U.S. patent application number 15/835276 was filed with the patent office on 2018-04-19 for carbon dioxide-based geothermal energy generation systems and methods related thereto.
The applicant listed for this patent is TerraCOH Inc.. Invention is credited to Jimmy Bryan Randolph.
Application Number | 20180106138 15/835276 |
Document ID | / |
Family ID | 49681157 |
Filed Date | 2018-04-19 |
United States Patent
Application |
20180106138 |
Kind Code |
A1 |
Randolph; Jimmy Bryan |
April 19, 2018 |
CARBON DIOXIDE-BASED GEOTHERMAL ENERGY GENERATION SYSTEMS AND
METHODS RELATED THERETO
Abstract
A system comprises an injection well in communication with an
underground reservoir that is at a first temperature and that
contains a native fluid, a production well in communication with
the reservoir, and a supply system providing a non-water based
working fluid to the injection well at a second temperature lower
than the first temperature. Exposure of the working fluid to the
first temperatures heats the working fluid to a third temperature
that is higher than the second temperature. At least a portion of
the working fluid at the third temperature enters the production
well and is produced from the reservoir as a production fluid. An
energy recovery apparatus in fluid communication with the
production well converts energy contained in the production fluid
to electricity, heat, or a combinations thereof.
Inventors: |
Randolph; Jimmy Bryan;
(Minneapolis, MN) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
TerraCOH Inc. |
Bloomington |
MN |
US |
|
|
Family ID: |
49681157 |
Appl. No.: |
15/835276 |
Filed: |
December 7, 2017 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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13800720 |
Mar 13, 2013 |
9869167 |
|
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15835276 |
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61725270 |
Nov 12, 2012 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
F24T 10/20 20180501;
Y02E 10/10 20130101; Y02E 10/14 20130101; Y02P 90/70 20151101; E21B
43/164 20130101; E21B 43/40 20130101; E21B 43/24 20130101 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 43/16 20060101 E21B043/16; E21B 43/40 20060101
E21B043/40 |
Claims
1. A system comprising: one or more injection wells for accessing
one or more underground reservoirs, the one or more reservoirs
being at one or more first temperatures and containing at least one
native fluid, each of the one or more injection wells having an
injection well reservoir opening in fluid communication with one of
the one or more reservoirs; one or more production wells each
having a production well reservoir opening in fluid communication
with one of the one or more reservoirs; a working-fluid supply
system for providing a non-water based working fluid to the one or
more injection wells at a second temperature lower than the one or
more first temperatures, wherein the working-fluid supply system,
the one or more injection wells, and the one or more production
wells are configured to store at least a first portion of the
non-water based working fluid in the one or more reservoirs for a
specified period of time, wherein exposure of the working fluid to
the one or more first temperatures heats the working fluid to a
third temperature that is higher than the second temperature,
wherein at least a second portion of the working fluid that is at
the third temperature enters the one or more production well
reservoir openings and is produced from the one or more reservoirs
via the one or more production well to provide a production fluid;
and an energy recovery apparatus in fluid communication with the
one or more productions wells, wherein energy contained in the
production fluid is converted to electricity, heat, or a
combination thereof, in the energy recovery apparatus.
2. The system of claim 1, wherein the at least one native fluid
includes a solution comprising methane, wherein exposure of the
non-water based working fluid to the at least one native fluid
causes methane to come out of the solution with the native fluid
such that the production fluid comprises methane that had come out
of the solution, and wherein the energy recovery apparatus
comprises at least one separation apparatus that separates at least
a portion of the methane from the production fluid.
3. The system of claim 2, wherein the energy recovery apparatus
further comprises a heater that combusts at least a portion of the
separated methane and heats the production fluid to a fourth
temperature that is higher than the third temperature to provide a
heated production fluid.
4. The system of claim 1, wherein the energy recovery apparatus
further comprises at least one of: one or more
electricity-generating devices; one or more heat exchangers; or a
combination thereof to convert energy contained in the production
fluid to electricity, heat energy, or a combination thereof.
5. The system of claim 1, wherein the energy recovery apparatus
comprises at least one heat recovery apparatus for recovering heat
from at least a first portion of the production fluid to heat a
second portion of the production fluid.
6. The system of claim 1, wherein the at least one native fluid
further comprises at least one hydrocarbon, wherein the production
fluid comprises at least a portion of the at least one hydrocarbon,
and wherein the energy recovery apparatus further comprises: one or
more separation units to separate the at least one hydrocarbon from
the production fluid; and a heat recovery apparatus configured to
recover heat energy from at least one of the one or more separation
units, the separated at least one hydrocarbon, or the separated
production fluid.
7. The system of claim 1, wherein the one or more reservoirs
comprise a brine aquifer and the at least one native fluid
comprises a brine with methane dissolved in the brine.
8. The system of claim 1, wherein the reservoir comprises a
partially-depleted oil or natural gas field and the at least one
native fluid comprises at least one hydrocarbon.
9. The system of claim 1, wherein the non-water based working fluid
is carbon dioxide.
10. The system of claim 1, wherein the specified period of time is
a temporary period of time, a semi-permanent period of time, a
substantially permanent period of time, or a permanent period of
time.
11. The system of claim 1, wherein the production fluid comprises
from 0.01 wt % to 99 wt % of the non-water based working fluid.
12. A system comprising: one or more injection wells for accessing
one or more underground reservoirs, the one or more reservoirs
being at one or more first temperatures, each of the one or more
injection wells having an injection well reservoir opening in fluid
communication with at least one of the one or more reservoirs; one
or more production wells each having a production well reservoir
opening in fluid communication with at least one of the one or more
reservoirs; a working-fluid supply system for providing a non-water
based working fluid to the one or more injection wells at a second
temperature, wherein exposure of the non-water based working fluid
to the one or more first temperatures results in heat energy being
exchanged between the non-water based working fluid and the one or
more reservoirs to provide a production fluid at a third
temperature, wherein at least a portion of the production fluid at
the third temperature enters the production well reservoir opening
and is produced from the reservoir via the one or more production
wells to provide a produced fluid; and an energy recovery apparatus
in fluid communication with the one or more production wells, the
energy recovery apparatus including equipment that generates waste
heat and at least one heat recovery apparatus configured to recover
at least a portion of the waste heat from the equipment and uses
the recovered portion of the waste heat to heat the produced fluid
to a fourth temperature that is higher than the third temperature
to provide a heated produced fluid.
13. The system of claim 12, wherein the equipment that generates
waste heat comprise at least one of: a compressor for compressing
at least a portion of the produced fluid or the working fluid; a
pump for moving at least a portion of the produced fluid or the
working fluid; an expansion device or generator for electricity
generation; an enhanced oil recovery system; a co-located
facility.
14. The system of claim 13, wherein the co-located facility
comprises a fuel production facility or a power plant.
15. The system of claim 14, wherein the fuel production facility
comprises an ethanol production facility or a biofuel production
facility.
16. The system of claim 12, wherein the energy recovery apparatus
further comprises at least one of: one or more
electricity-generating devices; one or more heat exchangers; or a
combination thereof to convert energy contained in the heated
produced fluid to electricity, heat energy, or a combination
thereof.
17. The system of claim 12, wherein the reservoir comprises a brine
aquifer.
18. The system of claim 12, wherein the reservoir comprises a
partially-depleted oil or natural gas field and the native fluid
comprises at least one hydrocarbon.
19. The system of claim 12, wherein the non-water based working
fluid is carbon dioxide.
20. The system of claim 12, wherein the production fluid comprises
from 0.01 wt % to 99 wt % of the non-water based working fluid.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation of U.S. patent
application Ser. No. 13/800,720, filed on Mar. 13, 2013, which
claims the benefit of priority to U.S. Provisional Patent
Application Ser. No. 61/725,270, entitled "ENHANCED CARBON-DIOXIDE
BASED GEOTHERMAL ENERGY GENERATION SYSTEMS AND METHODS," filed on
Nov. 12, 2012, which applications are incorporated by reference
herein in their entirety.
BACKGROUND
[0002] In light of global climate change and in response to an
increased desire to reduce dependence on foreign oil supplies,
renewable energy systems, such as wind, solar and geothermal-based
systems are being increasingly researched and developed. However,
many such systems have only limited potential due to, for example,
high costs, overall process inefficiencies, possible adverse
environmental impact, and the like.
SUMMARY
[0003] This disclosure describes systems and methods for
efficiently recovering geothermal heat from reservoirs by injecting
a non-water based working fluid, such as carbon dioxide (CO.sub.2),
into the reservoir to extract geothermal heat. The CO.sub.2 can
then be produced back to the surface and a portion of the
geothermal energy captured by the CO.sub.2 can be recovered by an
energy recovery apparatus, such as an electricity production
apparatus (e.g., an expansion device driving a generator) or a heat
recovery apparatus (e.g., one or more heat exchangers for heating a
second working fluid).
[0004] In particular, this disclosure describes recovering
geothermal heat from reservoirs that include a native fluid
including a solution comprising natural gas, and in particular
methane (CH.sub.4). The CO.sub.2 can cause the CH.sub.4 to come out
of solution with the native fluid such that the CH.sub.4 forms a
production fluid with the CO.sub.2. The production fluid can be
heated by geothermal heat and produced to the surface where at
least a portion of the CH.sub.4 can be separated from the
production fluid and combusted to increase the overall temperature
of the production fluid before it is fed into the energy recovery
apparatus. Such a system and method can utilize the chemical
properties of CO.sub.2 to extract CH.sub.4 from the reservoir, and
then can use the chemical energy stored in a portion of the
CH.sub.4 to supplement the geothermal energy captured by the
production fluid. The recovery of methane from the reservoir and
subsequent combustion of a portion of the methane to boost
production fluid temperature or pressure, or both, can increase the
overall system efficiency and the overall power produced compared
to geothermal capture alone. The methane capture and use of the
systems and methods of the present disclosure can allow for
economically viable recovery of geothermal energy from
low-temperature reservoirs (e.g., down to about 15.degree. C., or,
in some situations, down to about 10.degree. C.). The systems and
methods of the present invention can, therefore, open up reservoirs
for geothermal exploitation that heretofore had been economically
difficult or impossible to achieve.
[0005] The present disclosure describes a system comprising one or
more injection wells for accessing one or more underground
reservoirs, the one or more reservoirs being at one or more first
temperatures and containing at least one native fluid, the native
fluid including a solution comprising methane, each of the one or
more injection wells having an injection well reservoir opening in
fluid communication with at least one of the one or more
reservoirs. The system further includes one or more production
wells, each having a production well reservoir opening in fluid
communication with at least one of the one or more reservoirs. A
working-fluid supply system provides a non-water based working
fluid to the one or more injection wells at a second temperature
lower than the first temperatures. Exposure of the non-water based
working fluid to the native fluid causes at least a portion of the
methane to come out of solution with the native fluid to form a
production fluid of at least a portion of the non-water based
working fluid and the portion of the methane. Exposure of the
mixture to the first temperatures heats the production fluid to a
third temperature that is higher than the second temperature,
wherein the production fluid is capable of entering one or more of
the production well reservoir openings. The system also includes an
energy recovery apparatus in fluid communication with the one or
more productions wells, wherein energy contained in the production
fluid can be converted to electricity, heat, or a combination
thereof, in the energy recovery apparatus.
[0006] The present disclosure also describes a method comprising
introducing a non-water based working fluid at a first temperature
through one or more injection wells to one or more underground
reservoirs containing at least one native fluid, the native fluid
including a solution comprising methane, wherein the one or more
reservoirs are at one or more second temperatures that are greater
than the first temperature, exposing the non-water based working
fluid to the native fluid so that at least a portion of the methane
comes out of solution with the native fluid to form a production
fluid of at least a portion of the non-water based working fluid
and the portion of the methane, exposing the production fluid to
the second temperature to heat the production fluid to a third
temperature that is greater than the first temperature, producing
the production fluid through one or more production wells, and
extracting energy from the production fluid.
[0007] These and other examples and features of the present systems
and methods will be set forth in part in the following Detailed
Description. This Summary is intended to provide an overview of the
present subject matter, and is not intended to provide an exclusive
or exhaustive explanation. The Detailed Description below is
included to provide further information about the present systems
and methods.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] FIG. 1 is a simplified schematic diagram of an example
geothermal energy recovery system.
[0009] FIG. 2 is a simplified schematic diagram of another example
geothermal energy recovery system.
[0010] FIG. 3 is a simplified schematic diagram of another example
geothermal energy recovery system.
[0011] FIG. 4 is a simplified schematic diagram of another example
geothermal energy recovery system.
[0012] FIG. 5 is a simplified schematic diagram of the formation of
a high methane concentration zone within a reservoir.
[0013] FIG. 6 is a simplified schematic diagram of the placement of
various injection wells and production wells for extraction of
working fluid and methane from a reservoir.
[0014] FIG. 7A is a phase diagram of an example power cycle for a
CO.sub.2-only working fluid.
[0015] FIG. 7B is a phase diagram of an example power cycle for a
CO.sub.2-methane working fluid.
[0016] FIG. 8 is a simplified schematic diagram of another example
geothermal energy recovery system.
[0017] FIG. 9 is a simplified schematic diagram of another example
geothermal energy recovery system.
[0018] FIG. 10 is a simplified schematic diagram of another example
geothermal energy recovery system.
[0019] FIG. 11A shows a graph of electricity produced by a
methane-enhanced geothermal energy recovery system compared to a
non-enhanced CO.sub.2-based geothermal energy recovery system and
compared to methane combustion depending on the wellhead
temperature of the produced fluid.
[0020] FIG. 11B shows a graph of electricity produced by a
methane-enhanced geothermal energy recovery system compared to a
non-enhanced CO.sub.2-based geothermal energy recovery system and
compared to methane combustion depending on the bottomhole
temperature of the produced fluid.
[0021] FIG. 12A shows a graph of electricity produced by a
methane-enhanced geothermal energy recovery system compared to a
non-enhanced CO.sub.2-based geothermal energy recovery system and
compared to methane combustion depending on the wellhead
temperature of the produced fluid.
[0022] FIG. 12B shows a graph of electricity produced by a
methane-enhanced geothermal energy recovery system compared to a
non-enhanced CO.sub.2-based geothermal energy recovery system and
compared to methane combustion depending on the bottomhole
temperature of the produced fluid.
[0023] FIG. 13 shows a graph of electricity produced by a waste
heat-enhanced geothermal energy recovery system compared to a
non-waste heat enhanced CO.sub.2-based geothermal energy recovery
system and compared to waste heat recovery alone.
[0024] FIG. 14 shows a graph of the available energy values from
various sources.
[0025] FIG. 15 shows a graph of the electricity produced from
various sources.
DETAILED DESCRIPTION
[0026] In the following detailed description, reference is made to
the accompanying drawings that form a part hereof, and in which is
shown by way of illustration, specific examples in which the
invention may be practiced. These examples are described in
sufficient detail to enable those skilled in the art to practice
the invention, and it is to be understood that other embodiments
may be utilized. It is also to be understood that structural,
procedural, chemical and system changes can be made without
departing from the spirit and scope of the present invention. The
following detailed description is, therefore, not to be taken in a
limiting sense, and the scope of the present invention is defined
by the appended claims and their equivalents.
