenerating scrubbing solution. Gases
are routed through a scrubbing vessel (having one or more stages)
where up to about 99% of the H.sub.2S is extracted with an aqueous
scrubbing solution in the first stage.
[0045] The alkaline solution may be based on potassium hydroxide
(KOH). The chemical compound potassium hydroxide (KOH), sometimes
known as caustic potash, potassa, potash lye, and potassium
hydrate, is a metallic base. It is very alkaline and is a "strong
base", along with sodium hydroxide, lithium hydroxide, calcium
hydroxide, barium hydroxide and strontium hydroxide. Pure potassium
hydroxide is a colorless, highly hygroscopic, solid crystalline
compound, having density of about 2.04 g/cm.sup.3, readily soluble
in water (1 g KOH dissolves in 0.5 g water). Potassium hydroxide
forms solid hydrates, namely the monohydrate KOH.H.sub.2O, the
dihydrate KOH.2H.sub.2O, and the tetrahydrate KOH.4H.sub.2O; it is
used therefore as a highly intensive desiccant agent, e.g. for
drying liquid amines or their solutions in indifferent, nonpolar
solvents (such as hydrocarbons).
[0046] The black liquor may be processed using a sulfur recovery
loop. Potash (KOH) black liquor recovery may include acidifying and
causticizing steps as is done in many pulp processes. The main
components of the liquor are KOH and K.sub.2S. A water enclosed
circulation is used. The black liquor is successively acidified and
causticized to separate out deposited dregs and clear liquid. The
deposited dregs can be used to prepare compound organic fertilizer
containing K and Sulfur and the clear liquid can be reused to
prepare black liquor in the scrubbers.
[0047] The partially cleaned wet gas stream containing some sulfur
compounds may then be provided to an additional scrubbing stage
such as second stage scrubber 104. Although shown here with two
aqueous scrubbing stages any number of scrubbing stages may be
utilized. This allows individual scrubbing stages to be optimized
for the concentration of H.sub.2S gas encountered or other
contaminants encountered in gas stream 112. Although these stages
are shown in series, a multistage scrubber may have parallel stages
that can be reconfigured based on measured conditions associated
with gas stream 112. The partially cleaned wet gas stream 114 mixes
with an additional alkaline solution in the second stage scrubber.
The output of the second stage scrubber may be a wet, clean gas
stream 116 and a concentrated alkaline solution containing sulfide
ions. The alkaline solution containing sulfide ions may be supplied
as a feed to the alkaline solution of the first stage scrubber 102.
The wet clean gas stream may be supplied to a desiccating module or
process 106. This desiccating module may use a dry metallic base
120 to desiccate the wet clean gas stream in order to produce a dry
clean gas stream 118. The metallic base 120 that absorbs water may
be become a concentrated aqueous metallic base solution 122 which
may serve as an input to the second stage scrubber 104 in order to
form an alkaline solution in that second stage scrubber.
Additionally, a concentrated aqueous metallic base solution may
also be received from this sulfur recovery process. The sulfur
recovery process may process the black liquor in order to recover
elemental sulfur and regenerate the metallic base solution used to
remove sulfur compounds from the gas stream 112.
[0048] FIG. 2 provides a process flow diagram of a process operable
to remove sulfur containing compounds from a gas stream in
accordance with embodiments of the present invention that
explicitly shows sulfur recovery loop coupled to the process 100.
In FIG. 1 the black liquor may be removed from the first stage
scrubber 102 as a viable commercial product that may be sold and
processed onsite or offsite to recover elemental sulfur and produce
an aqueous metallic base solution. As shown here in FIG. 2 this
sulfur recovery loop may be part of the process that allows the
sulfur recovery loop to not only output elemental sulfur but also a
concentrated aqueous metallic base solution to the second stage
scrubber 104.
