U.S. patent application number 13/921411 was filed with the patent office on 2013-12-26 for process for enhanced oil recovery using capture of carbon dioxide.
The applicant listed for this patent is Michael J. Lewis. Invention is credited to Michael J. LEWIS.
Application Number | 20130341924 13/921411 |
Document ID | / |
Family ID | 49773785 |
Filed Date | 2013-12-26 |
United States Patent
Application |
20130341924 |
Kind Code |
A1 |
LEWIS; Michael J. |
December 26, 2013 |
PROCESS FOR ENHANCED OIL RECOVERY USING CAPTURE OF CARBON
DIOXIDE
Abstract
A process for enhanced oil recovery includes the steps of
producing steam in at least a first pressure range and a second
pressure range, passing the steam of the first pressure range to a
steam turbine so as to produce power therefrom, passing the steam
of the second pressure range to an amine capture system such that
carbon dioxide is delivered therefrom, and injecting the carbon
dioxide from the amine capture system into a well for enhanced oil
recovery. Steam of a third pressure range can be passed to an
absorption chiller so as to cool a liquid therein. The first
pressure range is greater than the second pressure range.
Inventors: |
LEWIS; Michael J.; (Houston,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Lewis; Michael J. |
Houston |
TX |
US |
|
|
Family ID: |
49773785 |
Appl. No.: |
13/921411 |
Filed: |
June 19, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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13204952 |
Aug 8, 2011 |
|
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13921411 |
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Current U.S.
Class: |
290/52 ; 166/267;
166/305.1 |
Current CPC
Class: |
F01D 15/10 20130101;
C09K 8/594 20130101; F05D 2260/61 20130101; B01D 53/62 20130101;
Y02C 20/40 20200801; F02C 1/002 20130101; F05D 2220/32 20130101;
Y02C 10/04 20130101; B01D 2252/204 20130101; Y02P 20/13 20151101;
B01D 53/78 20130101; E21B 43/34 20130101; Y02P 20/129 20151101;
F05D 2210/12 20130101; Y02P 90/70 20151101; E21B 43/164
20130101 |
Class at
Publication: |
290/52 ;
166/305.1; 166/267 |
International
Class: |
E21B 43/16 20060101
E21B043/16; F01D 15/10 20060101 F01D015/10; E21B 43/34 20060101
E21B043/34 |
Claims
1. A process for enhanced oil recovery from a well, the process
comprising: producing steam in at least a first pressure range and
a second pressure range; passing the steam of the first pressure
range to a steam turbine so as to produce power therefrom; passing
the steam of the second pressure range to an amine capture system
such that carbon dioxide is delivered therefrom; and injecting the
carbon dioxide from said amine capture system into a well for
enhanced oil recovery.
2. The process of claim 1, the step of producing steam further
comprising: producing steam in a third pressure range; and passing
the steam of the third pressure range to an absorption chiller so
as to cool a liquid therein.
3. The process of claim 2, said first pressure range having a
pressure greater than a pressure of said second pressure range,
said second pressure range having a pressure greater than a
pressure of said third pressure range.
4. The process of claim 1, passing the steam of the second pressure
range to a dehydration unit so as to dry the natural gas passing
therethrough.
5. The process of claim 1, further comprising: passing the steam of
the second pressure range to a heater treater; pumping oil and
water from the well into said heater treater; heating the pumped
oil and water in the heater treater with passed steam of the second
pressure range; and separating water from the heated pumped oil and
water in the heater treater.
6. The process of claim 1, the step of producing steam comprising:
operating a heat recovery steam generator so as to produce the
steam and to produce an exhaust; delivering the exhaust to the
amine capture system; and separating carbon dioxide from the
exhaust by said amine capture system.
7. The process of claim 6, further comprising: producing energy
from a combustion turbine; and operating said combustion turbine so
as to provide power to said heat recovery steam generator.
8. The process of claim 1, the step of injecting comprising:
compressing the carbon dioxide to a pressure of up to 2000
p.s.i.g.; and injecting the compressed carbon dioxide into the
well.
9. A process for enhanced oil recovery from a well, the process
comprising: producing steam in at least two pressure ranges;
passing the steam of one pressure range to an amine capture system
such that carbon dioxide is delivered therefrom: passing steam of
the other pressure range to an absorption chiller so as to cool a
liquid therein: passing the cooled liquid to said amine capture
system; and injecting the carbon dioxide from the amine capture
system into a well for enhanced oil recovery.
10. The process of claim 9, further comprising: producing steam of
another pressure range; and passing the steam of said another
pressure range to a steam turbine so as to produce power
therefrom.
11. The process of claim 9, further comprising: operating a heat
recovery steam generator so as to produce the steam of the at least
two pressure range.
12. The process of claim 9, the steps of passing the steam
comprising: selectively moving steam of said one pressure range to
said amine capture system and steam of the other pressure range to
said absorption chiller.