[0027] The present disclosure describes geothermal energy recovery
systems and methods using a non-water based working fluid, such as
carbon dioxide (CO.sub.2) for the recovery of geothermal energy.
The geothermal energy recovery systems and methods can include
aspects of the example systems and methods disclosed in U.S.
Published Application No. US2012-0001429 to Saar, et al., entitled
"CARBON DIOXIDE-BASED GEOTHERMAL ENERGY GENERATION SYSTEMS AND
METHODS RELATED THERETO," and U.S. patent application Ser. No.
13/554,868 to Saar et al., entitled "CARBON DIOXIDE-BASED
GEOTHERMAL ENERGY GENERATION SYSTEMS AND METHODS RELATED THERETO,"
filed on Jul. 20, 2012, both of which are hereby incorporated by
reference herein in their entireties. As described in these
applications, a carbon dioxide working fluid can travel through the
reservoir as a gas plume such that the system in the applications
are referred to as Carbon Dioxide (or CO.sub.2) Plume Geothermal
("CPG") systems.
[0028] The present disclosure also describes feeding the non-water
based working fluid to a reservoir that contains a native fluid
comprising a solution including methane. For example, the reservoir
can comprise a deep brine aquifer comprising a brine solution with
natural gas (the natural gas comprising generally about 97% methane
or more) dissolved in the brine solution. Because "natural gas," as
it is used herein, is generally at least about 97 wt % methane or
more, the remainder of this disclosure will refer to it as
"methane" for the sake of brevity. It will be understood by a
person of ordinary skill in the art that "methane" can refer to
other gaseous hydrocarbons that can be included in natural gas,
such as ethane, propane, and higher order alkanes. The injection of
a carbon dioxide working fluid into the brine aquifer can cause a
portion of the CO.sub.2 to dissolve into the brine solution, which
can force a substantial portion of the dissolved methane out of
solution. The released methane can combine with the remaining
CO.sub.2 to form a production fluid in the form of a gaseous plume
similar to the CO.sub.2 plumes in the CPG systems. In addition, a
zone of a mixture of brine solution with dissolved or free-phase
methane plus CO.sub.2 can form between the native brine solution
and the zone of CO.sub.2 combined with methane. The fluid
comprising brine, methane, and/or CO.sub.2 can also form a
production fluid, in addition to the production fluid that is
similar to a CO.sub.2 plume formed in a CPG system. As described in
more detail below, a portion of the methane recovered from the
brine aquifer can be combusted to increase the temperature or the
pressure, or both, of the production fluid prior to recovering
energy from the production fluid, such as by passing the production
fluid through an expansion device that powers a generator to
produce electricity. The remainder of the methane present in the
production fluid can either be separated out and sold, or it can be
re-injected into the reservoir to provide for further production
and use in the energy recover system. The use of recovered methane
to boost the economic efficiency of the system can be referred to
herein as methane-enhanced CO.sub.2 Plume Geothermal ("ME-CPG")
systems.
[0029] Alternatively, the reservoir can include an oil or natural
gas field where the oil or natural gas hydrocarbons have been
partially recovered using conventional recovery methods. The oil or
natural gas hydrocarbons can be recovered via the injection of
carbon dioxide or other recovery fluids into the field in order to
release a portion of the hydrocarbons from the reservoir. This
process can be referred to as "enhanced oil recovery" (EOR)
(described in more detail below). The production fluid from an EOR
field can include the CO.sub.2 working fluid, methane and other
natural gas components, other higher order hydrocarbons, and brine.
As with the brine aquifer reservoir described above, a portion of
the methane recovered from the EOR field can be used to increase
the temperature, the pressure, or both of the production fluid
before further energy recovery is conducted. The EOR hydrocarbons
can be separated from the production fluid and sold. A portion of
the separated hydrocarbons can also be combusted to heat the
working fluid or increase the working fluid's pressure prior to
energy recovery.
[0030] The systems of this disclosure can include components or
aspects where considerable heat is generated--heat that typically
is lost to the atmosphere. For example, both EOR and CPG systems
can include one or more compressors for the CO.sub.2 so that the
CO.sub.2 can be injected back into the reservoir for further oil or
natural gas recovery, geothermal heat recovery, or CO.sub.2
sequestration. The compressors can generate considerable heat, on
the order of 400 to 450 kilojoules (kJ) per kilogram (kg) of
CO.sub.2 compressed for each stage of compression, depending on the
type of compressor system used. EOR systems can also generate
considerable heat during the separation of the oil and natural gas
hydrocarbons from the production fluid, for example if a portion of
the methane or other produced fluid is combusted to heat the
production fluid in order to improve separation efficiency.
[0031] In some examples, the geothermal energy recovery system and
the EOR system (if present) can be co-located with another facility
type, e.g., a power plant or an ethanol or biofuel production
facility. For example, the co-located facility can be the initial
source of CO.sub.2 that is compressed and injected into the
reservoir for the recovery of geothermal heat, methane, and/or
other hydrocarbons. The co-located facility can also typically
produce considerable waste heat. In addition, for a co-located
biofuel production facility, such as an ethanol plant, a portion of
the biofuel produced at the plant can be combusted to increase the
temperature of a working fluid or production fluid or to increase
the pressure of the working fluid, or both, prior to energy
recovery from the working fluid or production fluid. Similarly,
biofuel or other from an off-site third party can be obtained and
transported to the geothermal recovery system and combusted to
increase the temperature of a working fluid or production fluid or
to increase the pressure of the working fluid, or both.
[0032] In some examples, the systems and methods of the present
disclosure can include a heat recovery system for recovering waste
heat generated by some other aspect of the system or method, such
as waste heat from the CO.sub.2 compressors, the EOR separation
system, or a co-located facility. The waste heat recovered by the
heat recovery system can also be used to increase the temperature,
the pressure, or both of the production fluid before it is fed into
the energy recovery system (e.g., the expansion device and
generator). Waste heat capture with a heat recovery system can
increase the efficiency of the geothermal energy recovery system
and method similar to the enhancement provided by recovered methane
combustion in the ME-CPG system. The capture of waste heat to boost
the economic efficiency of the system can be referred to herein as
waste heat-enhanced CO.sub.2 Plume Geothermal ("WHE-CPG") systems.
It will be appreciated that both ME-CPG and WHE-CPG can be used in
the same system.
Conventional Geothermal Energy Technology
[0033] Geothermal energy is heat energy generated and stored within
the earth (or any other planet), which can be "mined" for various
uses, including to produce electricity, for direct use, or for
ground-source heat pumps. Geothermal energy sources can be
relatively constant with heat energy replenished on human time
scales after being "mined." Geothermal energy also can require no
storage other than the earth.
[0034] Potential uses of conventional geothermal energy are
generally temperature dependent, with cascading systems utilizing a
single geothermal resource for multiple purposes. Water-based
geothermal systems that use water as a working fluid (e.g.,
conventional water-based enhanced geothermal systems (EGS) and
conventional non-EGS water-based) can require very high
temperatures. For example, electricity generation at water-based
geothermal power plants typically requires temperatures in excess
of 165.degree. C. Direct uses, such as aquaculture, greenhouse,
industrial and agricultural processes, resorts, space and district
heating (wells to structures) from such systems can utilize more
moderate temperatures of about 38 to 165.degree. C. when water is
the subsurface geothermal working fluid. Residential and commercial
building ground-source heat pumps from water-based geothermal
systems, which may use a secondary heat exchange fluid (e.g.,
isobutene) in order to transfer geothermal heat energy from the
ground for use, can generally require temperatures between about 4
and 38.degree. C.
Definitions
[0035] The terms "subterranean" or "subsurface" or "underground,"
as used herein, can refer to locations and/or geological formations
beneath the Earth's surface.
[0036] The term "in situ," as used herein, can refer to a natural
or original position or place of a geologic feature which may be
above ground or underground, such that it is located in a place
where it was originally formed or deposited by nature and has
remained substantially undisturbed over time, such that it is in
substantially the same original condition. A geologic feature can
be rock, mineral, sediment, reservoir, caprock and the like, or any
combination thereof. A geologic feature is further considered to
remain "in situ" following minor manmade disturbances used to
create and/or position components, such as channels such as
injection wells and/or production wells, within, around or near the
feature. A feature is also considered to remain "in situ" following
minor man-initiated disturbances, such as causing a controllable or
limited amount of rock, mineral, sediment or soil to become
dislodged as a result of the minor manmade or natural disturbance.
In contrast, a feature is not considered to remain "in situ"
following any type of large-scale manmade disturbances, including
large-scale hydrofracturing (such as to create an artificial
reservoir), or man-initiated disturbances, such as permanent
deformation of a geologic feature, earthquakes and/or tremors
following large-scale hydrofracturing, all of which can have a
further negative impacts on groundwater flow paths, habitats and
man-made structures.
[0037] The term "large-scale hydrofracturing," as used herein, can
refer to a known method for creating or inducing artificial
fractures and/or faults in a feature, such as a rock or partially
consolidated sediments, typically during operation of an enhanced
geothermal system (EGS). See, for example, U.S. Pat. No. 3,786,858
to Potter, which employs water for hydraulic fracturing of rock to
create a thermal geological reservoir from which fluid is
transported to the surface. Large-scale hydrofracturing is known to
create unintended fluid flow pathways that can result in fluid loss
or "shortcutting," which in turn decreases geothermal heating
efficiencies of the working fluid. Large-scale hydrofracturing can
also cause (micro-) seismicity and damages to natural and/or
manmade structures.
[0038] The term "rock," as used herein, can refer to a relatively
hard, naturally formed mineral, collection of minerals, or
petrified matter. A collection of rocks is commonly referred to as
a "rock formation." Various types of rocks have been identified on
Earth, to include, for example, igneous, metamorphic, sedimentary,
and the like. A rock can erode or be subject to mass wasting to
become sediment and/or soil proximate to or at a distance of many
miles from its original location.
[0039] The term "sediment," as used herein, can refer to a granular
material eroded by forces of nature, but not yet to the point of
becoming "soil." Sediment may be found on or within the Earth's
crust. A collection of sediments is commonly referred to as a
"sediment formation." Sediment is commonly unconsolidated, although
"partially consolidated sediments" are often referred to simply as
"sediments" and are therefore considered to be included within the
definition of sediment.
[0040] The term "soil," as used herein, can refer to a granular
material comprising a biologically active, porous medium. Soil is
found on, or as part of, the uppermost layer of the Earth's crust
and evolves through weathering of solid materials, such as
consolidated rocks, sediments, glacial tills, volcanic ash, and
organic matter. Although often used interchangeably with the term
"dirt," dirt is technically not biologically active.
[0041] The term "fluid," as used herein, can refer to a liquid,
gas, or combination thereof, or a fluid that exists above the
critical point, e.g., a supercritical fluid. A fluid is capable of
flowing, expanding, and accommodating a shape of its physical
surroundings. A fluid can comprise a native fluid, a working fluid,
or combinations thereof. Examples of fluid include, for example,
air, water, brine (i.e., salty water), hydrocarbon, CO.sub.2,
magma, noble gases, or any combination thereof.
[0042] The term "native fluid," as used herein, can refer to a
fluid which is resident in a rock formation or sediment formation
prior to the implementation of the systems or methods of the
present disclosure. A native fluid includes, but is not limited to,
water, saline water, oil, natural gas, hydrocarbons (e.g., methane,
natural gas, oil), and combinations thereof. Carbon dioxide can
also be previously-present in the rock or sediment formation and
thus constitute a native fluid in this case.
[0043] The term "working fluid," as used herein, can refer to a
fluid which is not native to a rock formation or sediment formation
and that is used by the systems or methods of the present
disclosure for some purpose. A working fluid can undergo a phase
change from a gas to a liquid (energy source), a liquid to gas
(refrigerant), or can become part of a solution (e.g., by
dissolving into a native fluid). A "working fluid" in a machine or
in a closed loop system can be the pressurized gas or liquid which
actuates the machine. Water is used as a working fluid in
conventional (e.g., water-based) heat engine systems. Non-water
based working fluids can include, but are not limited to, ammonia,
sulfur dioxide, carbon dioxide, and non-halogenated hydrocarbons
such as methane. A working fluid can include a fluid in a
supercritical state. Different working fluids can have different
thermodynamic and fluid-dynamic properties, resulting in different
power conversion efficiencies.
[0044] The term "pore space" as used herein, can refer to any space
not occupied by a solid (rock or mineral). Pore space can be the
space formed between grains or the space formed by fractures,
faults, fissures, conduits, caves, or any other type of non-solid
space. Pore space can be connected or unconnected and it can evolve
over time due to changes in solid space volume or size (which can
come from chemical reactions, deformations, etc.). A space can be
filled with fluid and still be deemed to be "pore space."
[0045] The term "CO.sub.2 plume" as used herein, can refer to a
large-scale (e.g., meters to several kilometers to tens of
kilometers across) CO.sub.2 presence within subsurface pore spaces.
Within a CO.sub.2 plume, a significant percentage of fluid in the
pore space can be CO.sub.2. The CO.sub.2 plume can include other
fluids, such as native methane or other hydrocarbons, which can be
collected and carried by the CO.sub.2 plume as it travels through a
reservoir. For example, a CO.sub.2 plume can include a substantial
percentage (e.g., as much as 20 wt. %) methane that has been
desorbed from a saline aquifer (as described in more detail below).
A CO.sub.2 plume can also include a substantial portion of native
hydrocarbons, (e.g., up to 90 wt % hydrocarbons or more), and can
still be considered a "CO.sub.2 plume" within the meaning of the
present disclosure. A CO.sub.2 plume can contain a substantial
portion, e.g., as much as 70% by volume, or more, of a native fluid
such as brine or hydrocarbons extracted from a reservoir. The brine
or other native fluid can be immobile or only minimally mobile and,
therefore, generally considered in the art to be residually
trapped.
[0046] The term "reservoir" or "storage rock formation" or "storage
sediment formation," as used herein, can refer to a formation
comprising one or more of rock, sediment, and soil that can be
capable of receiving and storing an amount of fluid substantially
"permanently" as that term is understood in the geological
arts.
[0047] The term "geothermal heat flow," as used herein, can refer
to any kind of heat transfer in the subsurface and can include one
or more of conductive heat transfer, advective heat transfer (also
referred to as convective heat transfer), and radiative heat
transfer (although radiative heat transfer can typically be
negligible in the subsurface). A "low" heat flow generally can be
considered to be less than about 50 milliwatts per square meter. A
"moderate" heat flow generally can be considered to be at least
about 50 to about 80 milliwatts per square meter. A "high" heat
flow generally can be considered to be greater than 80 milliwatts
per square meter.
[0048] The term "injection well," as used herein, can refer to a
well or borehole, which can be cased (e.g., lined) or uncased, and
which can contain one or more pipes through which a fluid can flow
(typically in a downward direction) for purposes of releasing that
fluid into the subsurface at some depth.