[0049] FIG. 3 provides a process flow diagram of a process operable
to remove sulfur containing compounds from a gas stream with
potassium hydroxide (KOH) in accordance with embodiments of the
present invention. Unlike FIG. 1, FIG. 3 specifically shows that
multiple aqueous stage scrubbers may be used to remove H.sub.2S and
other contaminants such as CO.sub.2 from the gas stream 112. The
number of stages may depend on the concentration and flow rates of
contaminants within the gas stream. The concentration of the
aqueous metallic base solution at the various stages may be
adjusted in order to achieve the desired reaction rate. For example
the first stage may have a lower concentration of the aqueous
metallic base solution while later stages have higher
concentrations of aqueous metallic base solution wherein as the
concentration of H.sub.2S within the various stages decreases in
order to achieve a desired reaction rate the concentration of the
aqueous metallic base solution may be increased. As shown
previously recovery loop may be used to recycle and reintroduce the
aqueous metallic base solution into later stage scrubbers. Not
shown would be a water makeup system that provides water to the
aqueous stage scrubbers in order to ensure the desired
concentrations at the specific stages.
[0050] FIG. 4 provides a process flow diagram of an N-stage process
operable to remove sulfur containing compounds from a gas stream in
accordance with embodiments of the present invention. FIG. 4
provides a process flow diagram of a variable stage process flow
operable to remove sulfur-containing compounds from a gas stream in
accordance with embodiments of the present invention. Unlike FIG.
1, FIG. 4 specifically shows that multiple aqueous stage scrubbers
may be used to remove H.sub.2S and other contaminants such as
CO.sub.2 from the gas stream 112. The number of stages may depend
on the concentration and flow rates of contaminants within the gas
stream. The concentration of the aqueous metallic base solution at
the various stages may be adjusted in order to achieve the desired
reaction rate. For example the first stage may have a lower
concentration of the aqueous metallic base solution while later
stages have higher concentrations of aqueous metallic base solution
wherein as the concentration of H.sub.2S within the various stages
decreases in order to achieve a desired reaction rate the
concentration of the aqueous metallic base solution may be
increased. As shown previously recovery loop may be used to recycle
and reintroduce the aqueous metallic base solution into later stage
scrubbers. Not shown would be a water makeup system that provides
water to the aqueous stage scrubbers in order to ensure the desired
concentrations at the specific stages.
[0051] FIG. 5 provides a process flow diagram of an N-stage process
operable to monitor various process parameters and optimize
processes to remove sulfur containing compounds from a gas stream
in accordance with embodiments of the present invention. A process
monitoring and control system 502 may be coupled to and control the
flow of concentrated aqueous metallic base solutions to the various
stages in order to ensure the desired reaction rates. Additionally,
the Process monitor and control system may monitor and control the
chemical composition, pressure, temperature, flow rate, and volume
of all fluid streams both to and within the various reactors and
processing modules within the process.
[0052] FIG. 5 specifically adds process monitors 502 which may
monitor (in real time or specified intervals) the chemical
composition, pressure, temperature, gas concentrations and aqueous
concentrations of various components within the process. For
example gas monitors 502 may provide spectroscopic monitoring of
the incoming gas stream 112 to identify the concentration of
H.sub.2S within the gas stream as well as any other contaminant
components within the gas stream. This monitoring may be done at
various stages within the process flow such that flow rates,
chemical concentrations, pressures and temperatures may be varied
in order to achieve the desired dry clean gas. Additionally stages
may be bypassed when not needed. This may be due to a varying
concentration of contaminants in the feed stream gas stream 112.
Thus the present invention allows by dynamically monitoring the
concentration of components within solution and gas the processes
may be optimized to extract the contaminants.
[0053] The H.sub.2S scrubber may be located following a gas/liquid
separator and before an optional dehydration process that may be
incorporated within the scrubbing system as shown in the FIGs. The
level of H.sub.2S on the various H.sub.2S scrubber stage outputs
depends on several variables including but not limited to inlet
H.sub.2S (PPM), inlet mercaptan concentration (ppm), gas flow rate
(MMscfd), inlet pressure (psig), relative humidity, reactor
dimensions, and gas temperature.
[0054] As flow conditions vary greatly over location and time,
embodiments of the present invention apply process monitors that
may continually monitor the above identified variables. Process
conditions and chemical concentrations may then be metered or
controlled to optimize reaction rates. This prevents problems
associated with prior solutions where operators injected large
amounts of chemicals to cover peak production periods and spikes in
input H.sub.2S concentrations. This prior solution required
over-injection, wasted money and failed to optimize process
conditions for given contamination levels.
[0055] Embodiments of the present invention provide improved
effectiveness of the chemical injection methods by controlling
proper dispersion of the proper amount and concentration of
chemicals into the fluid stream with and sufficient concentration
and contact time. This controlled injection and process monitoring
reduces opportunities for solidification that cause blockages in
pipes and equipment and foaming.