13. The process of claim 9, further comprising: passing the steam
of the one pressure range to a dehydration unit so as to dry
natural gas passing therethrough.
14. The process of claim 9, further comprising: passing the steam
of the one pressure range to a heater treater; pumping oil and
water from the well into said heater treater; heating the pumped
oil and water in the heater treater with passed steam of said one
pressure range; and separating the oil from the heated pumped oil
and water in the heater treater.
15. The process of claim 9, the step of producing steam comprising:
operating a heat recovery steam generator so as to produce the
steam and to produce an exhaust; delivering the exhaust to the
amine capture system; and separating carbon dioxide from the
exhaust by said amine capture system.
16. The process of claim 15, further comprising: producing energy
from a combustion turbine; and operating said combustion turbine so
as to provide power to said heat recovery steam generator.
17. A process for enhanced oil recovery from a well, the process
comprising: producing steam from a heat recovery steam generator,
passing the steam from the heat recovery steam generator to an
amine capture system; delivering a mixture of carbon dioxide and
natural gas to said amine capture system; operating said amine
capture system such that carbon dioxide and natural gas are passed
separately therefrom; and injecting the carbon dioxide from said
amine capture system into the well for enhanced oil recovery.
18. The process of claim 17, further comprising: producing steam of
another pressure from said heat recovery steam generator; passing
said steam of another pressure to an absorption chiller so as to
cool a liquid therein; and introducing the cooled liquid to said
amine capture system so as to cool the amine therein.
19. The process of claim 17, further comprising: producing steam of
a further pressure from said heat recovery steam generator; passing
the steam of the further pressure to a steam turbine so as to drive
said steam turbine; and producing power from said steam
turbine.
20. The process of claim 17, further comprising: operating said
heat recovery steam generator so as to produce the steam and an
exhaust; delivering the exhaust to said amine capture system; and
separating carbon dioxide from the exhaust by said amine capture
system. injecting the carbon dioxide from said amine capture system
into a well for enhanced oil recovery.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present application is a continuation-in-part of U.S.
patent application Ser. No. 13/204,952, filed on Aug. 8, 2011, and
entitled "System and Method for Producing Carbon Dioxide for Use in
Hydrocarbon Recovery", presently pending.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
NAMES OF THE PARTIES TO A JOINT RESEARCH AGREEMENT
[0003] Not applicable.
INCORPORATION-BY-REFERENCE OF MATERIALS SUBMITTED ON A COMPACT
DISC
[0004] Not applicable.
BACKGROUND OF THE INVENTION
[0005] 1. Field of the Invention
[0006] The present invention relates to carbon dioxide injection
for tertiary hydrocarbon recovery. More particularly, the present
invention the relates to portable carbon dioxide generators that
can be used for producing the carbon dioxide gas for injection into
a hydrocarbon-bearing formation. The present invention also relates
to systems and methods whereby steam of different pressures can be
utilized to enhance the efficiency of the enhanced recovery
process.
[0007] 2. Description of Related Art Including Information
Disclosed Under 37 CFR 1.97 and 37 CFR 1.98.
[0008] The world's power demands are expected to rise 50% by 2030.
With worldwide total of active coal plants over 50,000 and rising,
the International Energy Agency estimates that fossil fuels will
account for 85% of the energy market by 2030. Meanwhile, trillions
of dollars worth of oil remain underground in apparently depleted
wells.
[0009] The U.S. currently produces approximately 5.1 million
barrels of oil per day. Most of the oil fields in the United States
are declining in oil recovery productivity. It has been proven that
carbon dioxide can be used for enhanced oil recovery so as to
increase oil recovery productivity in the declining fields. The
Department of Energy estimates that 89 billion barrels of
"stranded" oil can be recovered using carbon dioxide for enhanced
oil recovery.
[0010] There are tens of thousands of depleted oil and natural gas
wells around the world, which collectively possess significant
amounts ofpetroleum resources that cannot currently be extracted
using conventional extraction techniques. For example, in a typical
oil well, only about 30% of the underground oil is recovered during
initial drilling. An additional approximately 20% may be accessed
by "secondary recovery" techniques such as water flooding. In
recent years, "tertiary recovery" techniques have been developed to
recover additional oil from depleted wells. Such tertiary recovery
techniques include thermal recovery, chemical injection, and gas
injection. Using current methods, these tertiary techniques allow
for an additional 20% or more of the original oil-in-place (OOIP)
to be recovered.
[0011] Gas injection is one of the most common tertiary techniques.
In particular, carbon dioxide injection into depleted oil wells has
received considerable attention owing to its ability to mix with
crude oil. Since the crude oil is miscible with carbon dioxide, the
injection of carbon dioxide renders the oil substantially less
viscous and more readily extractable.