[0049] The term "production well," as used herein, can refer to a
well or borehole, which can be cased (e.g., lined) or uncased, and
which can contain one or more pipes through which a fluid can flow
(typically in an upward direction) for purposes of bringing fluids
up from the subsurface up to the Earth's surface or near the
surface. A production well can exist in the same borehole as an
injection well.
[0050] The term "enhanced geothermal system" (EGS), as used herein,
can refer to a system in which a manmade (e.g., artificial)
reservoir is created, usually by means of large-scale
hydrofracturing of the subsurface, e.g., by inducing fractures to
create space which can contain significant amounts of fluid. Such
artificial reservoirs typically can be much smaller than natural
reservoirs.
[0051] The term "enhanced oil recovery" (EOR) (also referred to as
"improved oil recovery," "tertiary recovery," or "quaternary
recovery"), as used herein, can refer to a system or method of
recovering hydrocarbons, including, by not limited to, liquid
hydrocarbons such as crude oil and hydrocarbons such as natural gas
that are gaseous at atmospheric pressure and temperature, from a
reservoir. EOR can include the injection of a fluid, such as carbon
dioxide, or other components into the reservoir in order to improve
extraction of the hydrocarbons, such as by at least one of reducing
the fluid viscosity, reducing the surface tension of the
hydrocarbons, or increasing pressure in the reservoir, in order to
more easily remove them from the reservoir.
[0052] The term "conventional water-based geothermal system," as
used herein, can refer to a geothermal system that uses water as a
working fluid. A conventional water-based geothermal approach can
be used in natural reservoir systems or in hydrofractured (e.g.,
EGS) systems.
[0053] The term "conventional CO.sub.2-based EGS," as used herein,
can refer to a conventional EGS system that uses carbon dioxide as
the working fluid.
[0054] The term "waste heat," as used herein, can refer to heat
energy generated by a system or unit operation that typically is
allowed to dissipate to the environment rather than being used for
some other purpose within the system or method.
Enhanced CPG Systems
[0055] FIG. 1 shows an example system 10 for the recovery of
geothermal energy from a reservoir 1. The reservoir 1 can include a
native fluid 2. The native fluid 2 can include a solution
comprising methane (CH.sub.4) 4. In an example, the native fluid 2
can comprise a brine within a reservoir 1 that is a saline aquifer.
The methane 4 can be dissolved in the brine in low concentrations.
In another example, the native fluid 2 can be native hydrocarbons,
such as those in an oil field. A working fluid 12 can be injected
into the reservoir 1 via an injection well 14. The injection well
14 can include an injection well opening 16 that is in fluid
communication with the reservoir 1 to allow the working fluid 12 to
enter the reservoir 1.
[0056] In an example, the working fluid 12 is a non-water based
working fluid 12, such as carbon dioxide (CO.sub.2). For the sake
of brevity, the remainder of this disclosure will describe the
working fluid 12 as CO.sub.2 working fluid 12. However, as
described above, the working fluid 12 can comprise other suitable
compounds capable of absorbing thermal energy from its
surroundings, and further releasing the thermal energy as described
herein. Other examples of non-water based working fluids 12 can
include, but are not limited to, ammonia, sulfur dioxide, or
non-halogenated hydrocarbons such as methane.
[0057] The CO.sub.2 working fluid 12 can be provided from a
CO.sub.2 source 18, such as a waste stream from a facility that
produces CO.sub.2, such as via combustion. Examples of facilities
that can be a CO.sub.2 source 18 include power plants, such as a
fossil fuel power plants (e.g., coal plant, natural gas plant, and
the like), a plant capable of producing fuel, such as biofuel
(e.g., ethanol plant), or an industrial plant, such as a cement
manufacturer, steel manufacturer, and the like. The CO.sub.2 source
18 can also be natural geologic CO.sub.2 produced from a geologic
formation. In an example, the CO.sub.2 can be transported from a
remote CO.sub.2 source 18 via any suitable means, (e.g., a pipeline
or via various transportation means, such as a truck, ship, or
railroad). In another example, the facility that provides the
CO.sub.2 source 18 can be co-located with the geothermal recovery
system 10, such as a co-located power plant, biofuel plant, or
industrial plant. As described in more detail below, a co-located
facility can provide for synergies allowing for more efficient
operation of the co-located facility and of the geothermal energy
recovery.
[0058] In an example, the system 10 can be located at a site (e.g.,
in a position) configured to provide access to a target formation.
The target formation can comprise a caprock 8 located above a
reservoir 1, as shown in FIG. 1. The reservoir 1 can have a natural
temperature higher than a temperature of the working fluid. The
natural temperature can be caused by in-situ geothermal heat
located within the reservoir or the geological formation proximate
to the reservoir. The natural temperature in the reservoir 1 can be
affected by a geothermal heat 6 flow, such as the geothermal heat 6
flowing up from below.
[0059] A top layer 9 can be located above the caprock 8 and the
reservoir 1. The top layer 9 can comprise any number of layers and
types of natural deposits or formations. For example, the top layer
9 can comprise one or more features such as one or more reservoirs
(e.g., the reservoir 1 or a different reservoir) or one or more
caprocks (e.g., the caprock 8) having the features as described
herein. The top layer 9 can additionally or alternatively comprise
additional areas suitable for injection of the working fluid, such
as the CO.sub.2 working fluid 12. In an example, the top layer 9
additionally or alternatively further comprises any type of rocks,
including rocks or sediments in layers, rock or sediment
formations, and the like, or any combinations thereof. The top
layer 9 can additionally or alternatively comprise a top layer or
layers of sediment or soil of varying depths. The permeability and
porosity of the top layer 9 can vary widely, as long as drilling
can be performed to insert the injection well 14 and production
well 28, as described below.
[0060] The top layer 9 can include a variety of geologic features,
including, but not limited to, soil, sand, dirt, sediment, and the
like, or combinations thereof. The top layer 9 can further have a
wide range of depths (e.g., "thickness") sufficient to ensure the
working fluid introduced into the reservoir 1 can remain in the
desired state, such as a supercritical state. In an example, the
depth of the top layer 9 is at least 100 meters (m) or more, and
can be up to one (1) kilometer (km) or more, such as up to three
(3) km, four (4) km, five (5) km, for example, up to 10 km or over
15 km including any range there between, below the Earth's surface
(e.g., below or within a given topography in an area, which may or
may not be exposed to the atmosphere). In most examples, however,
it is expected that the target formations will be located between
about 800 m and about four (4) km beneath the Earth's surface.
[0061] Factors that can be considered in selecting reservoir depths
can also vary according to local geology (e.g., specific rock type,
geothermal heat flow rates, subsurface temperatures), access to
working fluid (e.g., carbon dioxide from fossil fuel burning power
plants, ethanol plants), drilling and operation costs, and
sociopolitical circumstances (e.g., consumer locations, constructs,
electric grid locations, and the like).
[0062] The target formation, which can include the reservoir 1, a
caprock 8, and a top layer 9, can be made up of a variety of rock
types, including, but not limited to, igneous rock, metamorphic
rock, limestone, sedimentary rock, crystalline rock, and
combinations thereof. In an example, the target formation is a
sedimentary basin having a substantially bowl or convex shape. In
other examples, the target formation can have another shape, such
as the substantially dome or concave shape, although the present
disclosure is not limited to the shapes described or depicted in
the figures. In some examples, the target formation is lower than
the lowest freshwater aquifer, but this may not always be the case.
The target formation can comprise a brine or water aquifer or a
brine or water-filled rock formation (e.g., reservoir 1) that
includes a native fluid 2. The native fluid 2 can be inhibited or
prevented from escaping upwardly, for example due to the presence
of the caprock 8. The target formation can also contain a fault
which can offset the target formation or a portion of the target
formation, thereby forming a geological trap, as the term is
understood in the art. In an example, the target formation is a
reservoir containing one or more of natural gas, oil, native
CO.sub.2, fresh water, or brine.
[0063] In an example, CO.sub.2, such as the CO.sub.2 working fluid
12 shown in FIG. 1, is used as the working fluid in combination
with a reservoir 1 located at least about 0.1 km, to about 5 km
deep. Such a combination can minimize upward leakage of the working
fluid, since additional caprocks 8 can be present between the
reservoir 1 and the Earth's surface. Additionally, higher natural
reservoir temperatures (e.g., greater than about 70.degree. C.) and
higher pressures (e.g., greater than about 8 MPa) can be
encountered at such depths. Larger depths can also increase the
likelihood of the presence of dissolved salts and other minerals in
the native fluid, which can reduce the likelihood that such native
fluid would otherwise be useful for drinking and irrigation
applications.
[0064] If present, the caprock, such as the caprock 8 shown in FIG.
1, can be a geologic feature having a very low permeability, e.g.,
below about 10.sup.-16 m.sup.2. Such a low permeability can allow
the caprock 8 to essentially function as a barrier for fluid
contained in the reservoir 1 below. Permeability can also be
dependent, in part, on the depth (e.g., thickness) of the caprock
8, as well as the depth of the top layer 9 above the caprock 8 and
the reservoir 1. The porosity of the caprock 8 can vary widely. As
is known in the art, even if a rock is highly porous, if voids
within the rock are not interconnected, fluids within the closed,
isolated pores cannot move. Therefore, as long as the caprock 8
exhibits permeability sufficiently low to allow it to prevent or
inhibit fluid leakage from fluid in the reservoir 1, the porosity
of the caprock 8 is not limited.
[0065] The thickness of the caprock 8 can vary, but is generally
substantially less than the thickness of the top layer 9. In an
example, the top layer 9 has a thickness on the order of 10, or 10
to 100, up to 1000 times the thickness of the caprock 8, further
including any range there between, although the systems and methods
of the present disclosure are not so limited. In an example, the
thickness of the caprock 8 can vary from about one (1) cm up to
about 1000 m or more, such as between about five (5) cm and 1000 m,
such as between about one (1) m and about 100 m. The caprock 8 can
comprise more than one caprock layer, such that multiple caprocks
can be present which partially or completely cover one another and
can act jointly as a caprock 8 to prevent or reduce upward leakage
of the working fluid from the reservoir 1.
[0066] The reservoir 1 can be one or more natural underground rock
reservoirs capable of containing fluids. For example, the reservoir
1 can be a previously-created manmade reservoir or a portion of a
previously-created manmade reservoir, such as, for example, shale
formations remaining from shale fracturing for hydrocarbon removal.
The reservoir 1 can also be capable of storing carbon dioxide on a
permanent or substantially permanent basis, as this term is
understood in the art. In some examples, the reservoir 1 is
sufficiently porous and permeable to be able to sequester fluids,
such as carbon dioxide, and to receive and retain geothermal heat
6. In contrast to conventional geothermal systems, such as enhanced
geothermal systems using a water-based working fluid, there is no
requirement that the reservoir 1 be a hot dry rock reservoir, as
that term is understood in the art, although, as noted herein, such
a reservoir can optionally be used.
[0067] The reservoir 1 can be sufficiently permeable to allow
multidirectional routes for dispersion or flow of fluid at
relatively high rates, including lateral dispersion or flow. The
caprock 8 above the reservoir 1, if present, can further enhance
the dispersion capabilities of the reservoir 1. In an example, the
porosity of the reservoir 1 can range from between about two (2) %
to about 50% or greater, such as up to about 60%.
[0068] The reservoir 1 can be sufficiently permeable to allow
fluids to flow relatively easily, e.g., at a rate of about 0.1 to
about 50 liters/minute (L/min) or higher, such as up to several
thousand L/min. In an example, the reservoir 1 has a permeability
of about 10.sup.-16 m.sup.2 to about 10.sup.-9 m.sup.2, or greater,
such as up to about 10.sup.-6 m.sup.2.
[0069] In an example, the reservoir 1 has a porosity of at least
about two (2) % and a permeability of at least about 10.sup.-5
m.sup.2, with the caprock 8 having a maximum permeability of about
10.sup.-16 m.sup.2.
[0070] The reservoir 1 can have any suitable natural temperature.
In an example, the natural temperature of the reservoir 1 is at
least about 40.degree. C., although natural temperatures below
40.degree. C. can be sufficient, such as down to 30.degree. C. or
20.degree. C., further including down to 10.degree. C., including
any range there between. The ability to economically recover
geothermal energy from a reservoir 1 having a natural temperature
as low as 10.degree. C., as described below, demonstrates a
substantial advantage of the methane-enhanced geothermal recovery
systems of the present disclosure over systems that use CO.sub.2
alone for geothermal recovery, such as CPG systems described above.
Natural temperatures greater than 90.degree. C. can also be
present, with the highest temperature limited only by the amount of
geothermal heat 6 provided and the ability of the reservoir 1 to
capture and retain the geothermal heat 6. For example, it is
possible that temperatures greater than about 300.degree. C. can be
present in the reservoir 1.
[0071] A specific desired natural temperature can be obtained by
varying the depth of the injection well 14 or the production well
28, or both. In an example, higher natural temperatures can be
obtained by increasing the depth of the injection well 14, with or
without increasing the depth of the production well 28. The overall
size of the reservoir 1 can also vary.
[0072] The geothermal heat 6 can flow at any suitable rate,
including at a high rate as is present in "high geothermal heat
flow regions", as the term is understood in the art. Conventional
water-based systems are known to require high geothermal heat flow
in most instances. As a result, as compared to conventional systems
using water as the working fluid, the systems described herein can
operate in a wider range of locations, including low and moderate
geothermal heat flow regions. The methane-enhanced and waste-heat
enhanced systems of the present disclosure can also operate a wider
range of locations than systems that merely use a CO.sub.2 working
fluid to recover geothermal energy, including at lower heat flow
rates than the CO.sub.2 geothermal-only systems. Also in contrast
to conventional water-based systems which can be operated in areas
containing little natural water (e.g., the American Southwest),
thus requiring importation of water, the novel systems described
herein do not rely on water as the working fluid, and thus do not
import water for use as a working fluid. It is to be understood,
that areas having medium or low geothermal heat flow rates can also
be used.
[0073] In some examples, the CO.sub.2 working fluid from the
CO.sub.2 source 18 can be compressed to an elevated pressure in a
compressor 20. In an example, the compressed CO.sub.2 can be cooled
in a cooling unit 22 because cooling the CO.sub.2 working fluid 12
prior to injection into the injection well 14 can be advantageous
by improving injectability of the CO.sub.2. Most fluids, including
CO.sub.2, are denser when they are cooler than when they are
warmer, such that a relatively cold column of CO.sub.2 in the
injection well 14 can compress itself more than a relatively hot
column of CO.sub.2. Therefore, a relatively cold and relatively low
pressure CO.sub.2 working fluid 12 at the surface can have the same
pressure at the bottom of the injection well 14 as a relatively hot
and relatively high pressure CO.sub.2 working fluid 12 fed to the
injection well 14. A pump (not shown) can optionally be included
downstream of the cooling unit 22 either before the CO.sub.2
working fluid 12 enters the injection well 14 or within the
injection well 14.