[0056] Foaming occurs when hydrocarbons condense in the liquid or
as a result of variations in flow rate and pressure. Foaming causes
carry over of the liquid which can affect downstream processes. To
prevent foaming, defoaming agents are introduced. Continuous
monitoring and control of chemical concentrations and liquid levels
may prevent foaming.
[0057] FIG. 6 provides an automated and controlled process to
remove sulfur-containing compounds from a fluid stream in
accordance with embodiments of the present invention. FIG. 6
applies the process monitoring and control systems described
previously to an Amine scrubbing process. Process 600 includes one
or more amine scrubbing stages 602, multiple process monitors 604,
and amine and H.sub.2S separating module 606, a sulfur recovery
loop 608 and a desiccating module 610. A fluid stream containing
sulfur compounds 112 may be provided to a first stage amine
scrubber 602 where an amine solution such as DEA dissolved in water
may be applied to separate the H.sub.2S gas from the fluid stream.
The amine and H.sub.2S are directed to a separating module 606
while the cleaned fluid stream 612 may be directed to an optional
desiccating module 610. The separating module 606 may apply heat to
the amine and H.sub.2S solution or mixture such that dissolved
H.sub.2S is released as a concentrated H.sub.2S gas stream which
may be supplied to the sulfur recovery loop 608. The regenerated
amine may be redirected to the first stage amine scrubber 602.
[0058] Sulfur recovery loop 608 may use one of many processes to
recover elemental sulfur from the H.sub.2S gas. This may be done
using a Claus process, an iron-based process, catalyst based, SANS
based or base metal process such as but not limited to those
discussed in this application. Optional desiccating module 610 may
be used to remove water from the substantially cleaned fluid
exiting the amine scrubbing stages 602 in order to produce a dry
clean fluid stream 614. Process monitor 604 may provide continuous
process monitoring of the chemical composition of various streams
and points in the action this allows the chemical reactions in the
various stages to be optimized by controlling concentrations,
pressure, temperature and other variables known to those having
skill in the art. For example the fluid stream containing sulfur
compounds 112 may vary greatly thus the concentration of amine and
the amount of amine solution in the scrubber may vary additionally
other stages may be placed online or offline such as an iron-based
scrubbing stage or an alkaline metal-based scrubbing stage
depending on the concentration. By monitoring the amine
concentration of the solution within Scrubber 602 in equality of
the amine within the Scrubber 602 the need for makeup amine may be
closely monitored and allow remote monitoring of the status of the
raw materials used to remove sulfur compounds. Similarly the sulfur
recovery loop may be monitored for the amount of H.sub.2S gas being
processed and thus the amount of feedstock required to remove the
H.sub.2S.
[0059] A polyvalent metal compound such iron (Fe) may be used in a
solid or aqueous form as a scrubbing agent to remove H.sub.2S from
the fluid stream as well. This iron may in one embodiment take the
form of Fe.sub.2O.sub.3 and/or Fe.sub.3O.sub.4. Polyvalent metal
compounds such as Fe.sub.2O.sub.3 and/or Fe.sub.3O.sub.4 may be
provided as a substantially uniform and granular material. This
polyvalent metal compound is both stable and non-pyrophoric and may
react with H.sub.2S to form another stable compound, an iron
sulfide with the formula FeS.sub.2. Such a process may be selective
to H.sub.2S, and yield little or no undesirable byproducts.
Furthermore, the substantially uniform shape and size of some
polyvalent metal compounds material may prevent channeling.
[0060] FIG. 7 provides a block diagram of an aqueous iron scrubber
in accordance with the embodiments of the present invention. The
fluid stream containing process 700 includes an aqueous iron
H.sub.2S scrubber 702 which may be one or more stages, multiple
process monitors 704, Control system 705, optional desiccating
module 706, aqueous iron regeneration module 708, and a solid
separator 710. The process may work at both ambient temperature and
pressure although the chemical process may be controlled by
adjusting both temperature and pressure as well as concentration of
various chemical components and solutions such as the iron oxide
solution concentrations.