[0012] Carbon dioxide in quantities sufficiently large enough for
commercial exploitation generally has come from three sources. One
such source is the naturally occurring underground supply of carbon
dioxide in areas such as Colorado, Wyoming, Mississippi, and other
areas. A second source is that resulting from by-products of the
operation of a primary process, such as the manufacture of ammonia
or a hydrogen reformer. A third source is found in the exhaust
gases from burning of various hydrocarbon fuels. One of the largest
problems that is faced by carbon dioxide users is the problem of
transportation from the place of production to the point of
use.
[0013] Problems exist within the current carbon dioxide pipeline
infrastructure in that extensions into potentially productive areas
are costly and somewhat limited due to the availability of high
purity carbon dioxide. Even in areas that have relatively close
proximity to an existing carbon dioxide pipeline, extensions to
potential producing areas are costly and time-consuming. The single
greatest problem is the lack of commercial quantities of carbon
dioxide in close proximity to the oil fields that are in need of
this resource to produce the remaining the reserves that are
recoverable by using the tertiary recovery methods. This problem is
exacerbated when the field is remote to an existing carbon dioxide
pipeline and/or is not of sufficient size to justify the costly
extension of the pipeline infrastructure. Because an oilfield
undergoing tertiary recovery will begin to recycle quantities of
carbon dioxide that is recovered along with the tertiary oil, the
need for carbon dioxide will diminish significantly over time. This
necessitates the recovery of pipeline infrastructure capital costs
quickly.
[0014] Currently, carbon dioxide is present in low concentrations,
such as within the flue gas from power generation facilities. These
plants are found all over the United States and can be fired from a
variety of hydrocarbon sources, including coal, fuel oil, biomass,
and natural gas. Unfortunately, these facilities are most often
located near large water sources due to their need to use this
water for cooling during the power production process. In addition,
generally, these are very large facilities with a long economic
life. There are many oil fields that are not located within
sufficiently close proximity to attempt to economically utilize a
carbon capture technology and pipeline delivery method to provide
the carbon dioxide to the oilfields that have this need.
[0015] In the past, various patents have issued relating to the
production of carbon dioxide for tertiary hydrocarbon recovery. For
example, U.S. Pat. No. 4,499,946, issued on Feb. 19, 1985 to Martin
et al., provides a portable, above-ground system and process for
generating combustion gases and for injecting the purified nitrogen
and carbon dioxide at controlled temperatures into a subterranean
formation so as to enhance the recovery thereof. The system
includes a high-pressure combustion reactor for sufficient
generation of combustion gases at the required rates and at
pressures up to about 8000 p.s.i. and temperatures up to about
4500.degree. F. The reactor is water-jacketed but lined with
refractory material to minimize soot formation.
[0016] U.S. Pat. No. 4,741,398, issued on May 3, 1988 to F. L.
Goldsberry, shows a hydraulic accumulator-compressor vessel using
geothermal brine under pressure as a piston to compress carbon
dioxide-rich gas. This is used in a system having a plurality of
gas separators in tandem to recover pipeline quality gas from
geothermal brine. A first high pressure separator feeds gas to a
membrane separator which separates low pressure waste gas from high
pressure quality gas. A second separator produces low pressure
waste gas. Waste gas from both separators is combined and fed into
the vessel through a port at the top as the vessel is drained for
another compression cycle.
[0017] U.S. Pat. No. 4,824,447, issued on Apr. 25, 1989 to F. L.
Goldsbeny, describes an enhanced oil recovery system which produces
pipeline quality gas by using a high pressure separator/heat
exchanger and a membrane separator. Waste gas is recovered from
both the membrane separator and a low pressure separator in tandem
with the high pressure separator. Liquid hydrocarbons are skimmed
off the top of geothermal brine in the low pressure separator. High
pressure brine from the geothermal well is used to drive a
turbine/generator set before recovering waste gas in the first
separator. Another turbine/generator set is provided in a
supercritical binary power plant that uses propane as a working
fluid in a closed cycle and uses exhaust heat from the combustion
engine and geothermal energy of the brine in the separator/heat
exchanger to heat the propane.
[0018] U.S. Pat. No. 4,899,544, issued on Feb. 13, 1990 to R. T.
Boyd, discloses a cogeneration/carbon dioxide production process
and plant. This system includes an internal combustion engine that
drives an electrical generator. A waste heat recovery unit is
provided through which hot exhaust gases from the engine are passed
to recover thermal energy in a usable form. A means is provided for
conveying exhaust gases coming out of the waste heat recovery unit
to a recovery unit where the carbon dioxide is extracted and made
available as a saleable byproduct.
[0019] U.S. Pat. No. 7,753,972, issued on Jul. 13, 2010 to Zubrin
et al., discloses a portable renewable energy system for enhanced
oil recovery. This is a truck mobile system that reforms biomass
into carbon dioxide and hydrogen. The gases are separated. The
carbon dioxide is sequestered underground for enhanced oil recovery
and the hydrogen used to generate several megawatts of carbon-free
electricity.