[0074] Although the CO.sub.2 from the CO.sub.2 source 18 can, in
some examples, be used "as is," in other examples, further
processing of the CO.sub.2 from the CO.sub.2 source 18 can be
performed prior to introducing the CO.sub.2 to the compressor 20,
the cooling unit 22, or the injection well 14. For example, some
waste streams can require dewatering or drying, or both. In an
example, the CO.sub.2 from the CO.sub.2 source 18 can be stored on
site or off site for a period of time. In an example, the cold
CO.sub.2 that is fed from the cooling unit 22 into the injection
well 14 as the CO.sub.2 working fluid 12 is a saturated liquid or
supercritical CO.sub.2.
[0075] As shown in FIG. 1, the working fluid 12 can pass through
the reservoir 1 in the form of a CO.sub.2 plume 24. The CO.sub.2
working fluid 12 can cause at least a portion of the methane 4
within the reservoir 1 to come out of solution from within the
native fluid 2 where the methane 4 can be carried along with the
CO.sub.2 plume 24. Together, the CO.sub.2 working fluid 12 within
the CO.sub.2 plume 24 and the methane 4 can form a production fluid
26 that can pass through a production well opening 30 of each of
one or more production wells 28. Each production well 28 can carry
the production fluid 26 to or near the surface for energy recovery
within an energy recovery system 32. In some examples, the
production fluid 26 can be sent through a filter system at or near
the surface to reduce or prevent particulate matter from entering
any surface system components, such as those within the energy
recovery system 32.
[0076] As mentioned above, in an example the native fluid 2 can
comprise a brine, such as what can be present in a deep saline
aquifer 1. In an example, a saline aquifer 1 can be present
proximate to a hydrocarbon field such that a portion of the methane
and other gaseous hydrocarbons, such as ethane and propane, can
dissolve into the brine 2 within the aquifer 1. Although many
alkane compounds can dissolve in brine, methane has the highest
solubility compared to higher-order alkanes (e.g., ethane, propane,
butane, etc.). Therefore, while other alkanes can be dissolved into
solution in the brine 2, the present disclosure will describe the
systems and methods herein as being with respect to dissolved
methane. In an example, the composition of methane dissolved in the
brine 2 can be from about 0.1 wt % to about 5 wt %/o methane. Such
a low percentage of methane generally makes the methane, by itself,
uneconomical to mine. For example, the cost to extract dilute
methane dissolved in a saline aquifer would generally be achieved
by pumping the brine to the surface and extracting the methane. The
energy requirement to pump the brine to the surface can cost
considerably more than the actual value of the methane that is
extracted.
[0077] Carbon dioxide is known to have a higher solubility in brine
than methane and other alkanes, such that when the CO.sub.2 working
fluid 12 is injected into the aquifer 1, the CO.sub.2 will
preferentially dissolve into the brine 2 and force at least a
portion of the methane 4 out of solution. The dissolution of the
methane 4 can create a zone of relatively high concentration of
methane in front of the advancing CO.sub.2 plume 24. FIG. 5
(described in more detail below) shows an example of the formation
of a zone 34 that has a high concentration of methane 4 in front of
the CO.sub.2 plume 24. The CO.sub.2 plume 24 can force the
high-concentration zone 34, which can also contain a substantial
percentage of brine or other native fluid 2, through the reservoir
1 and into the one or more production wells 28. In addition, a
portion of the methane 4 that has come out of solution with the
brine 2 can dissolve into the CO.sub.2 phase to form a
CO.sub.2/methane solution plume that is advanced by or combines
with the CO.sub.2 plume 24. As described above, the combination of
the methane 4 that has come out of solution and the CO.sub.2 plume
24 is referred to herein as "production fluid 26," whether the
CO.sub.2 and methane form separate plumes, a gas mixture, or a gas
solution of methane and CO.sub.2. As described in more detail
below, in some examples, the high-concentration methane zone 34 can
also be produced separately from the CO.sub.2 plume 24, such as via
the formation of separate production wells 28A, 28B for each.
[0078] As the production fluid 26 moves through the reservoir 2, it
can become heated by geothermal heat 6 that is present in or is
supplied to the reservoir 120. The geothermal heat 6 can raise the
temperature of one or more components of the production fluid 26,
raise the pressure of one or more components of the production
fluid 26, or both. For example, the geothermal heat 6 can raise the
temperature of the CO.sub.2 working fluid 12, the released methane
4, or both, raise the pressure of the CO.sub.2 working fluid 12,
the released methane 4, or both, or raise both the temperature and
the pressure of the CO.sub.2 working fluid 12 or the released
methane 4, or both, within the production fluid 26. For example,
the temperature of the production fluid 26 as it enters the
production well opening 30 can be higher than the temperature of
the CO.sub.2 working fluid 12 as it exits the injection well
opening 16.
[0079] Upon its release at the injection well reservoir opening 16,
the relatively cool CO.sub.2 working fluid 12 can permeate through
the reservoir 1 forming the CO.sub.2 plume 24. Upon exposure to the
temperatures present in the reservoir 1 (which are higher than the
temperature of the cold CO.sub.2 working fluid 12), the cold
CO.sub.2 working fluid 12 absorbs heat from the reservoir 1, thus
causing an upwardly-migrating CO.sub.2 plume 24, which, in an
example, can be laterally advected due to non-zero groundwater flow
velocities within the reservoir 1. In an example, lateral migration
occurs additionally or alternatively due to the CO.sub.2 plume 24
spreading, as additional CO.sub.2 exits the production well 28. In
an example, the CO.sub.2 working fluid 12, in the form of the
CO.sub.2 plume 24 or the production fluid 26, can form a continuous
or substantially continuous connected stream from the injection
well opening 16 to the production well opening 30.
[0080] The CO.sub.2 plume 24 can migrate, can be transported (such
as in a closed loop system as described herein), or can flow or
spreads towards the production well 28, entering a production well
reservoir opening 30 as a relatively hot production fluid 26, e.g.,
a fluid having a temperature greater than the temperature of the
cold CO.sub.2 working fluid 12 at the injection well opening 16.
The CO.sub.2 plume 24 can move at any suitable rate in a
substantially horizontal manner across the reservoir 1. In an
example, the CO.sub.2 plume 24 can move at a rate of from about 0.1
to about one (1) m per day, inclusive, such as from about 0.4 to
about 0.6 m/day, inclusive, although the systems and methods of the
present disclosure are not so limited.
[0081] In another example, the reservoir 1 can comprise a
hydrocarbon field, such as a reservoir that is part of an oil or
natural gas field. The oil or natural gas reservoir 1 can be
partially depleted by conventional hydrocarbon recovery methods. In
such a case, if the CO.sub.2 working fluid can serve to assist in
oil or hydrocarbon recovery through enhanced oil recovery (EOR). An
EOR system can be set up similar to the system described above for
a brine saline aquifer, e.g., with a CO.sub.2 source 18 providing
the CO.sub.2 working fluid that can be injected into the reservoir
1 using a compressor 20 and, in some examples, a cooling unit 22.
Therefore, FIG. 1 will be used to describe an EOR system as
well.
[0082] In an EOR-type system, methane 4 and other hydrocarbon
gasses can be in a solution within the native fluid 2, such as by
being dissolved or complexed with other hydrocarbons in the native
fluid 2, or the methane 4 can be physically stored within the
reservoir 1, such as within pores of the rock formation that forms
the reservoir 1. The native fluid 2 can also comprise at least one
hydrocarbon to be recovered, such as oil, natural gas, or both. The
CO.sub.2 working fluid 12 can be injected through the one or more
injection wells 14 and into the reservoir 1, where the CO.sub.2
working fluid 12 can interact with the native fluid 2, and in
particular can interact with the at least one hydrocarbon of the
native fluid 2, to form at least one production fluid 26. The
interaction between the CO.sub.2 working fluid 12 and the native
fluid 2 can improve the mobility of the hydrocarbons in the
resulting production fluid 26 to improve extraction of the
hydrocarbons from the reservoir 2. The production fluid 26 can be
pushed toward one or more production wells 28, where it can be
returned at or near the surface.
[0083] In an example, water or other fluids can be injected into
the reservoir in addition to the CO.sub.2 or other non-water based
working fluid 12. For example, a Water Alternating Gas ("WAG")
method can be used where the CO.sub.2 working fluid 12 and a
water-containing working fluid are alternated, with the CO.sub.2
working fluid 12 acting to improve mobility of the hydrocarbons,
and the water-containing working fluid pushing the CO.sub.2 and
hydrocarbon production fluid 26 toward one or more production well
openings 30 and up the one or more production wells 28. Further
description of EOR and WAG is including in National Energy
Technology Laboratory (NETL), "Carbon Dioxide Enhanced Oil
Recovery," (available at
http://www.netl.doe.gov/technologies/oil-gas/publications/EP/small_CO2_eo-
r_primer.pdf) (March 2010) which is incorporated herein by
reference in its entirety.
[0084] In the case of an EOR-type method, the production fluid 26
can include at least a portion of the CO.sub.2 working fluid 12 and
at least a portion of the hydrocarbons that had been part of the
native fluid 2. The production fluid 26 can also include other
native fluids that can be present in the reservoir 1, such as a
brine solution, and other injected fluids, such as a
water-containing working fluid. In an example, the production fluid
26 can include a non-water based working fluid (e.g., CO.sub.2)
content between about 0.01 wt % and about 99 wt %, inclusive, for
example between about 33 wt % and about 50 wt %, inclusive, of the
non-water based working fluid. The production fluid 26 can include
a hydrocarbon content of between about 1 wt % and about 95 wt %,
inclusive, for example between about 25 wt % and about 50 wt %,
inclusive, of hydrocarbons. The production fluid 26 can include a
composition of other fluids, such as brine or an injected
water-containing working fluid, of between about 1 wt % and about
95 wt %, inclusive, for example between about 25 wt % and about 50
wt %, inclusive, of other native fluids or other injected
fluids.
[0085] Depending on the composition of the native fluid in the
reservoir 1 and the specifics of the particular EOR operation, the
production fluid 26 can have a "high" percentage of CO.sub.2 from
the working fluid, e.g., between about 66 wt % and about 99 wt %
CO.sub.2, inclusive, a "low" percentage of CO.sub.2 from the
working fluid, e.g., between 1 wt % and about 33 wt % CO.sub.2,
inclusive, or any range of CO.sub.2 content in between, such as a
"medium" percentage of the CO.sub.2 working fluid, e.g., between
about 33 wt % and about 66 wt % CO.sub.2, inclusive. In some
examples, the percentage of CO.sub.2 in the production fluid can be
very low, such as from 1 wt % to 9 wt %, inclusive, for example
from 2 wt % to 5 wt %, inclusive.
[0086] In the case of a CO.sub.2 working fluid 12, the CO.sub.2 can
be partially or fully miscible with the hydrocarbons so that the
CO.sub.2 working fluid 12 and the hydrocarbons form a homogenous or
substantially homogenous solution of CO.sub.2 and hydrocarbon.
Alternatively, the CO.sub.2 working fluid 12 can be fully or
substantially immiscible so that the CO.sub.2 only partially
dissolves, or substantially does not dissolve in the hydrocarbons
so that the CO.sub.2 and the hydrocarbons in the production fluid
141 are produced as separate immiscible or substantially immiscible
fluids. The CO.sub.2 can mix with the hydrocarbons and can provide
for at least one of reduced viscosity of the hydrocarbons, reduced
surface tension of the hydrocarbons, increased mobility of the
hydrocarbons, or increased fluid pressure in the reservoir 1 so
that the hydrocarbons can more easily separate from the rock
formation of the reservoir 1 or be more easily driven toward the
production well opening 30, or both.
[0087] The production fluid 26 can be carried up through the
reservoir 2, such as by or in conjunction with a CO.sub.2 plume 24.
The production fluid 26 can also be formed as a zone of mobilized
hydrocarbons and CO.sub.2 that can be similar to a plume, but not
necessarily. In an example where a water-containing working fluid
is used, such as in a WAG process (described above), the one or
more production fluids 26 can include alternating zones of
mobilized hydrocarbons with CO.sub.2 and zones of water-containing
working fluid. As the production fluid 26 moves through the
reservoir 2, it can become heated by geothermal heat 6 that is
present in or is supplied to the reservoir 1. The geothermal heat 6
can raise the temperature of one or more components of the
production fluid 26, raise the pressure of one or more components
of the production fluid 26, or both. For example, the geothermal
heat 6 can raise the temperature of at least one of the CO.sub.2
working fluid 12, the methane 4 released from the native fluid 2,
or other hydrocarbons released from the native fluid 2, raise the
pressure of at least one of the CO.sub.2 working fluid 12, the
methane 4 released from the native fluid 2, or other hydrocarbons
released from the native fluid 2, or raise both the temperature and
the pressure of at least one of the CO.sub.2 working fluid 12, the
methane 4 released from the native fluid 2, or other hydrocarbons
released from the native fluid 2. For example, the temperature of
the production fluid 26 as it enters the production well opening 30
can be higher than the temperature of the CO.sub.2 working fluid 12
as it exits the injection well opening 16.
[0088] The dissolving of at least a portion of the CO.sub.2 working
fluid 12 into a brine working fluid 2 can provide for CO.sub.2
sequestering, e.g., to store CO.sub.2 that has been produced in a
power plant, a biofuel plant, or an industrial plant in order to
reduce CO.sub.2 emissions into the atmosphere. Similarly, a portion
of the CO.sub.2 working fluid 12 can be sequestered into an oil or
hydrocarbon reservoir 1 when the CO.sub.2 working fluid 12 is being
used for EOR.
[0089] Whether the native fluid 2 comprises a fluid with dissolved
methane, such as a brine, or a hydrocarbon fluid, such as oil or
natural gas in an EOR field, the production fluid 26 can be brought
to the surface via the one or more production wells 28 so that
energy can be recovered via an energy recovery system 32. In an
example, shown in FIG. 1, the energy recovery system 32 can
comprise an expansion device 36. The expansion device 36 can
provide shaft power 38 to a generator 40, which in turn can
generate electricity 42. Because the expansion device 36 in FIG. 1
is being directly driven by the production fluid 26 that is being
heated by the geothermal heat 6, the system of FIG. 1 can be
referred to as a direct expansion device system, or more commonly a
direct turbine system.
[0090] The system 10 can include a pump or compressor (not shown)
at the surface, e.g., essentially immediately downstream of the
production well 28, and upstream of the energy recovery system 32,
in order to boost the pressure of the production fluid 26. The
increased pressure from this pump or compressor can allow the
production fluid 26 to effectively and efficiently produce power
when the production fluid 36 is run through the expansion device
36. A pump or compressor in this location, e.g. upstream of the
energy recovery system 26, can be particular effective for a
reservoir 1 comprising a saline aquifer with native CO.sub.2 in the
native fluid 2, because the production fluid 26 can be produced at
pressures that are too low to cost-effectively produce electricity
42 from the expansion device 36 and the generator 40. Waste heat
off this pump or compressor can be harvested, as described in more
detail below, for supplementing power production. Alternatively, a
pump or compressor can be added to the system essentially
immediately upstream of the injection well 14 before reinjection
the CO.sub.2 into the reservoir 1 as part of the working fluid
12.