[0061] Aqueous H.sub.2S scrubber 702 creates a bath of reacted
water that fluid stream 112 flows through. This may flow through
the bottom of the scrubber. H.sub.2S in the fluid stream may be
absorbed by the reacted water and may be subsequently converted in
to elemental sulfur and iron sulfide. Sulfur generated may be
removed from the aqueous solution by filtration or a solid
separator 710. The reacted water may then again be regenerated and
passed through the scrubber for further cleaning of sour gas.
H.sub.2S when dissolved in the aqueous solution is ionized to
hydrogen and sulfur. The sulfur ions can be oxidized by polyvalent
metal ions such as but not limited to iron which can exist in both
a ferric and ferrous state. The sulfur ion contacts the polyvalent
metal ion to become oxidized where it is oxidized to elemental
sulfur and precipitated. The chemical reaction is shown in Equation
Four. These metal ions may be later oxidized to ferric ions by
reaction with atmospheric oxygen in the aqueous iron regeneration
module 708. Embodiments of the present invention provide a process
that is highly selective to H.sub.2S. The H.sub.2S may be converted
to elemental sulfur which has commercial value. Process monitor 704
allows the concentrations of iron in the scrubber to be adjusted
based on incoming fluid streams.
[0062] FIG. 8 provides a block diagram of a H.sub.2S removal
process in accordance with embodiments of the present invention.
This process may be applied to sour natural gas at well heads to
remove H.sub.2S and convert the H.sub.2S to elemental sulfur via
the liquid-phase modified Claus reaction. The process provide by
embodiments of the present invention may not be affected by
contaminants such as but not limited to carbon dioxide, oxygen,
mercaptans, and heavy hydrocarbons.
[0063] H.sub.2S may be removed from the sour gas in a conventional
tray absorber 804. The H.sub.2S reacts with dissolved sulfur
dioxide (SO.sub.2) to produce dissolved elemental sulfur, which has
a high solubility in a sulfur-amine nonaqueous sorbent (SANS).
Operating conditions within the absorber are monitored and
controlled in real time as discussed previously such that H.sub.2S
converts to polysulfides which are nonvolatile but which can be
readily transformed to sulfur by reaction with an oxidizing agent.
The nonaqueous liquid sorbing liquor (or scrubbing solution)
comprises an organic solvent for elemental sulfur, dissolved
elemental sulfur, an organic base which drives the reaction
converting H.sub.2S sorbed by the liquor to a nonvolatile
polysulfide which is soluble in the sorbing liquor, and an organic
solubilizing agent which prevents the formation of polysulfide
oil-which can tend to separate into a separate viscous liquid layer
if allowed to form. The solubilizing agent is typically selected
from the group consisting of aromatic alcohols, ethers and other
polar organic compounds including sulfolane, propylene carbonate,
and tributyl phosphate, and mixtures thereof. The sorbing liquor is
preferably essentially water insoluble as this offers advantages
where water may be condensed in the process. It is also preferable
for water to be essentially insoluble in the solvent. The
nonaqueous solvent is typically selected from the group consisting
of alkyl-substituted naphthalenes, diaryl alkanes including
phenylxylyl ethanes such as phenyl-o-xylylethane, phenyl tolyl
ethanes, phenyl naphthyl ethanes, phenyl aryl alkanes, dibenzyl
ether, diphenyl ether, partially hydrogenated terphenyls, partially
hydrogenated diphenyl ethanes, partially hydrogenated naphthalenes,
and mixtures thereof. In order to obtain a measurable conversion of
sulfur and H.sub.2S to polysulfides, the base added to the solvent
must be sufficiently strong and have sufficient concentration to
drive the reaction of sulfur and H.sub.2S to form polysulfides.
Most tertiary amines are suitable bases for this use. It should be
noted that while the solvent utilized in the process requires the
addition of a base to promote the reaction of sulfur and H.sub.2S
to form polysulfides, the base and the solvent may be the same
compound.
[0064] A H.sub.2S rich solution passes from the absorber passes to
a flash tank 806. After the flash step, the solution flows to a
precipitator 812 where solid elemental sulfur precipitates. An
H.sub.2S lean SANS solution flows from the precipitator 812 back to
the absorber following a heat treatment to raise the solution
temperature back to the circulating temperature and ensures that
all elemental sulfur is dissolved in the solution.
[0065] Because the elemental sulfur stays dissolved in the
solution, there are no solids in the liquid circulated to the
absorber. This feature helps to eliminate the root cause of
foaming, plugging, and other operational problems that have plagued
other processes.