[0020] U.S. Patent Publication No. 2008/0283247, published on Nov.
20, 2008 to Zubrin et al., shows a portable, modular apparatus for
recovering oil from an oil well and generating electric power. This
system includes a chassis to support a fuel reformer, a gas
separator, a power generator, and/or a compressor. The fuel
reformer module is adapted to react a fuel source with water to
generate a driver gas including a mixture of carbon dioxide gas and
hydrogen gas. The gas separator module is operatively coupled to
the reformer module and is adapted to separate at least a portion
of the hydrogen gas from the rest of the driver gas. The power
generator module is operatively coupled to the gas separator module
and is adapted to generate electric power using a portion of the
separated hydrogen gas. The compressor module is operatively
connected to the reformer module and is adapted to compress a
portion of the driver gas and to eject the driver gas at high
pressure into the oil well for enhanced oil recovery.
[0021] U.S. Patent Publication No. 2009/0236093, published on Sep.
24, 2009 to Zubrin et al., shows a method for extracting petroleum
by using reformed gases. This method includes reforming a fuel
source by reaction with water to generate driver gas and injecting
the driver gas into the oil well. The reforming operation includes
causing the combustion of a combustible material with ambient
oxygen for the release of energy. A reforming reaction fuel and
water is heated with the energy released from this heating process.
This is at a temperature above that required for the reforming
reaction in which the fuel and water sources are reformed into
driver gas.
[0022] U.S. Patent Publication No. 2010/0314136, published on Dec.
16, 2010 to Zubrin et al., discloses an in-situ apparatus for
generating carbon dioxide gas at an oil site for use in enhanced
oil recovery. The apparatus includes a steam generator adapted to
boil and superheat water to generate a source of superheated steam,
as well as a source of essentially pure oxygen. The apparatus also
includes a steam reformer adapted to react a carbonaceous material
with the superheated steam and the pure oxygen, in an absence of
air, to generate a driver gas made up of primarily carbon dioxide
gas and hydrogen. A separator is adapted to separate at least a
portion of the carbon dioxide gas from the rest of the driver gas
to generate a carbon dioxide-rich driver gas and a hydrogen-rich
fuel gas. A compressor is used for compressing the carbon
dioxide-rich driver gas for use in enhanced oil recovery.
[0023] U.S. Patent Publication No. 2011/0067410, published on Mar.
24, 2011 to Zubrin et al., teaches a reformation power plant that
generates clean electricity from carbonaceous material and high
pressure carbon dioxide. The reformation power plant utilizes a
reformation process that reforms carbonaceous fuel with
super-heated steam into a high-pressure gaseous mixture that is
rich in carbon dioxide and hydrogen. This high-pressure gas
exchanges excess heat with the incoming steam from a boiler and
continues onward to a condenser. Once cooled, the high-pressure gas
goes through a methanol separator, after which the carbon
dioxide-rich gas is sequestered underground or is re-used. The
remaining hydrogen-rich gas is combusted through a gas turbine. The
gas turbine provides power to a generator and also regenerative
heat for the boiler. The generator converts mechanical energy into
electricity, which is transferred to the electric grid.
[0024] It is an object of the present invention to provide a system
for use in hydrocarbon recovery that places a high purity carbon
dioxide source close to the hydrocarbon-bearing formation.
[0025] It is another object of the present invention to provide a
system for producing carbon dioxide and hydrocarbon recovery which
is portable.
[0026] It is still another object of the present invention to
provide a system for producing carbon dioxide for use in
hydrocarbon recovery that can be permitted as a minor emission
source.
[0027] It is still a further object of the present invention to
provide a system for producing carbon dioxide for use in
hydrocarbon recovery which can be delivered in short order to a
desired location.
[0028] It is a further object of the present invention to provide a
system for producing carbon dioxide for use in hydrocarbon recovery
which allows power to be sold into the power grid.
[0029] It is still another object of the present invention to
provide a system for producing carbon dioxide for use in
hydrocarbon recovery that is environmentally beneficial.
[0030] It is still a further object of the present invention to
provide a system for producing carbon dioxide for use in
hydrocarbon recovery which minimizes site work and field
construction costs and equipment.
[0031] It is still a further object of the present invention to
provide a system that will minimize water requirements for the
enhanced hydrocarbon recovery.
[0032] These and other objects and advantages of the present
invention will become apparent from a reading of the attached
specification and appended claims.
BRIEF SUMMARY OF THE INVENTION
[0033] The present invention is a process for enhanced oil recovery
from a well in which the process includes the steps of: (1)
producing steam in at least a first pressure range and a second
pressure range; (2) passing the steam of the first pressure range
to a steam turbine so as to produce power therefrom; (3) passing
the steam of the second pressure range to an amine capture system
such that carbon dioxide is delivered therefrom; and (4) injecting
the carbon dioxide from the amine capture system into a well for
enhanced oil recovery.