[0091] The expansion device 36 can comprise any suitable type of
expansion device 36 known in the art, such as a turbine, although
the present disclosure is not so limited. In contrast to
conventional water-based geothermal systems which produce low
pressure steam at high volumetric flow rates, the use of a
conventional turbine in higher pressure CO.sub.2 geothermal energy
systems and methods described herein, is an option, rather than a
requirement
[0092] In an example, the expansion device 36 comprises one or more
piston-cylinder devices. The expansion device 36 can be one or more
scroll, screw or rotary compressors designed to run in reverse as
engines. The expansion device 36 can comprise a single expansion
device 36, or a plurality of expansion devices 36. Multiple
expansion devices 36 can run in parallel, with one or more first
expansion devices 36 running pumps or compressors directly and one
or more second expansion devices 36 producing electric power for
sale. The generator 40 can be any suitable generator known in the
art, to produce electricity 42. In an example, the components of
the production fluid 26 can comprise primarily or substantially all
of lower density gases so that the expansion device 36 can be a
direct turbine. Relatively low-density gaseous or supercritical
fluids can provide relatively higher energy efficiency, and thus
produce relatively more energy in the form of electricity, than
higher density fluids in liquid phase when decreasing between the
same pressure levels. Passing a low density fluid, such as CO.sub.2
and methane, through a direct turbine generally can produce more
electricity than extracting thermal energy to operate an Organic
Rankine Cycle or other binary system, and then decreasing the
pressure through a valve or turbine, when operating between the
same inlet and exit conditions.
[0093] As described above, the native fluid 2 in the reservoir 2
can comprise methane 4, such as methane 4 within solution in the
native fluid 2. As further described above, the injection of the
CO.sub.2 working fluid 12 can cause at least a portion of the
methane 4 to come out of solution with the native fluid 2 and be
brought up to the surface with the CO.sub.2 working fluid 12 as a
production fluid 26. The system and method of the present
disclosure can be configured to take advantage of the methane 4
that is produced to the surface in order to improve the efficiency
of the geothermal energy recovery by recovering another form of
energy from the reservoir 1--namely, a portion of the chemical
energy stored in the methane 4.
[0094] As shown in FIG. 1, the system 10 can include a separation
system 44 that can be configured to separate a portion 46 of the
methane from a production fluid comprising CO.sub.2 and methane.
The separated methane 46 can be combusted to increase the
temperature of the production fluid 26, the pressure of the
production fluid 26, or both. In an example, at least a portion of
the separated methane 46 can be fed into a heater 48 that can heat
the production fluid 26, or increase the pressure of the production
fluid 26, or both, to form a heated and/or pressurized production
fluid 50.
[0095] After combustion in the heater 48, the methane 46 is
converted into CO.sub.2 and water vapor in an exhaust stream 56. In
an example, at least a portion of the CO.sub.2 in the exhaust
stream 56 can be captured by a CO.sub.2 capture system 58. In an
example, the CO.sub.2 capture system 58 can comprise an absorber
through which an absorbing material can flow, such as an absorbing
solution comprising one or more amines, and a regenerator that can
strip CO.sub.2 from the amine solution. The outputs from the
CO.sub.2 capture system 58 can include a CO.sub.2-rich stream 60
and a vented gas 62 (e.g., water vapor and other non-absorbed
compounds). If desired, the vented gas 62 can be further treated.
The CO.sub.2 output stream 60 can be fed back into the reservoir 1,
such as by compressing the CO.sub.2 output stream 60 in a
compressor, which can be the same compressor 20 as is used to
compress the CO.sub.2 from the CO.sub.2 source 18, as shown in FIG.
1, or it can be a different compressor.
[0096] In another example, rather than heating the production fluid
26 with a heater 48, the separated methane 46 can be combusted in a
conventional gas turbine or gas engine (not shown) to produce
electricity from the turbine or engine. The combustion of the
methane 46 in the gas turbine or the engine can produce substantial
waste heat in the form of hot combustion gases (e.g., CO.sub.2 and
steam) and hot engine or turbine cooling jacket fluid. The waste
heat can be added to the production fluid 26, such as via a heat
exchanger. This configuration can, in some cases, lead to higher
energy conversion efficiency then directly heating the production
fluid 26 in a heater 48.
[0097] In some examples, a portion of the separated methane 46 can
be split off from the methane stream 46 and stored or sold as a
methane product 47. However, in some situations, it may be
inefficient or uneconomical to sell a portion of the separated
methane 46 rather than combusting all of the methane 46 to boost
the temperature or pressure of a working fluid or production fluid.
The reason for this is because the most likely end point for sold
methane is a natural gas power plant where it will be burned to
produce electricity. As described above, the separated methane 46
combusted in the heater 48 is used to heat a working fluid or
production fluid, which in turn can be sent through an energy
recovery system 32 to generate electricity 42. However, the sold
methane 47 can lose some economic efficiency due to transportation
costs to bring the methane 47 to the outside power plant. Burning
methane in a power plant can also be less efficient than the energy
recovery system 32 because power plants do not also incorporate
geothermal energy recovery. Moreover, natural gas power plants
typically employ steam turbines, which can be considerably less
efficient than direct turbines using supercritical CO.sub.2 as the
working fluid or CO.sub.2 and methane as a production fluid. In
addition, the majority of natural gas power plants are not equipped
for CO.sub.2 capture so that the methane 47 delivered to these
power plants will likely contribute to CO.sub.2 emissions. In
contrast, the energy recovery systems 32 of the present disclosure
can also be configured with a CO.sub.2 capture system 58, as
described above, to capture any CO.sub.2 formed by the heater 48.
Thus, the systems of the present disclosure can provide for reduced
CO.sub.2 emissions to the atmosphere. Even if the outside power
plant were to have CO.sub.2 capturing capabilities, the systems and
methods of the present disclosure can provide for more efficient
reduction of emissions because the CO.sub.2 capture system and
geologic storage of CO.sub.2 can be co-located with the geothermal
energy recovery system, reducing or eliminating the need for
transportation systems necessary to reduce or prevent emissions
from natural gas power plants.
[0098] The heater 48 can be positioned upstream of the expansion
device 36, as shown in FIG. 1, so that the heated and/or
pressurized production fluid 50 is formed prior to the production
fluid 50 being fed into the expansion device 36. After passing
through the expansion device 36, the heated and/or pressurized
production fluid 50 can become a slightly cooled production fluid
52.
[0099] In some examples, the separation system 44 can cool or
depressurize the production fluid in order to achieve the
separation of the methane 46 (described in more detail below).
Therefore, in an example, the methane separation system 44 is
downstream of the expansion device 36 such that the cooled
production fluid 52 is fed into the separation system 44. By
separating the methane 46 from the production fluid 52 downstream
of the expansion device 36, the system can prevent or reduce the
loss of geothermal energy during the separation of the methane 46
from the production fluid 52.
[0100] In an example, the methane separation system 44 can comprise
one or more membranes that are configured to selectively allow the
passage of one or more components within the production fluid 52
through the membrane while preventing or impeding the passage of
one or more other components within the production fluid 52 through
the membrane. For example, the membrane can be selectively
permeable between CO.sub.2 and methane, so that the CO.sub.2 can
pass substantially unimpeded through the membrane, while a portion
of the methane 46 is prevented from passing through the membrane,
or vice versa. In an example, the pressure difference across the
membrane can be controlled, which can control the percentage of
methane that can be removed from the production fluid 52 in order
to control the amount of methane in the separated methane stream
46.
[0101] It has been found that even if only a small percentage of
the methane is separated from the production fluid can provide for
substantial increases in energy recovery from the energy recovery
system 32. In an example, the production fluid contains about 5 wt
% methane, and about 10 wt % to about 30 wt % of this can be
separated out and combusted, which can provide for an increase in
the production of electricity 42 of from about 75% to 1000% above
the electricity that can be produced from the geothermal energy
collected by the production fluid alone. Moreover, separating only
a small portion of the methane from the production fluid can ensure
that a substantial amount of methane is still present in the
production fluid before it is re-injected back into the reservoir 1
(described in more detail below). The presence of methane in the
re-injected production fluid can ensure that methane is present in
the reservoir to be extracted over time such that there is a
generally always a portion of methane that can be brought to the
surface with the production fluid 26.
[0102] The use of the separated methane 46 can allow for
economically viable geothermal energy recovery from reservoirs
having lower temperatures than can be achieved through simply
extracting the thermal energy from the production fluid 26. For
example, a CO.sub.2 plume 24 is used to collect geothermal energy,
with no combustion of produced methane or any other heat-recovery
methods (such as those described below), the recovery of geothermal
energy from the reservoir may only be economically efficient at
temperatures down to between about 30.degree. C. and about
50.degree. C., and in most cases only down to about 60.degree. C.
However, with the use of the methane separation system 44 and the
methane combustion heater 48, economically viable recovery of
geothermal energy can be achieved down to a reservoir temperature
of about 10.degree. C. to about 25.degree. C., depending on the
percentage of methane that can be produced from the reservoir 1,
the reservoir depth and temperature, and the local ambient
temperature.
[0103] As noted above, the system 10 of the present disclosure can
be used for geothermal energy capture, as described herein, and can
also be used for sequestering CO.sub.2 within the rock formation or
native fluid 2 within the reservoir 1. Therefore, in some examples,
at least a portion of the CO.sub.2 working fluid 12 can be stored
permanently or semi-permanently within the reservoir 1, such that a
replacement supply of CO.sub.2 can be required in order to continue
operation of the system. The capture of the CO.sub.2 output stream
60 from the exhaust stream 56 can provide for a substantial portion
of the make-up CO.sub.2 required. In an example, the CO.sub.2
output stream 60 from the CO.sub.2 capture system 58 can provide
all or substantially all of the CO.sub.2 required to make up for
CO.sub.2 that is sequestered within the reservoir 1. FIGS. 2-4 show
examples of indirect energy recovery systems that can be used for
the purpose of recovering energy from the production fluid 26. Each
of FIGS. 2-4 shows the production fluid 26 being passed through a
heat exchanger 62 in order to heat a secondary working fluid 64.
The secondary working fluid 64 can be sent through one or more
energy conversion devices. The systems of FIGS. 2-4 are often
referred to as "binary systems" because they use two working
fluids, rather than one.
[0104] FIG. 2 shows an example energy recovery system 66 where a
portion of the energy from the secondary working fluid 64 is drawn
off as heat 68. The heat 68 can be used in any suitable direct-use
applications, such as space heating. The secondary working fluid 64
can then be sent through an expansion device 70 to produce shaft
power 72 that can be provided to the compressor 20 for compressing
the CO.sub.2 from the CO.sub.2 source 18 or the CO.sub.2 output
stream 60, or both. After passing through the expansion device 70,
the additional heat 68 can be extracted for the direct-use heat
applications. The secondary working fluid 64 can be cooled in a
secondary cooling unit 74 before sending the secondary working
fluid 64 back into the heat exchanger 62 in order to complete the
cycle of the secondary working fluid 64.
[0105] FIG. 3 shows another example energy recovery system 78 where
both heat 80, e.g., for a direct-use application, and electricity
82 can be generated from the secondary working fluid 64. In the
example of FIG. 3, the working fluid 64 can be passed through an
expansion device 84, similar to the expansion device 70 in FIG. 2,
where at least a first portion of the shaft power 86A from the
expansion device 84 is used to drive a generator 88 to produce the
electricity 82. A second portion of the shaft power 86B from the
expansion device 84 can be used to assist in driving the compressor
20.
[0106] FIG. 4 shows another example energy recovery system 92,
where a portion of the energy in the secondary working fluid 64 can
be recovered as electricity 90 in a method similar to that
described above with respect to FIG. 3, and another portion of the
energy from the secondary working fluid 64 can be provided as heat
to a separate power cycle 94 having components as understood in the
art, such as a Rankine power cycle, an Organic Rankine Cycle (ORC),
or a Kalina Cycle. With a separate power cycle 94, the condensing
pressure can be subcritical and the highest pressure during the
heat addition can be either supercritical or subcritical.
[0107] Each of the binary systems 66, 78, 92 of FIGS. 2-4 can
provide for separation and combustion of a portion of the methane
within the production fluid 26 in order to supplement energy
recovery from the reservoir 1. For example, in FIG. 2, after the
production fluid 26 is passed through the heat exchanger 64, the
production fluid can be passed through a methane separation system
96 that can be similar to the methane separation system 44
described above with respect to FIG. 1. The methane separation
system 96 can separate off a portion 98 of the methane within the
production fluid, which can be supplied to a combustion heater 100.
In an example, the combustion heater 100 can be configured to heat
the circulating secondary working fluid 64 before it enters the
expansion device 70. In the example shown in FIG. 2, the heat 68 is
drawn off of the secondary working fluid 64 after heating the
secondary working fluid 64 with the methane combustion heater 100
and after passing the secondary working fluid 64 through the
expansion device 70. However, the system is not so limited, and the
heat 68 can be drawn off from the secondary working fluid 64 before
heating with the methane combustion heater 100 or before passing
the secondary working fluid 64 through the expansion device 70.
[0108] In the example of FIG. 3, the separated methane 98 from the
separation system 96 can be fed to a heater 102 that is configured
to heat the production fluid 26 before it is fed into the heat
exchanger 62. FIG. 4 shows an example where both the production
fluid 26 before the heat exchanger 62 and the secondary working
fluid 64 before the expansion device 84 are heated with combusted
methane 98 separated with a methane separation system 96. In the
example shown in FIG. 4, a first combustion heater 104 is supplied
with a first portion 98A of the separated methane to heat the
production fluid 26, and a second combustion heater 106 is supplied
with a second portion 98B of the separated methane to heat the
secondary working fluid 64. In another example (not shown), both
the production fluid 26 and the secondary working fluid 64 can be
heated with a single, common combustion heater.
[0109] As with the heater 48 in FIG. 1, the exhaust gas from each
of the heaters 100, 102, 104, and 106 can be sent through a
CO.sub.2 capture system in order to capture the CO.sub.2 from the
combustion of the methane 98 in order to inject the separated
CO.sub.2 into the reservoir 1. CO.sub.2 capture and recirculation
to the compressor is not shown in FIGS. 2-4, but a person of
ordinary skill in the art will understand that a CO.sub.2 capture
system can be implemented.