[0066] The precipitator/filter 812 is the only place where sulfur
solids exist within the process, and sulfur solids are removed by a
filter system. The produced sulfur may used in agriculture,
disposed of as non-hazardous waste, or recycled into liquid
SO.sub.2. SO.sub.2 may be added to the solution in one of three
ways: (1) liquid SO.sub.2 may be metered into the system; (2) a
portion of the product sulfur may be burned and the resulting
SO.sub.2 absorbed into the SANS solution in a small separate
contactor; and (3) a portion of the inlet stream can be burned and
the SO.sub.2 absorbed in a separate contactor.
[0067] Monitoring and control system 802 may monitor flow
conditions, chemical compositions, pressure, temperature, feed
stock properties, fluid inlet and outlet properties. This
information may be used to control the pressure, temperature,
volume, flow rates and concentration of reactants in various
reactors and processing modules of the automated H2S removal
systems described above. Additionally the monitoring and control
system may be communicatively coupled to a larger system to monitor
conditions such that onsite measurements by field personnel are
reduced. Also, feedstock delivery can be optimized by monitoring
the feedstock and process conditions from a remote site. This
allows delivery of feedstock's (i.e. scrubbing solutions and
solids) to be optimized for a group of wells.
[0068] The monitoring and control system can take the form of an
entirely hardware embodiment, an entirely software embodiment or an
embodiment containing both hardware and software elements. In a
preferred embodiment, the invention is implemented in software,
which includes but is not limited to firmware, resident software,
microcode, etc. The monitoring and control system may include a
data processing system suitable for storing and/or executing
program code will include at least one processor coupled directly
or indirectly to memory elements through a system bus. The memory
elements can include local memory employed during actual execution
of the program code, bulk storage, and cache memories which provide
temporary storage of at least some program code in order to reduce
the number of times code must be retrieved from bulk storage during
execution.
[0069] Input/output or I/O devices (including but not limited to
keyboards, displays, pointing devices, etc.) can be coupled to the
system either directly or through intervening I/O controllers.
[0070] Network adapters may also be coupled to the system to enable
the data processing system to become coupled to other data
processing systems or remote printers or storage devices through
intervening private or public networks. Modems, cable modem and
Ethernet cards are just a few of the currently available types of
network adapters.
[0071] FIG. 9 provides a logic flow diagram of a method to remove
contaminants from a contaminated fluid stream. Operations 900 begin
in Step 902 when the fluid stream containing contaminants is
received. In Step 904 the chemical composition and concentration of
contaminants within the fluid stream may be determined. Based on
the chemical composition and concentration of contaminants
determined in Step 904, a first base solution may be added to a
first scrubbing stage in Step 906. This first base solution
dispersed within the scrubbing stage removes a portion of the
contaminants from the fluid stream and these contaminants enter a
contaminant solution in Step 908. Water may be removed or
desiccated from the fluid stream with a desiccating module to
provide a clean substantially contaminant free fluid stream in Step
910. The water reacts with the desiccating media to form a
concentrated base solution.
[0072] Embodiments of the present invention may further include
determining the chemical composition and concentration of
contaminants within the fluid stream after removing the first
portion of the contaminants. The concentrated base solution may be
metered to a second scrubbing stage based on the chemical
composition and concentration of the contaminants within the fluid
stream after removing the first portion of the contaminants. This
allows a second or additional scrubbing stage to remove a remaining
portion of the contaminants. All fluids and solutions may have
their chemical composition and constituent concentrations
determined such that they may be metered to the various stages
within the scrubber to optimize or configure the reaction rates to
remove contaminants from the fluid stream. These contaminants may
be sulfur containing compounds such as H.sub.2S and the base or
alkaline solutions may be a potassium hydroxide solution, aqueous
iron solution, non-aqueous solutions, SANS solutions or other
alkaline solutions known to those having skill in the art.
[0073] FIG. 10 provides a process flow diagram of a process
operable to remove contaminants from a contaminated fluid stream,
such as a petroleum stream, in accordance with embodiments of the
present invention. Operations of 1000 begin with Step 1002 when a
fluid feed stream comprising H.sub.2S is provided as an input to
the system. A chemical composition concentration of H.sub.2S within
the fluid feed stream may be determined in Step 1004. The fluid
feed stream may be metered to a multi-stage scrubber in Step 1006.