[0034] In the present invention, the step of producing steam
further includes producing steam in a third pressure range. The
third pressure range is passed to an absorption chiller so as to
cool a liquid therein. The steam of the first pressure range has a
pressure range greater than the pressure of the steam of the second
pressure range. The pressure of the steam is of the second pressure
range is greater than the pressure of the steam in the third
pressure range. The first pressure range will have a pressure
greater than 500 p.s.i.g. The steam of the second pressure range
will have a pressure of between 150 and 200 p.s.i.g. The steam of
the third pressure range will be less than 25 p.s.i.g.
[0035] The steam of the second pressure range can be used of
variety of purposes. In particular, the steam of the second
pressure range can be passed to a dehydration unit so as to dry the
natural gas passing therethrough. Additionally, the steam of the
second pressure range can be passed to a heater treater. Initially,
oil and water are pumped from the well into the heater treater. The
pumped oil and water are heated in the heater treater with the
passed steam of the second pressure range. Water is separated from
the pumped oil and water in the heater treater.
[0036] In the present invention, the step of producing steam
includes the steps of operating a heat recovery steam generator so
as to produce the steam and to produce an exhaust. The exhaust is
delivered the exhaust to the amine capture system. The carbon
dioxide is separated from the exhaust by the amine capture system.
The energy is initially produced by a combustion turbine. The
combustion turbine is operated so as to provide power to the heat
recovery steam generator.
[0037] In the present invention, the step of injecting the carbon
dioxide includes the steps of compressing the carbon dioxide to a
pressure of up to 2000 p.s.i.g. The compressed carbon dioxide is
injected into the well.
[0038] The use of the combustion turbine in conjunction with the
heat recovery steam generator provides power for sale and use in
the project and steam for additional power. The heat recovery steam
generator allows for the generation of steam at various steam
pressures. Within the present invention, it is contemplated that
the heat recovery steam generator will generate steam in at least
two, and most likely, three different pressure ranges. By a using a
heat recovery steam generator with multiple steam pressures, the
exhaust temperature (containing the carbon dioxide to be captured)
can be greatly lowered. This, in turn, increases the retention of
the enhanced amine solution.
[0039] The high pressure steam (in excess of 500 p.s.i.g.) will be
utilized to generate additional power through the use of a
condensing steam turbine. The turbine condenses the steam that is
produced and is used to generate additional power. The steam is
converted back to water for reintroduction to the heat recovery
steam generator. This serves to generate additional power without
the necessity of the large volumes of water required in many
installations, or the capital costs and electrical requirements of
the air cooling.
[0040] The medium pressure steam (approximately 150-200 p.s.i.g.)
will be utilized to provide the heat of the regeneration of the
enhanced amine in the carbon dioxide capture system as well as for
the regeneration of glycol in the gas dehydration system. The
medium pressure steam can also be used for the regeneration of the
standard amine in the facility that is used to separate recycle gas
coming from the oil field into its natural gas and carbon dioxide
components.
[0041] The low pressure steam (up to approximately 25 p.s.i.g.)
will be used to provide the heat required for the absorption
chillers that are used to cool turbine inlet air and to cool the
regenerated enhanced amine and normal amine before injection into
the respective contactor vessels. A portion of this steam, or
possibly even hot water being returned from the absorption
chillers, will be utilized to heat the inlet oil and water in the
heater-treater on the inlet side of the central oil field
production facilities. If optimization would indicate that a
portion of the steam can provide all or a portion of the
refrigeration for the natural gas processing, then the steam can be
utilized as part of the natural gas liquids separation
facility.
[0042] The enhanced oil recovery projects are long term
developments. Typically, they would require carbon dioxide for many
years. The production outcomes are predictable. An oil field
central processing facility has to be in service for the same
period of time and would require two externally provided inputs,
heat and power. Given the reservoir and oil characteristics, a
reservoir simulation model can be created and the outputs of that
model can be utilized to design the central facility equipment.
Through the use of the heat from the combustion turbine, the
overall efficiency of the process is greatly improved.
[0043] A standard oil field central processing facility will have a
gas flame-driven heat source for the amine plant, the
heater-treater and the gas dehydrator. Each of these pieces of
equipment has its own safety and emissions issues. The integrated
design of the present invention allows a single source of heat and
emissions to be the combustion turbine. In this facility, the
insulated steam and return lines will travel to and from each
individual piece of equipment taking heat and returning water to
the process with minimal losses.
[0044] There has been and will continue to be a push to increase
the energy efficiency of processes wherever they are located.