[0110] The methane separation system 44, 96 can separate the
methane stream 46, 98, as described above, and can leave a final
production fluid 108 that can comprise CO.sub.2 and methane. The
final production fluid 108 can also include other compounds, such
as oil and gas compounds from an EOR reservoir or entrained brine
solution from a saline aquifer, that can be further separated from
the final production fluid 108 and sold as separate products, or
the other compounds can be injected back into the reservoir 1 or
into another reservoir. In an example, further cooling of the final
production fluid 108 can be needed such that the final production
fluid 108 is sent through a cooling unit, such as a cooling tower
to further cool the production fluid before re-injecting the
production fluid back into the reservoir. In an example, the final
production fluid 108 can be cooled with the same cooling unit 22
that can cool compressed CO.sub.2 coming of the compressor 20. The
systems of FIGS. 2-4 can include a pump (not shown) can optionally
be included downstream of the cooling unit 22 either before the
CO.sub.2 working fluid 12 enters the injection well 14 or within
the injection well 14.
[0111] Alternatively, the other compounds, such as oil and gas
compounds or brine solution, can be separated from the production
fluid 26 after it is produced from the production well 28 but
before the energy recovery system 32, 66, 78, 92. In such a case,
the production fluid 26 can be separated into various component
streams, such as a CO.sub.2 and methane stream, a hydrocarbon
stream, and a brine stream. Each of the components streams will
include geothermal heat extracted from the reservoir 1. Therefore,
thermal energy can be extracted from each stream with a separate
energy recovery system, such as an expansion device and generator,
as described above with respect to FIG. 1, or as a binary system,
as described above with respect to FIGS. 2-4. The energy recovery
system that is employed for each stream can therefore be tailored
to the particular characteristics of the stream. For example, for a
CO.sub.2 and methane stream, a direct turbine system can be
appropriate because it is generally the most efficient for
low-density, supercritical or gaseous working fluids. In contrast,
for a hydrocarbon stream or a brine stream, a binary system may be
more appropriate and efficient. Therefore, in the case where the
production fluid 26 comprises multiple compounds that are to be
separated, the energy recovery system can be design to be the most
economically efficient for each particular stream.
[0112] The physical and thermodynamic properties of CO.sub.2 and
methane, which can be the two primary components in the production
fluid 26, can allow for the final production fluid 108 to be
re-injected into the reservoir 1 via the injection well 14 without
the need for an injection pump. In other words, the system 10 can
be configured so that the CO.sub.2 working fluid 12/production
fluid 26, 108 can form a thermosiphon as it circulates through the
reservoir 1, to the surface via the production well 28, through the
energy recovery system 32, 66, 78, 92, and back into the injection
well 14.
[0113] In the case of CO.sub.2 and methane, a thermosiphon can be
formed due to the expansion properties of the gases as they are
heated in the reservoir 1. In an example, a relatively cold and
compressed CO.sub.2 working fluid 12 (which can include methane
within the re-injected final production fluid 108) is injected into
the injection well 14, forming a long column of cold fluid. As the
depth into the well is increased, the fluid at a particular point
within the injection well becomes more and more compressed, until
the CO.sub.2 working fluid exits the injection well 14 as a heavy,
dense fluid from the injection well opening 16. As described above,
at least a portion of the CO.sub.2 working fluid 12 can form a
CO.sub.2 plume 24 (which can include re-injected methane,
un-dissolved methane 4, and other compounds from the native fluid
2). The CO.sub.2 plume 24 can form a connected link between the
injection well opening 16 and the production well opening 30. As
the CO.sub.2 plume 24 moves through the reservoir 1, it can be
heated by the geothermal heat 6 within or flowing into the
reservoir 1. Both CO.sub.2 and methane expand substantially as they
are heated, e.g., on the order of about a 100% expansion per
100.degree. C. for CO.sub.2 and about a 20% expansion per
50.degree. C. for methane.
[0114] The limited space in the reservoir 1 for expansion can cause
the CO.sub.2 plume 24 to become more and more compressed as it
moves through the reservoir 1 from the injection well 14 to the
production well 28. This effect can partially offset the pressure
loss due to Darcy flow as the CO.sub.2, methane, and other fluids
move through the reservoir. Therefore, once the CO.sub.2 plume 24
reaches the production well opening 30 as the production fluid 26,
it is a relatively hot relative to the CO.sub.2 working fluid 12 at
the injection well opening 16, and has a pressure loss between the
injection well opening 16 and the production well opening 30 that
is smaller than would be expected from an identical reservoir using
other working fluids, such as water or brine. As the production
fluid 26 moves up the production well 28, it expands or becomes
less dense (e.g., because there is less and less gas on top of the
production fluid 26 as it moves up the production well 28), but
still is at a relatively hot temperature and a relatively high
pressure. In an example, the production fluid 26 expands less as it
moves up the production well 28 than the CO.sub.2 working fluid 12
compresses as it moves down the injection well 14.
[0115] The injection well 14, production well 28, and the various
components of the energy recovery system 32, 66, 78, 92 can be
configured so that a thermosiphon can form between the production
well 28 and the injection well 14 so that the final production
fluid 108 can be re-injected into the injection well 14 without the
use of a separate pump (as shown in FIG. 1, where the final
production fluid 108 can be re-injected into the injection well 14
immediately after the cooling unit 22, without needing to use the
compressor 20). In some examples, the system parameters that can be
adjusted to provide for a thermosiphon can include the size or
diameter of the wells 14, 28, which can determine the frictional
losses as the CO.sub.2 working fluid 12 and production fluid 26
flow through the injection well 14 and production well 28, and the
pressure drop across the equipment through which the production
fluid 26 flows, particularly the expansion device 32 in a direct
turbine system or the heat exchanger 62 in a binary system.
[0116] A thermosiphon or thermosiphon-like system, as described
above, can provide efficiency advantages over systems using other
working fluids. For example, the formation of a CO.sub.2 and/or
methane thermosiphon can reduce or minimize parasitic power loses,
such as those that can occur due to fluid injection or production
pumps. Such parasitic power loses from pumps or compressors can
account for as much as 30% or more of the gross power generated in
geothermal systems using other working fluids, such as a
water-based geothermal recovery system. The ability to provide for
a thermosiphon can be a particular advantage for a CO.sub.2 working
fluid 12 and the methane that can be included in the production
fluid 26 over other working fluids, particularly water-based
geothermal systems where a thermosiphon is impossible, practically
speaking.
[0117] The presence of a pump or compressor essentially immediately
downstream of the production well 28, as described above, does not
prevent the function of a thermosiphon or thermosiphon-like
operation of the system. Rather, the pump or compressor can merely
improve efficiency of the power production in the energy recovery
system 32, 66, 78, 92. A pump or compressor upstream of the energy
recovery system 32, 66, 78, 92 can be desirable when the produced
CO.sub.2 temperature is very low, e.g., temperatures that are far
lower than conventional geothermal can economically support, such
as temperatures less than about 75.degree. C.). The pump or
compressor may be economically viable when supplemental heat,
either waste heat or heat from combusted fuel, is added to the
production fluid 26 between the upstream pump or compressor and
energy recovery system 32, 66, 78, 92.
[0118] The residual saturation of the brine native fluid 2 in the
reservoir 1 can affect the lifespan of methane production from the
system. As used herein, the term "residual saturation" can refer to
the fraction of the reservoir pore space that remains occupied by
the brine or water native fluid 2 after the CO.sub.2 working fluid
12 is injected into the reservoir 1 to form the CO.sub.2 plume 24.
The residual brine or water native fluid 2 can include dissolved
methane 4, and this methane 4 can diffuse out of solution over time
and be carried or pushed by the CO.sub.2 plume 24. The residual
water or brine native fluid 2 can also prevent circulation of the
CO.sub.2 working fluid 12 through the portions of the reservoir 1
that are occupied by the residual native fluid 2 while still
permitting exchange of geothermal heat 6 from the reservoir 1 and
residual native fluid 2 to the CO.sub.2 working fluid 12. Thus, the
residual saturation of the brine native fluid 2 can, in practice,
increase the percentage of the reservoir 1 that is occupied by a
given volume of the CO.sub.2 working fluid 12. Therefore, the
residual native fluid 2 can, in essence, increase the volume of the
rock formation in the reservoir 1 that is contacted by the CO.sub.2
working fluid 12, which in turn can increase the amount of
geothermal energy that can be captured by the CO.sub.2 working
fluid 12. Moreover, the methane 4 that is released from solution
from the residual brine or water means that the reservoir 1 can
continue to produce methane while increasing the volume of the rock
formation that is contacted by the CO.sub.2 working fluid 12, thus
increasing the methane production and the geothermal energy
recovery efficiency of the system. For this reason, residual
saturation can provide a substantial feature of the
methane-enhanced systems of the present disclosure.
[0119] As described above, when the CO.sub.2 working fluid 12 is
injected into the reservoir 1 where methane 4 and other alkanes are
in a solution in the native fluid 2, the CO.sub.2 can cause a
portion of the methane 4 to come out of solution where the methane
can interact with the advancing CO.sub.2 plume 24. The release of
the methane 4 from the solution can result in the formation of a
zone of high methane concentration in front of the advancing
CO.sub.2 plume 24. FIG. 5 shows a conceptual view of such a
high-concentration methane zone 34 in front of the advancing
CO.sub.2 plume 24. A portion of the released methane 4 can dissolve
within or mix with the CO.sub.2 plume 24, however, the
high-concentration zone 34 can include more methane by weight %
than is present in the CO.sub.2 plume 24. In an example, in order
to maximize methane extraction from the reservoir 1, the production
wells 28 can be configured to include one or more first production
wells 28A that are located relatively close to the injection well
14 and one or more second production wells 28B that are located
further from the injection well 14. In the example shown in FIG. 5,
the first production wells 28A so that the production well openings
30A (shown as horizontal production wells 28A in FIG. 5) are
located within the CO.sub.2 plume 24 that includes CO.sub.2 and
methane that is mixed with or dissolved into the CO.sub.2. The
second production wells 28B can be positioned so that the
production well openings 30B (shown as vertical production wells
28B in FIG. 5) are within the high-concentration methane zone
34.
[0120] The first production wells 28A, which can also be referred
to herein as "CO.sub.2 production wells 28A," can include a
production fluid comprising CO.sub.2 and a small portion of
methane. The production fluid from the CO.sub.2 production wells
28A can be processed in substantially the same manners as described
above with respect to the production fluid 26 in FIGS. 1-4, e.g.,
by separating off at least a portion of the methane present in the
production fluid to supplement the geothermal energy absorbed by
the production fluid prior to sending the production fluid to an
energy recovery system.
[0121] The second production wells 28B, which can also be referred
to herein as "methane production wells 28B," can produce a
combination of methane and brine solution from the reservoir 1. The
production fluid from the methane production wells 28B can also
include some CO.sub.2 and, in some examples, other native fluids,
such as hydrocarbons from an EOR reservoir. Because the openings
30B to the methane production wells 28B are designed to be within
the high-concentration methane zone 34 within the reservoir 1, the
produced fluid from the methane production wells is expected to be
primarily methane, with brine solution also comprising a sizable
portion of the production fluid.
[0122] The separate recovery of the production fluid from the
CO.sub.2 plume 24 (primary CO.sub.2 with a small portion of
methane) from the CO.sub.2 production wells 28A and from the
high-concentration methane zone 34 (primarily methane with a small
portion of brine) from the methane production wells 28B can provide
for more controlled extraction of methane and CO.sub.2 and for
maximum methane extraction from the reservoir 1. However, as will
be appreciated by a person of ordinary skill in the art, as the
CO.sub.2 plume 24 expands within the reservoir 1, the
high-concentration methane zone 34 can move past the methane
production wells 28B. Therefore, a staged approach for the
placement and drilling of the production wells 28 can be used to
continue to provide for the separate production of CO.sub.2 from
CO.sub.2 production wells 28A and of methane from methane
production wells 28B.
[0123] FIG. 6 is a map view showing an example well placement for a
staged production using separate CO.sub.2 production wells and
methane production wells. As shown in the example of FIG. 6, an
initial injection well 114 is drilled in a generally central
location within a field 110. A set of initial arc production wells
can be drilled on either side of the injection well 114. In an
example, each set of production wells can include a first, CO.sub.2
production well 116A, and a second, methane production well 116B.
In an example, at the start up of the system, only the injection
well 114, CO.sub.2 production wells 116A, and methane production
wells 116B are drilled.
[0124] A CO.sub.2 working fluid can be injected into the injection
well 114, as described above, so that a CO.sub.2 plume forms within
the underground reservoir. As further described above, the CO.sub.2
working fluid can cause methane to come out of solution such that a
zone of high methane concentration forms in front of the CO.sub.2
plume. The CO.sub.2 production wells 116A can be positioned
relative to the injection well 114 so that a CO.sub.2 production
well opening is located within the CO.sub.2 plume during an initial
operating period after start up. The methane production wells 116B
can be positioned relative to the injection well 114 so that a
methane production well opening is located within the zone of high
methane concentration during an initial operating period after
start up. In an example, the CO.sub.2 production wells 116A are
spaced from the injection well 114 at about 100 m to about 2000 m.
Each methane production well 116B can be spaced another 10 m to
about 1000 m from a corresponding CO.sub.2 production well
116A.
[0125] As the CO.sub.2 working fluid is added to the reservoir from
a CO.sub.2 source, from circulating CO.sub.2, or from CO.sub.2
capture off the methane combustion heater, the CO.sub.2 plume will
grow over time. After an initial operating period, the CO.sub.2
plume will reach the methane production wells 116B and the zone of
high methane concentration will be pushed beyond the first methane
production wells 116B. At such time, a second set of production
wells can be drilled, such as a second pair of arc CO.sub.2
production wells 118A and a second pair of arc methane production
wells 118B. In the example shown in FIG. 6, the first set of
production wells (e.g., CO.sub.2 production wells 116A and methane
production wells 116B) can be positioned along a first axis with
respect to the injection well 114 (e.g., east to west through the
injection well 114, as shown in FIG. 6). The second set of
production wells (e.g., CO.sub.2 production wells 118A and methane
production wells 118B) can be positioned along a second axis with
respect to the injection well 114, wherein the second axis can be
generally perpendicular to the first axis (e.g., north to south
through the injection well 114, as shown in FIG. 6). The additional
production wells 118A, 118B and larger CO.sub.2 plume can support a
larger CO.sub.2 circulation rate through the reservoir. One or more
additional injection wells 120 can be drilled to accommodate the
additional CO.sub.2 circulation. In an example, the added injection
wells 120 can be positioned along the second axis relative to the
initial injection well 114. The added injection wells 120 can be
spaced from the initial injection well 114 with approximately the
same spacing as the CO.sub.2 production wells 116A are spaced from
the injection well 114, e.g., at about 100 m to about 2000 m.
Similarly, the second CO.sub.2 production wells 118A can be spaced
from the added injection wells 120 with approximately the same
spacing, e.g., at about 100 m to about 2000 m, with the second
methane production wells 118B being spaced from the CO.sub.2
production wells 118A at about 10 m to about 1000 m.