Additionally in Step 1008 the alkaline solution may be metered to
the multi-stage scrubber. The alkaline solution may be metered
based on the chemical composition and concentration of the alkaline
solution as well as the concentration of H.sub.2S in other
contaminants or constituents of the fluid stream. The fluid feed
stream and the alkaline solution mix within the scrubber to produce
a fluid stream having a reduced H.sub.2S content. An alkaline
solution containing sulfide ions may be removed from the scrubber
and directed to a sulfur recovery process in Step 1012 where a by
product of the sulfur recovery process is a regenerated alkaline
solution. In later stages of a multi-stage scrubber an alkaline
solution containing sulfide ions may be directed upstream to a
previous stage of the multi-stage scrubber to act as an alkaline
solution to remove additional H.sub.2S. In Step 1014 a chemical
composition concentration of H.sub.2S within the fluid stream
having a reduced H.sub.2S content may be determined. The fluid
stream having a reduced H.sub.2S content can then be outputted to a
fluid network such as a natural gas pipeline for further
processing. By determining real time chemical composition and
concentration of H.sub.2S within the substantially H.sub.2S free
fluid stream outputted by the multi-stage scrubber this information
may be supplied in real time to downstream processes when the
downstream processes, i.e., refinery processes may be configured or
optimized based on the real time chemical composition and
concentration of H.sub.2S within the substantially H.sub.2S free
fluid stream. By monitoring the H.sub.2S concentration in real time
over the life of a refinery or transportation network the sulfide
corrosive effects on the transportation network such as sulfide
embitterment of steel may be calculated and proactively tracked
such that components may be replaced prior to failure based on
actual H.sub.2S exposure as opposed to an arbitrary time chosen
based on peak exposures.
[0074] FIG. 11 provides a block diagram of a contaminate control
system in accordance with embodiments of the present invention.
This contaminate control system includes a monitoring and control
system 1102, a fluid source 1104, a real-time or near real-time
analytical equipment 1110, an isolation valve 1106, and downstream
processes and equipment 1108. Fluid source 1104 may be a petroleum
stream of crude oil or natural gas as provided by a well or within
a refinery. Other embodiments may sample a water stream or other
fluid source 1104. This fluid source may be located within a
refinery or chemical processing plant. Monitoring and control
system 1102 is coupled to real-time or near real time analytical
equipment such as an inline spectroscopy tool 1110. This equipment
may be used to provide real-time monitoring of a fluid stream
within fluid source 1104. This monitoring equipment is able to
accurately and in real-time determine the chemical composition and
concentration of contaminants within the fluid source, as well as
the chemical composition of constituent components. Additionally
the monitoring control system may monitor the flow rate, pressure,
temperature and other parameters associated with the fluid source.
The monitoring and control system may compare contaminate levels to
predetermined threshold levels. When the predetermined or threshold
levels compare unfavorably, monitoring and control system 1102 may
throttle or secure flow by adjusting or closing valve 1106. This
allows downstream process and equipment 1108 to be protected from
contaminate levels within fluid source 1104. This provides a
significant advantage over existing systems. Real-time chemical
composition and analysis such as that provided by an inline
spectroscopy monitoring tool may be used to isolate downstream and
processes and equipment from potentially harmful contaminates.
Additionally, this may allow the downstream processes and equipment
to be reconfigured, manually or automatically, in order to handle a
process contaminant. The monitoring and control system 1102 may
couple to downstream processes and equipment and insure that they
are properly configured to handle contaminates and the chemical
composition of the fluid stream prior to opening or returning the
fluid source of 1104 to service. This may prevent the unnecessary
application of downstream processes where not needed.
[0075] FIG. 12 provides a logic flow diagram illustrating a process
of securing or adjusting fluid flow based on real-time measured
contaminate levels in accordance with embodiments of the present
invention. Operations 1200 begin in step 1202 when a fluid stream
having potential contaminates is received. In step 1204, chemical
concentration of contaminants and constituent components within the
fluid stream are determined in real-time or new real-time using
equipment such as in-line spectroscopy monitoring tools. These
determined contaminate levels may be compared to predetermined
thresholds in Step 1206. When the comparison is favorable at
decision point 1208, the fluid may be provided to downstream
equipment and processes in step 1212. However, when the comparison
is unfavorable, flow may be secured and reconfigured in step 1210.