Unfortunately, one of the areas that has historically been one of
the most wasteful users of energy has been the energy industry
itself. The present invention generates heat, savings for the
oil-gas-water separation and the heater-treater, gas-water
separation in the dehydrator, natural gas-carbon dioxide separation
in the amine and enhanced amine processes, and savings for the
absorption chilling refrigeration process. Studies have indicated
that this integrated process generates an approximately 16%
reduction in the use of external energy in the central processing
and also a similar reduction in emissions. This 16% energy savings
does not take into consideration the heat that is required to
regenerate the enhanced amine that captures the carbon dioxide in
the first place. If the energy required for this process was
provided, separate and apart from the heat recovery steam
generator, it would require an increase of approximately 42% in the
external fuel, and subsequent emissions requirements. The
integrated process of the present invention provides an effective
method of generating carbon dioxide for enhanced oil recovery
directly at an oil field location while, at the same time,
providing all the necessary heat and power required to run all of
the associated oil field processes in the most efficient manner
possible.
[0045] This foregoing Section is intended to describe, in
generality, the preferred embodiment of the present invention. It
is understood that modifications to the process of the present
invention can be made within the scope of the present invention. As
such, this Section should not to be construed, in any way, as
limiting of the broad scope of the present invention. The present
invention should only be limited by the following claims and their
legal equivalents.
BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS
[0046] FIG. 1 is a block diagram showing the process of the
enhanced oil recovery of the present invention.
DETAILED DESCRIPTION OF THE INVENTION
[0047] Referring to FIG. 1, there is shown the process 10 for
enhanced oil recovery. The process 10 of the present invention
includes a combustion turbine 12, a heat recovery steam generator
14, amine capture systems 16 and 18, and a compressor 20.
[0048] The combustion turbine 12 is a natural gas-powered
combustion turbine which utilizes natural gas as the fuel source.
The combustion turbine 12 includes a generator suitable for
generating electrical energy. The combustion turbine 12 is
connected by line 22 to the electrical grid or to suitable
batteries. As such, the electrical energy produced by the
combustion turbine 12 can be connected to the electrical grid so
that electrical energy from the combustion turbine 12 can be sold
to the utilities. The combustion turbine 12 is connected to a
natural gas pipeline 24 and/or to the natural gas line 26 which
emanates from the process 10. Inlet air to the combustion turbine
12 is provided along inlet air line 28. The inlet air passing
through line 28 is delivered to an inlet air chiller 30. The inlet
air chiller cools the inlet to a cooler temperature so that the
output of the combustion turbine 12 remains more constant. For
example, in hot weather, the combustion turbine 12 will operate
less efficiently. The inlet air chiller 30 will serve to cool the
inlet air to approximately 60.degree. F. prior to passing to the
combustion turbine 12. The inlet air 30 will sit above the turbine.
As such, water will fall out from the inlet air chiller 30. This
chilled water can then be provided to the thermal storage 32 or for
other make-up water needs.
[0049] The exhaust from the combustion turbine 12 is delivered to
the heat recovery steam generator 14. The heat recovery steam
generator 14 causes the hot exhaust 34 from the combustion turbine
12 to pass therethrough such that the heat recovery steam generator
14 will extract residual heat from the hot exhaust 34 and produce
steam for the process of the present invention. The heat recovery
steam generator 14 will also lower the exhaust temperature before
the exhaust gases pass into the amine capture systems 16 and/or 18.
Importantly, the heat recovery steam generator 14 will produce a
great deal of steam. In particular, the heat recovery steam
generator 14 will produce steam of a first pressure range, a second
pressure range, and a third pressure range. Line 36 shows the steam
output from the heat recovery steam generator 14. It can be seen
that the steam of the first pressure range 38 will pass to a
condensing steam turbine 40. The first pressure range of the steam
passing from line 36 into line 38 will be greater than 500 p.s.i.g.
As such, the steam will have sufficient power so as to properly
operate the condensing steam turbine.
[0050] The steam turbine 40 is a device that extracts thermal
energy from pressurized steam and uses it to carry out mechanical
work on a rotating output shaft. Since the steam turbine 40
utilizes rotary motion, it is particularly suited to be used to
drive an electrical generator. The steam turbine is in the form of
a heat engine that derives most of its improvement in thermodynamic
efficiency through the use of multiple stages in the expansion of
the steam. Ultimately, the electrical power for the process 10 of
the present invention can be provided as an output 42 of the
condensing steam turbine. The steam 38 of the first pressure range
is returned back to the heat recovery steam generator 14 along line
44 as water.
[0051] The heat recovery steam generator 14 also passes the steam
along line 36 so as to produce steam of a second pressure so as to
be delivered along line 46. The steam of the second pressure, as
passed along line 46, will be in the range of between 150 p.s.i.g.
and 200 p.s.i.g. Suitable valving systems, known in the art, can
serve to properly deliver the desired pressure of steam along the
respective lines. The steam of the second pressure range can be
utilized for a variety of purposes. The steam passing along line 46
can then pass to line for delivery to the amine capture system 16.
In particular, the amine capture system 16 is a Fluor Econamine FG
Unit.