[0126] As the CO.sub.2 plume continues to grow, the CO.sub.2 plume
can reach the methane production wells 118B such that additional
production wells may be drilled. For example, a third set of
production wells, such as third CO.sub.2 production wells 122A and
third methane production wells 122B can be drilled. In an example,
the third production wells (e.g., CO.sub.2 production wells 122A
and methane production wells 122B) can be positioned along the
first axis (e.g., the same axis as the first production wells 118A,
118B), or can be positioned along another axis with respect to the
injection well 114. In an example, each third CO.sub.2 production
well 122A can be spaced from a corresponding first CO.sub.2
production well 116A by approximately the same spacing as the first
CO.sub.2 production well 116A is spaced from the injection well
114, e.g., at about 100 m to about 2000 m. Each third methane
production well 122B can be spaced from a corresponding third
CO.sub.2 production well 122A at about 10 m to about 1000 m.
[0127] As noted above, the primary components from the methane
production wells 28B, 116B, 118B are expected to be methane and
brine solution, which will generally be in separate phases at the
surface (e.g., gaseous methane and liquid brine solution).
Therefore, separation of methane from the production fluid of the
methane production wells 28B, 116B, 118B can be relatively easy and
inexpensive. A portion of the methane from the methane production
wells 28B, 116B, 118B can be added to the combustion heater, along
with any methane separated from the CO.sub.2 production wells 28A,
116A, 118A, to supplement the geothermal energy recovered by an
energy recovery system. A portion of the methane from the methane
production wells 28B, 116B, 118B can also be stored or re-injected
into the reservoir to ensure methane availability over the lifespan
of the reservoir, wherein the re-injected methane can later be
produced with CO.sub.2, separated, and combusted to supplement
geothermal energy recovery from the reservoir.
[0128] Any CO.sub.2 that is produced from the methane production
wells 28B, 116B, 118B can be sent through the energy recovery
system, if the temperature and/or pressure of the CO.sub.2 from the
methane production wells 28B, 116B, 118B is sufficiently high.
Alternatively, the CO.sub.2 produced form the methane production
wells 28B, 116B, 118B can be compressed, such as in compressor 20,
and injected into the injection wells 14, 114, 120 along with the
CO.sub.2 working fluid 12.
[0129] Any brine or other liquid produced from either the CO.sub.2
production wells 28A, 116A, 118A or the methane production wells
28B, 116B, 118B can be processed with an energy recovery device,
such as an expansion device, a binary energy recovery system, or a
heat exchanger, to recover geothermal energy that has been absorbed
by the brine or other liquids. In most examples, unless the brine
has a sufficiently high temperature, heat can be recovered from a
brine solution only through a binary power system, such as an
organic Rankine cycle (ORC) or a Kalina cycle. If the temperature
of the brine solution is at least about 165.degree. C., and
preferably at least about 200.degree. C., then a direct flash or
dual-flash power system can be employed. In certain examples, it
may be desirable to combust a portion of the methane extracted from
the reservoir 1 in order to boost the temperature of the brine
solution in addition to increasing the temperature and/or the
pressure of the CO.sub.2 production fluid. However, in general,
water-based power systems are less efficient than gas-based power
systems, and particularly CO.sub.2-based power systems. In some
examples, after geothermal heat has been extracted from the brine
solution, the brine system can be disposed of, such as by injecting
the brine solution into the reservoir 1 or another geological
formation, or the brine solution can be used for another purpose
within the system, such as a cooling medium within the cooling unit
22. Alternatively, the brine solution can be processed to extract
useful minerals or to provide fresh water.
[0130] In order to maximize methane production and ensure methane
is available for the lifespan of the system, careful and staged
CO.sub.2 plume development can be employed. A single geologic
reservoir that is capable of supporting CO.sub.2 injection and
sequestration can, for instance, have multiple sublayers that can
preferentially permit CO.sub.2 flow. Sublayers can be distinguished
by permeability and porosity. Sublayers that favorably support
CO.sub.2 injection via relatively high permeability or porosity, or
both, can be near-vertically separated from sublayers of lower
permeability, porosity, or both. Such sublayers that support or
retard CO.sub.2 flow can alternate in any order in a near-vertical
stack, where "near-vertical," as used herein, can refer to the
geologic layers and sublayers being substantially horizontally
oriented, or only inclined from horizontal by from zero to a few
degrees in deep naturally permeable and porous formations. Such
sublayering is common in deep permeable formations. The sublayer
can allow CO.sub.2 injection and production to begin in one
sublayer and then proceed to others, e.g. by perforating and
completing the injection wells, or the production wells, or both,
for the CO.sub.2 plume (which can include methane plume, as
described above) in one sublayer, and with a methane
high-concentration zone, in another sublayer as each sublayer
matures. In such a way, a long-term methane supply for operation of
the geothermal energy recovery system can more readily be
achieved.
[0131] The examples described above with respect to FIGS. 1-6 have
all shown or described a single reservoir that includes a native
fluid comprising methane in solution, where the CO.sub.2 working
fluid injected into the reservoir both extracts a portion of the
methane and absorbs geothermal heat. However, other systems and
methods can be included with the concepts of the present
disclosure. For example, a geological formation can include a first
geological formation in close proximity to a second geological
formation. The first geological formation can comprise a native
fluid that includes methane, while the second geological formation
can comprise conditions that are favorable to geothermal heat
absorption into a CO.sub.2 working fluid, or for CO.sub.2
sequestering, or both. For example, the first, methane-containing
formation can be located above or below the second, geothermal heat
formation. With such a geological configuration, a first set of one
or more injection wells and one or more production wells can be
drilled for the first formation, and a second set of one or more
injection wells and one or more production wells can be drilled for
the second formation. A small amount of CO.sub.2 working fluid can
be injected into the first formation to extract methane therefrom,
while a larger amount of CO.sub.2 working fluid can be injected
into the second formation for geothermal heat recovery or CO.sub.2
sequestering, or both. The circulating CO.sub.2 working fluid in
the first formation can supply methane for the system, while the
circulating CO.sub.2 working fluid in the second formation can be
used for geothermal heat recovery, e.g., via the formation of a
CO.sub.2 plume, or for sequestering at least a portion of the
injected CO.sub.2, or both.
[0132] As discussed above, the production fluid 26 being produced
from the reservoir 1 can have a percentage of methane included
within the production fluid 26, e.g., from 1 wt % to 10 wt % or
more, such as about .sub.5 wt % methane and 95 wt % CO.sub.2. It
has been surprisingly found that the inclusion of even a small
percentage of methane in the production fluid 26 can have a
demonstrable improvement in system efficiency compared to a
produced fluid that is substantially all CO.sub.2, as in a CPG
geothermal recovery system. FIGS. 7A and 7B show pressure-enthalpy
phase diagrams for a 100% CO.sub.2 working fluid cycling through
the system (FIG. 7A) and a 95% CO.sub.2, 5% methane working fluid
(FIG. 7B). Each phase diagram has been marked with a hypothetical
cycle of the working fluid or production fluid as it moves through
the reservoir 1, is produced to the surface systems (e.g., the
energy recovery system 32), and re-injected back into the reservoir
1.
[0133] Each of the phase diagram cycles in FIGS. 7A and 7B is
marked with five (5) points representing five specific locations
within the cycle. In both FIG. 7A and FIG. 7B, point "1" represents
the injection of the working fluid 12 at the top of the injection
well 14. Point "2" represents the working fluid 12 as it exits the
injection well opening 16. Point "3" represents the production
fluid 26 as it enters the production well opening 30. Point "4"
represents the point just before the production fluid 26 enters the
energy recovery system, e.g., just before it is sent through an
expansion device 36. Point "5" represents the production fluid 26
after it has exited the energy recovery system 32, e.g., from the
expansion device 36, but before it has been cooled in a cooling
unit 22.
[0134] As can be seen from the comparison of FIGS. 7A and 7B, the
system that includes 5% methane can actually recover more energy
within the energy recovery system 32, as indicated by the greater
change in enthalpy along the horizontal axis of FIG. 7B between
point 4 and point 5, compared to the change in enthalpy between
points 4 and 5 in FIG. 7A. For example, the enthalpy change between
points 4 and 5 in FIG. 7A (CO.sub.2 only) is about 40 kJ/kg of
working fluid, while the enthalpy change between points 4 and 5 in
FIG. 7B (CO.sub.2 and methane) is about 50 kJ/kg of working fluid,
or slightly more than a 20% increase in potential energy to be
extracted. Although not all of the enthalpy change in the working
fluid or production fluid can be recovered by the energy recovery
system 32, assuming the efficiency of the energy recovery system 32
recovering energy from a CO.sub.2 and methane fluid is
substantially the same as the efficiency of the system 32
recovering energy from a pure CO.sub.2 system, it is expected that
the difference in enthalpy change will result in a higher amount of
energy being extracted from the production fluid (and thus a higher
amount of electricity produced) for a CO.sub.2 and methane system
compared to a CO.sub.2 only stream as in a CPG system.
[0135] In addition, the amount of heat energy that needs to be
removed in the cooling unit 22 (represented by the enthalpy change
between points 5 and 1 in FIGS. 7A and 7B) is less for the CO.sub.2
and methane working fluid or production fluid. For example, the
enthalpy change between points 5 and 1 in FIG. 7A (CO.sub.2 only)
is about 215 kJ/kg, while the enthalpy change between points 5 and
1 in FIG. 7B (CO.sub.2 and methane) is about 195 kJ/kg, or
approximately a 9% decrease in the heat dump that is required
within the cooling unit 22.
[0136] As demonstrated by FIGS. 7A and 7B, the addition of even a
small portion of methane (5 wt. %) provides for potentially a 20%
increase in electricity production and a 10% decrease in the
cooling load required before re-injection. This shows that,
surprisingly, the extraction of even a small portion of methane
from the native fluid 2 within a reservoir 1 can not only be used
to boost temperature or pressure of the production fluid, which can
increase overall system efficiency (as described above, but also
further improves the operating efficiency of the system simply by
the methane being present.
Waste Heat-Enhanced CPG System
[0137] As noted above, in some examples, the reservoir into which
the CO.sub.2 working fluid is injected, e.g., reservoir 1 in FIGS.
1-4, can comprise a hydrocarbon field that has been partially
depleted via conventional oil or natural gas recovery methods. In
these partially-depleted oil and natural gas fields, the CO.sub.2
can be injected for the purpose of enhanced oil recovery (EOR).
Hydrocarbon reservoirs can contain substantial fractions of oil and
gas, which can be far more than the small percentage of methane
that can be dissolved in deep brine aquifers. The CO.sub.2 working
fluid that is injected into such hydrocarbon reservoirs can free
and carry to the surface large quantities of hydrocarbons and other
fluids such that CO.sub.2 constitutes even the minority of the
produced flow. In some examples, however, the hydrocarbon field can
be substantially depleted of hydrocarbons such that they produce
very little oil or natural gas through primary or secondary
recovery. In these substantially depleted fields, water or brine
and CO.sub.2 can comprise far more of the flow than do
hydrocarbons. In short, the composition of the production fluid
from an EOR field can be complex and varied. In some examples, the
methane and other hydrocarbons that are produced can be much
greater than is necessary for enhancing geothermal energy recovery
and for re-injection into the reservoir, so that the additional
methane and other hydrocarbons can be sold in addition to what is
kept for use in enhanced CPG operations.
[0138] The complex produced fluid from an EOR field, which can
generally comprise a combination of CO.sub.2, hydrocarbons, and
water or brine, can either be separated before or after geothermal
heat energy extraction. The heat extraction apparatuses, generally
either a direct or a binary power system, that are employed in an
EOR setting can be chosen on a site-specific basis according to
produced fluid temperature, pressure, and composition
conditions.
[0139] In an example, the systems required for EOR operations can
be powered by electricity. The electricity requirements of an EOR
system can be substantially greater than the requirements for a
CO.sub.2 plume geothermal system or a CO.sub.2 geothermal system
including methane combustion to supplement the geothermal energy
recovery. The electricity for EOR operations can be purchased from
the grid or through the use of on-site gas turbines fueled by
purchased or locally-produced methane. In the case of produced
methane, power production efficiency and total power produced can
be increased through the use of the methane-enhanced geothermal
recovery systems described above. The increased efficiency of the
methane-enhanced systems can be achieved with little or no increase
in cost for the site operator because geothermal and gas combustion
energy are combined. Moreover, the overall power costs for an EOR
system that is supplemented with methane-enhanced geothermal energy
recovery can be decreased because the power produced onsite can be
produced from all available energy types, e.g., geothermal and gas
chemical.
[0140] One or more components of the geothermal energy recovery
system or other co-located systems, such as an EOR recovery system,
can include an operation or equipment that can generate
considerable heat. Often, heat generated by these systems,
operations, or equipment are allowed to dissipate to the atmosphere
such that the heat energy is essentially wasted. This kind of heat
is referred to herein as "waste heat."
[0141] An example of waste heat that can occur at or near a
geothermal energy recovery system can include heat generated by a
CO.sub.2 compressor. As noted above, CO.sub.2 working fluid 12 from
a CO.sub.2 source 18 can be pressurized in a compressor 20 before
it is injected into the injection well 14. Similarly, the CO.sub.2
that is formed during combustion of the separated methane 46 to
increase the temperature or pressure of the production fluid 26 and
the captured can also be compressed with a compressor 20 and
injected into the injection well 14. Also, in an enhanced oil
recovery (EOR) system, CO.sub.2 can be produced from the reservoir
1 and separated from the production fluid 26. The produced CO.sub.2
can be compressed and re-injected back into the reservoir 1. It is
understood in the art that CO.sub.2 compressors, such as those used
in EOR systems or for the compression of CO.sub.2 for injection
into a reservoir, such as for CO.sub.2 sequestration, can generate
a considerable amount of heat. In an example, a CO.sub.2 compressor
for the injection of CO.sub.2 into the reservoir 1 can generate 50
to 1500 kJ of heat energy per kg of CO.sub.2 compressed, such as
200 to 600 kJ of heat energy per kg of CO.sub.2 compressed, for
example 400 to 450 kJ of heat energy per kg of CO.sub.2
compressed.
[0142] Another example of a source of waste heat can occur in an
EOR system. As described above, a production fluid from an EOR
field can include CO.sub.2, brine or other native liquids, and
hydrocarbons from the oil or gas reservoir. The different
components of the production fluid can be separated, either before
the geothermal energy is recovered or after. One method for
separating hydrocarbons from the other fluids in the production
fluid can include burning a portion of the methane or other
hydrocarbons that are produced within a separation vessel, which in
turn heats the production fluid. The increased temperature of the
production fluid can improve separation of liquid hydrocarbons from
CO.sub.2, natural gas, and brine. However, the heating to improve
separation results in a stream of hot liquid hydrocarbons, hot
brine, hot CO.sub.2 and natural gas, or any combination thereof,
that have conventionally simply been allowed to cool by dissipating
the heat to the atmosphere.