Additionally, downstream processes and equipment may be
reconfigured in order to handle the contaminates or lack thereof in
the most economical manner possible.
[0076] In summary, a method operable to remove contaminants from a
contaminated gas stream is provided. The process includes receiving
the gas stream containing contaminants. A first portion of the
contaminants are removed from the gas stream with a first scrubbing
vessel. A first base solution reacts with the contaminants such
that the contaminants enter a contaminant solution. A remaining
portion of the contaminants from the gas stream is then removed
with a at least one additional scrubbing vessel, wherein a second
base solution reacts with the contaminants such that part of the
remaining portion of the contaminants enter a second solution.
Water content is then removed from the gas stream with a
desiccating module, wherein the desiccating module outputs a clean
gas stream.
[0077] The processes described above in addition to being
applicable to H.sub.2S scrubbing of petroleum fluid streams may
also provide a H.sub.2S scrubber that may be used on synthetic gas
streams, power plant effluent or coal effluent streams, geo thermal
water streams wherein water is heavily contaminated with H.sub.2S,
mining operations where H.sub.2S is produced while extracting
metals from various ores.
[0078] The corresponding structures, materials, acts, and
equivalents of all means or step plus function elements in the
claims below are intended to include any structure, material, or
act for performing the function in combination with other claimed
elements as specifically claimed. The description of the present
invention has been presented for purposes of illustration and
description, but is not intended to be exhaustive or limited to the
invention in the form disclosed. Many modifications and variations
will be apparent to those of ordinary skill in the art without
departing from the scope and spirit of the invention. The
embodiment was chosen and described in order to best explain the
principles of the invention and the practical application, and to
enable others of ordinary skill in the art to understand the
invention for various embodiments with various modifications as are
suited to the particular use contemplated.
[0079] As one of average skill in the art will appreciate, the term
"substantially" or "approximately", as may be used herein, provides
an industry-accepted tolerance to its corresponding term. Such an
industry-accepted tolerance ranges from less than one percent to
twenty percent and corresponds to, but is not limited to, component
values, integrated circuit process variations, temperature
variations, rise and fall times, and/or thermal noise. As one of
average skill in the art will further appreciate, the term
"operably coupled", as may be used herein, includes direct coupling
and indirect coupling via another component, element, circuit, or
module where, for indirect coupling, the intervening component,
element, circuit, or module does not modify the information of a
signal but may adjust its current level, voltage level, and/or
power level. As one of average skill in the art will also
appreciate, inferred coupling (i.e., where one element is coupled
to another element by inference) includes direct and indirect
coupling between two elements in the same manner as "operably
coupled". As one of average skill in the art will further
appreciate, the term "compares favorably", as may be used herein,
indicates that a comparison between two or more elements, items,
signals, etc., provides a desired relationship. For example, when
the desired relationship is that signal 1 has a greater magnitude
than signal 2, a favorable comparison may be achieved when the
magnitude of signal 1 is greater than that of signal 2 or when the
magnitude of signal 2 is less than that of signal 1.
[0080] The terminology used herein is for the purpose of describing
particular embodiments only and is not intended to be limiting of
the invention. As used herein, the singular forms "a", "an" and
"the" are intended to include the plural forms as well, unless the
context clearly indicates otherwise. It will be further understood
that the terms "comprises" and/or "comprising," when used in this
specification, specify the presence of stated features, integers,
steps, operations, elements, and/or components, but do not preclude
the presence or addition of one or more other features, integers,
steps, operations, elements, components, and/or groups thereof.
[0081] The corresponding structures, materials, acts, and
equivalents of all means or step plus function elements in the
claims below are intended to include any structure, material, or
act for performing the function in combination with other claimed
elements as specifically claimed. The description of the present
invention has been presented for purposes of illustration and
description, but is not intended to be exhaustive or limited to the
invention in the form disclosed. Many modifications and variations
will be apparent to those of ordinary skill in the art without
departing from the scope and spirit of the invention. The
embodiment was chosen and described in order to best explain the
principles of the invention and the practical application, and to
enable others of ordinary skill in the art to understand the
invention for various embodiments with various modifications as are
suited to the particular use contemplated.
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