[0052] The Fluor Econamine FG Unit which forms the amine capture
system 16 is an amine-based technology for a large-scale,
post-combustion carbon dioxide capture. The Econamine FG Plus
technology is one of the first and one of the most widely applied
commercial solutions that has been proven in operating environments
to remove carbon dioxide from high oxygen content flue gases. The
amine capture system 16 utilizes a solvent formulation that is
specially designed to recover carbon dioxide from low-pressure,
oxygen-containing streams, such as boilers and reformer stack gas
and gas-turbine flue-gas streams. The carbon dioxide recovered by
the amine capture system 16 can be tailored to meet the end user's
specifications. In particular, the amine capture system 16 utilizes
a particular type of amine that captures carbon dioxide without
degrading in the presence or oxygen.
[0053] The steam passing along 18 is used to provide heat. In this
amine capture system, the amine will enter the contactor tower and
trickle downward while the exhaust gases flow upwardly. As such,
the amine will contact the exhaust gases and retain the carbon
dioxide. The amine and carbon dioxide is then delivered to a boiler
(heated by the steam 48) such that the carbon dioxide will boil out
of the amine then be delivered outwardly along line 50 in the
system 10. Exhaust gases pass from the amine capture system 16
along line 52.
[0054] The exhaust from the heat recovery steam generator 14 is
passed along line 54 to a blower 56. The blower 56 is in the nature
of a fan. As such, the exhaust 56 can provide further heat for the
amine capture system 16. The exhaust, as passed by the blower 56,
will contain additional carbon dioxide that can be removed through
the use of the amine capture system 16. The higher velocity exhaust
gas from line 58 is delivered by blower 56 along line 58 as an
input into the amine capture system 16.
[0055] The steam of the second pressure can further be delivered
along lines 60 and 62 to the amine capture system 18. The amine
capture system 18 is a membrane separator or a standard amine
contactor. The membrane separator or standard amine contactor as
used as part of the amine capture system 18 serves to remove the
carbon dioxide from the natural gas and carbon dioxide mixture as
passes as an input along 64 to the amine capture system 18. The
carbon dioxide output is passed along line 66 to the compressor 20.
The amine capture system 18 serves to receive the solution
containing carbon dioxide. The steam from the heat recovery steam
generator 14 is delivered along lines 60 and 62 as heat to the
amine capture system 18. As such, this heat is used so as to strip
the carbon dioxide from the solution. As a result, the low pressure
carbon dioxide will pass outwardly of the amine capture system 18
along line 66 to the carbon dioxide compressor 20. The carbon
dioxide that passes along line 66 is a low-pressure, high-purity
carbon dioxide.
[0056] The amine capture system 18 utilizes the steam of the second
pressure range, as passed along line 48, directly to the amine
capture system 18. Additionally, the amine capture system 18 can
also utilize steam that is produced from the amine capture system
16. As such, the steam that is part of the output of the amine
capture system 16 can be further utilized within the system 10 of
the present invention.
[0057] The steam of the second pressure can also be used to
facilitate the drying of the natural gas and carbon dioxide that
has been produced from the well. In particular, steam of the second
pressure range passes along line 68 into the dehydration unit 70.
The dehydration unit 70 utilizes triethylene glycol to remove water
from the mixture of carbon dioxide and natural gas that passes as
an input along line 72 to the dehydration unit 70. The dehydration
unit 70 takes the water out of the carbon dioxide and natural gas
mixture. As such, only a dry gas mixture of the natural gas and
carbon dioxide will pass along line 64 as an input to the amine
capture system 18.
[0058] The steam of the second pressure can further pass along line
74 as a steam input to the heater treater 76. The heater treater 76
is a vessel that is commonly used in the oil field. In particular,
the heater treater 76 receives an oil and water mixture from line
78 from a bulk separator 80. Additionally, the heater treater 76
can further receive oil and water along line 82 from the test
separator 84. As a result, the heater treater 76 will contain a
mixture of oil and water therein. In normal application, water will
settle within the heater treater while oil will flow toward the
top. By the application of the steam of the second pressure range
from the heat recovery steam generator 14, the temperature of the
oil and water mixture within the heater treater 76 is elevated. As
such, this will enhance the separation process. Ultimately, water
will pass outwardly of the heater treater 76 along line 86 for
disposal. The natural gas and carbon dioxide will flow outwardly of
the heater treater 76 along line 88 to a compressor 90. The crude
oil that is separated from the water in heater treater 76 is passed
along line 92 to crude storage vessel 94. Ultimately, the crude oil
that is received within the storage vessel 94 can be provided as a
salable product along line 96.
[0059] The compressor 90 receives the mixture of natural gas and
carbon dioxide from the heater treater 76 and builds up the
pressure of the gas. Typically, natural gas and carbon dioxide will
have a pressure of approximately 75 p.s.i.g. from the field. The
compressor 90 will enhance the pressure of the natural gas and
carbon dioxide mixture to between 600 and 700 p.s.i. As such, the
compressed mixture of natural gas and carbon dioxide can flow into
the dehydration unit 70 along line 72.
[0060] As can be seen in FIG. 1, the bulk separator 80 receives
production fluids from the well along line 100. As such, the
production well fluids will typically include natural gas, carbon
dioxide, water and oil. The bulk separator 80 serves to pass the
separated natural gas and carbon dioxide mixture along line 102 for
delivery to the compressor 90 and/or into the line 88 from the
heater treater 76. The oil and water mixture from the bulk
separator 80 passes along line 78 as an input to the vessel at the
heater treater 76. The water from the bulk separator will pass
along line 104 for disposal.
[0061] The test separator 84 receives production fluid along line
106. The test separator operates on each well separately. The test
separator 84 can determine how much carbon dioxide is associated
with the oil. The test separator 84 will then pass the oil and
water mixture the heater treater 76 along line 82. The test
separator 84 will further transmit the produced water along line
108 for disposal. Additionally, the natural gas and carbon dioxide
mixture from the test separator 84 is delivered along line 110 to
the compressor 90. As such, the natural gas and carbon dioxide
mixture from the heater treater 76, from the bulk separator 80, and
from the test separator 84 will flow for use in the system 10 of
the present invention.
[0062] In FIG. 1, it can be seen that the amine capture system 18
serves to separate the carbon dioxide from the natural gas. As
stated previously, the carbon dioxide will flow outwardly of the
amine capture system 18 along line 66 to the compressor 20. The
natural gas, as separated from the carbon dioxide, will flow along
line 110 to a natural gas processing system 112. The natural gas
processing system 112 utilizes refrigeration so as to separate the
various components of the natural gas. In particular, the methane
and ethane will flow outwardly of the natural gas processing system
112 along line 114. The methane or ethane that passes along line
114 can be delivered to the natural gas pipeline 116.
Alternatively, the natural gas that passes in the line 114 can be
utilized as the fuel for the combustion turbine 12. As such, this
natural gas would flow along line 118 as a fuel input to the
combustion turbine 12.
[0063] The natural gas processing system 112 will further pass
natural gas liquids along line 120 to a natural gas liquid storage
and loadout facility 122. The natural gas liquids can include
propane and butane. As such, the gas will need to be pressurized
for delivery. Ultimately, any natural gas liquids that are in the
natural gas storage and loadout facility 122 can be delivered along
line 124 for sale.
[0064] The natural gas processing system 112 can deliver pentanes
and hexanes along line 126 for mixture with the crude passing in
line 92. As such, these heavy natural gas components can be
delivered as part of the crude product from the system 10.
[0065] The heat recovery steam generator 14 further produces steam
of a third pressure range. This third pressure range will be in the
order of less than 25 p.s.i.g. The steam of the second pressure
range is delivered along line 128 to an absorption chiller 130. The
cooling provided by the absorption chiller 130 can also be provided
by a mechanical refrigeration unit. The steam passing in line 128
is used to provide the energy to the absorption chiller 130. The
absorption chiller 130 can produce chilled water for delivery to
the thermal storage 32 along line 132. The absorption chiller 130
will receive water, for chilling, along line 134 from the thermal
storage 32.
[0066] The thermal storage 32 is in the nature of a tank.
Typically, the water within the tank of the thermal storage 32 will
contain glycol so as to avoid any freezing. The glycol will
facilitate the ability to cool the water on a hot day while keeping
the water from freezing on extremely cold days. The thermal storage
32 will further level out the refrigeration load of the system.
Ultimately, warm water from the thermal storage 32 will pass for
cooling to the absorption chiller 130. The thermal storage 32
serves to deliver chilled water along line 136 to the inlet air
chiller 30, to the amine capture system 16, to the amine capture
system 18 and to the compressor 20. Ultimately, after the chilled
water has been utilized by these components, the water will return
along line 138 back to the thermal storage 32. It is also possible
that the chilled water flowing from the thermal storage 32 can also
be used to facilitate the refrigeration of the natural gas in the
natural gas processing system 112.
[0067] The compressor 20 serves to deliver the compressed carbon
dioxide along line 140 to the well. The carbon dioxide that is
compressed by the compressor 20 is received from the amine capture
system 18. The compressor 20 will serve to compress the carbon
dioxide to a pressure of approximately 2000 p.s.i.g. As such, this
compressed carbon dioxide can be utilized for tertiary oil recovery
in the well.
[0068] The foregoing disclosure and description of the invention is
illustrative and explanatory thereof. Various changes in the
details of the illustrated construction and the steps of the
described method can be made within the scope of the present
invention without departing from the true spirit of the invention.
The present invention should only be limited by the following
claims and their legal equivalents.
* * * * *