[0143] Still another example of a source of waste heat can occur
with a facility that includes the geothermal energy recovery
systems of the present disclosure co-located with another type of
facility that produces excess heat. For example, if the geothermal
energy recovery facility is co-located with an ethanol or other
biofuel production plant. A co-located ethanol or biofuel plant can
be desirable because such plants generally produce CO.sub.2 waste
streams during production that can be captured and used as the
CO.sub.2 source for the geothermal energy recovery systems of the
present disclosure. Other examples of waste heat sources from other
facilities include, but are not limited to, fermentation tanks in
biofuel facilities, furnaces in industrial facilities such as
cement manufacturing plants, cooling units in fossil fuel power
plants, and the heat energy produced at a flare, such as a methane
or natural gas flare. Moreover, the CO.sub.2 generated by ethanol
and biofuel plants are typically relatively clean CO.sub.2 streams
that can be captured at a lower cost than CO.sub.2 from fossil fuel
power plants. Capturing and injecting the CO.sub.2 from the ethanol
or biofuel plant can require the use of a CO.sub.2 compressor,
which, as noted above, can generate considerable waste heat.
[0144] The above examples of waste heat are intended to be merely
exemplary of the sources of waste heat that may be typical or
advantageous when co-located with geothermal energy recovery. The
above examples are not intended to be limiting, and a person of
ordinary skill in the art can readily determine whether other waste
heat sources can be used to supplement geothermal energy recovery,
as described below.
[0145] FIG. 8 shows a non-limiting example of a system 130 where
geothermal energy recovery can be supplemented by waste heat
recovery. The system 130 of FIG. 8 can include a CO.sub.2 source
132 that is pressurized in a compressor 134 to form a CO.sub.2
working fluid 136 that can be injected into a reservoir 138 through
an injection well 140. The CO.sub.2 working fluid 136 off the
compressor 134 can be cooled in a cooling unit 135.
[0146] The reservoir 138 can include a native fluid 142 that can
include methane 144 in solution within the native fluid 142. In an
example, the native fluid 142 can include oil or other hydrocarbons
or brine within an EOR reservoir 138. The CO.sub.2 working fluid
136 can form a CO.sub.2 plume 146 within the reservoir 138 that can
comprise CO.sub.2 from the working fluid 136, a portion of the
methane 144 that is released from solution within the native fluid
142, hydrocarbons from the native fluid 142 that are released due
to the injection of the CO.sub.2 working fluid 136, and other
native fluids such as brine or water (discussed in more detail
above). All of these components can form a production fluid 148
that is produced to the surface via a production well 150. In
short, the system 130 can be configured as an enhanced oil recovery
(EOR) system. As described above, the system 130 can include
several subsystems for energy recovery or conversion that
supplements geothermal energy recovery by increasing the energy
that is available to an energy recovery system.
[0147] The production fluid 148 can be fed into a separation system
152 that can separate the production fluid 148 into its various
components. In an example, the separation system 152 can separate
the production fluid 148 into a gaseous CO.sub.2 and methane stream
154, a liquid brine or water stream 156, and a liquid hydrocarbon
stream 158. As described above, in some methods separation can be
aided in the separation system 152 by heating the production fluid
148 to high temperatures to more efficiently separate the liquid
hydrocarbons 158 from the other components, which can result in all
three of the product streams 154, 156, and 158 from the separation
system 152 being at a high temperature, such as about 30.degree. C.
to about 120.degree. C., for example about 50.degree. C. to about
80.degree. C.
[0148] The heat energy created in the separation system 152 had
conventionally been allowed to dissipate to the atmosphere as waste
heat. The example system 130 of FIG. 8, however, is configured to
recover at least a portion of the waste heat from the separation
system 152. A secondary working fluid 160 can be circulated
throughout the system at the surface in order to recover heat
energy from various sources. As shown in the example of FIG. 8, one
or more heat exchangers can be configured to recover heat from the
hot separated streams 154, 156, 158, such as a first heat exchanger
162A on the CO.sub.2/methane stream 154, a second heat exchanger
162B on the brine stream 156, and a third heat exchanger 162C on
the liquid hydrocarbon stream 158. The secondary working fluid 160
can be split into three separate streams that are fed through the
heat exchangers 162 in order to absorb heat from the hot product
streams 154, 156, 158. The secondary working fluid 160 will also
absorb at least a portion of the geothermal energy absorbed by the
production fluid 148 in the reservoir 138. After passing through
the heat exchangers 162, the secondary working fluid 160 can be
rejoined for further circulation.
[0149] In one example, the separation system 152 may not produce a
considerable amount of waste heat, e.g., where liquid hydrocarbon
separation can be achieved without further heating. In such a case,
the heat exchangers 162 can be configured to only absorb the
geothermal energy that has been absorbed by the production fluid
148 (and which is present in the separate product streams 154, 156,
158). Alternatively, a single heat exchanger can be positioned
upstream or downstream of the separation system 152 to absorb the
geothermal heat energy.
[0150] At least a portion of the cooled CO.sub.2/methane stream 154
can be pressurized by a compressor 164 for re-injection back into
the reservoir 138 through the injection well 140. The cooled brine
or water stream 156 can be put into brine storage 166, such as
within water or brine tanks or by being injected into a geological
formation. At least a portion of the cooled liquid hydrocarbon
stream 158 can be sold as a hydrocarbon product 168.
[0151] The secondary working fluid 160 can circulate to other parts
of the system 130 in order to absorb other heat energy that might
otherwise be dissipated to the atmosphere. As described above, the
CO.sub.2/methane compressor 164 can generate considerable heat
energy, e.g., about 400 kJ to about 450 kJ per kg of CO.sub.2 and
methane being compressed for each stage of compression. In an
example, the secondary working fluid 160 can be circulated to the
compressor 164 in order to recover a portion of the waste heat
energy. In an example, a heat exchanger (not shown) can be placed
on the CO.sub.2/methane stream 154 immediately downstream of the
compressor 164 to transfer heat energy from the hot
CO.sub.2/methane stream 154 to the secondary working fluid 160. In
another example, the compressor 164 can be configured so that the
secondary working fluid 160 flows around or through the compressor
164, e.g., through a cooling jacket on the compressor 164, to
absorb heat from the compressor 164. Moreover, heat can be absorbed
from the outlet of the compressor (e.g., immediately downstream of
the compressor), or heat can be absorbed after one or more stages
(e.g., from an intercooler) of the compressor.
[0152] In an example, the compressor 164 produces more heat energy
than the heat energy produced in the separation system 152. For
this reason, the circuit of the secondary working fluid 160 can be
configured to first recover the heat energy from the separation
system 152 (via the heat exchangers 162), and then to recover heat
energy from the compressor 164.
[0153] As discussed above with respect to FIGS. 1-4, a portion of
the methane produced from the reservoir 138 can be separated from
the production fluid and combusted to supplement energy recovery by
increasing the temperature of a fluid, such as a production fluid
or a secondary working fluid. The system of FIG. 8 can optionally
include this feature of the present disclosure by including a
methane separation system 170 to separate a portion 172 of the
methane from the CO.sub.2/methane stream 154. The separated methane
172 can be fed into a combustion heater 174 that heats the
secondary working fluid 160. In an example, the combustion heater
174 produces more heat energy than the heat energy produced in the
separation system 152 or the compressor 164. For this reason, the
circuit of the secondary working fluid 160 can be configured to
first recover the heat energy from the separation system 152, then
recover the heat energy from the compressor 164, and then recover
the heat energy from the combustion heater 174.
[0154] A portion of the liquid hydrocarbons can be split off from
the liquid hydrocarbon stream 158 to be combusted in a heater to
further heat the secondary working fluid 160. In the example shown
in FIG. 8, a separated portion 176 of the liquid hydrocarbon stream
158 can be processed or refined in a refining or processing system
178 to modify the composition of the separated liquid hydrocarbons
176 to be more ideal for combustion within the heater. The refined
or processed liquid hydrocarbons 176 can be fed into a heater,
which can be the same heater 174 in which the separated methane 172
is combusted (as shown in FIG. 8), or the refined or processed
hydrocarbons 176 can be fed into a separate heater (not shown).
[0155] Alternatively, as described above, rather than heating the
secondary working fluid 160 with a heater 174, the separated
methane 172 and the liquid hydrocarbons 176 can be combusted in a
conventional gas turbine or gas engine (not shown) to produce
electricity from the turbine or engine. The combustion of the
hydrocarbon fuel, e.g., the methane 172 and the liquid hydrocarbons
176 in the gas turbine or the engine can produce substantial waste
heat in the form of hot combustion gases (e.g., CO.sub.2 and steam)
and hot engine or turbine cooling jacket fluid. The waste heat can
be added to the working fluid 160, such as via a heat exchanger.
This configuration can, in some cases, lead to higher energy
conversion efficiency then directly heating the working fluid 160
in a heater 174.
[0156] The byproducts of the combustion heater 174 can comprise
CO.sub.2, which can be captured and compressed for re-injection
into the reservoir 138, similar to the CO.sub.2 capture system 58
described above with respect to FIG. 1. The captured CO.sub.2 can
be fed into the same compressor 164 as the separated CO.sub.2 and
methane 154, or a separate compressor (not shown) can be used.
Waste heat from compressing the captured CO.sub.2 can also be
recovered using the secondary working fluid 160.
[0157] After the secondary working fluid 160 has recovered heat
from each heat source (e.g., waste heat from the separation system
152 or the compressor 164, or both, and heat from combustion of
separated methane 172 or separated liquid hydrocarbons 176 in a
combustion heater 174 (if present)), the secondary working fluid
160 can be fed into an energy recovery system 180 that can convert
energy in the secondary working fluid 160 to another form, such as
electricity 182 or direct-use heat. In the example shown in FIG. 8,
the energy recovery system 180 includes an expansion device 184
through which the secondary working fluid 160 passes to produce
shaft power 186. The shaft power 186 can drive a generator 188 to
produce the electricity 182. The secondary working fluid 160 can
then be circulated through a cooling unit 190 before restarting the
cycle at the heat exchangers 162.
[0158] As is further described above, a separate facility, such as
a power plant, a biofuel plant, or an industrial plant can be
co-located with the geothermal energy recovery system of the
present disclosure. Waste heat from such a co-located facility can
be recovered using heat exchangers and a working fluid, such as the
secondary working fluid 160, that is pumped between the co-located
facility and the geothermal energy recovery system, or the
production fluid 148 or one or more of its constituent components
can be pumped over to the co-located facility so that the waste
heat can be transferred directly to the production fluid or the
constituent component or components.
Alternative Configurations
[0159] In an example, another combustible fuel, such as natural
gas, biomass, or a biofuel (e.g., ethanol or diesel produced from
biological sources), can be obtained from a third party outside of
the geothermal energy recovery system. In another example, the
other fuel can be produced at a co-located facility, such as a
co-located ethanol or other biofuel production facility. The other
fuel can be used to boost total power production of the geothermal
energy recovery system, e.g., by combusting the outside fuel to
increase the temperature, the pressure, or both, of the CO.sub.2
based working fluid. For example, if a geothermal energy recovery
facility has been operating for a long period of time such that the
amount of methane that is being produced from the reservoir is low,
then the outside fuel can be used to supplement or replace the
now-defunct methane production. The geothermal heat recovered with
the CO.sub.2-based working fluid and the outside fuel source can
combine in much the same fashion as CO.sub.2-based energy recovery
and combusted produced methane, to increase the overall efficiency
of conversion energy to electricity and to produce more electricity
than either system could provide alone. In some examples, it may be
more economical to purchase natural gas (mainly CH.sub.4), or other
fuels, from a third party rather than relying on, or solely relying
on, separated CH.sub.4 from the production fluid. For example, if
the cost of natural gas is cheaper than the cost of separation. In
an example, the fuel used in the combustion heater can comprise
solely natural gas or other outside fuel, such as outside natural
gas or fuel purchased from a third party, rather than using any
separated CH.sub.4 produced from the reservoir.
[0160] In another example, site development considerations may
favor immediate production of the methane within the reservoir,
rather than long-term steady production of the methane. For
example, rather than ensure gradual methane production over the
life of a site, it can be better operated by producing the maximum
methane that can be extracted beginning immediately with the onset
of CO.sub.2 injection and continuing while the CO.sub.2 plume is
established. The produced methane can be sold or stored onsite,
such as in methane storage tanks or within a geologic formation
separate from the reservoir into which the CO.sub.2 working fluid
is injected. In the case of sold methane, a portion of the methane
can be purchased back over time to supply the system as needed. In
the case of stored methane, the methane can be removed from storage
over time to supply the system. Immediate production of the methane
can be economically favorable in circumstances when the well or
wells that for methane or brine production can be repurposed for
CO.sub.2 circulation without the need for separate methane and
CO.sub.2 wells. The economic advantages of repurposing the methane
or brine production wells for CO.sub.2 circulation can be balanced
with the added costs for methane storage (e.g., storage tanks or
systems for storing the methane in a geological formation).
[0161] FIG. 9 shows an example of another system 200 for geothermal
energy recovery from a production fluid 202 produced via a
production well 204 from a reservoir. The reservoir is not shown in
FIG. 9, but a person of ordinary skill in the art will understand
that the reservoir can be similar to the reservoirs shown in FIGS.
1-4 and 8. The system 200 can be particularly suited for an EOR
reservoir, e.g., a reservoir including native fluids including
methane, oil or other hydrocarbons, and brine. The system 200 can
also include an EOR facility 206, e.g., a facility including one or
more unit operations for the separation of the production fluid 202
into its components, some of which are described above with respect
to FIG. 8. The geothermal energy present in the production fluid
202 can be used to contribute to the process heat energy used
within the EOR facility 206. In other words, the natural geothermal
energy recovered by the production fluid 202, in addition to
providing for electricity generation as described throughout the
present disclosure, can also improve the efficiency of the EOR
process within the EOR facility 206. As demonstrated in FIG. 9, EOR
waste process heat 208 can be recovered from the EOR facility 206
via any of the techniques described herein.
[0162] The EOR facility 206 can separate a production gas stream
210, which can include CO.sub.2, CH.sub.4, and other gaseous
hydrocarbons, and water and other hydrocarbons 211 from the
production fluid 202. The system 200 can include a compressor or
pump 212 downstream of the EOR facility 206 for increasing the
pressure of the production gas stream 210 before recovering energy
from the production gas stream 210. In particular, the compressor
or pump 212 may be desired if the output pressure of the production
gas stream 210 from the EOR facility 206 has a relatively low
output pressure. The compressor or pump 212 can also compress the
production gas stream 210 to desired injection conditions so that
after energy recovery, the production gas stream 210 can be
injected back into the reservoir via an injection well 214.
[0163] The compressor or pump 212 can increase the overall
efficiency of the system. Surprisingly, it has been found that
increasing the pressure of the production gas stream 210, such as
with the compressor or pump 212, can increase the efficiency of the
system by more than the amount of energy required to compress the
production gas stream 210. Waste heat 216 from the compressor or
pump 212 can be recovered by the system 200, as described in more
detail above and below.
[0164] After the compressor or pump 212, if present, the production
gas stream 210 can be fed through an energy recovery apparatus that
can be similar to the methods described above, e.g., but first
heating the production gas stream 210 in a heater 218, such as by
combusting one or more fuels 219 in the heater 218, such as
separated CH.sub.4, hydrocarbon fuel from the EOR operation, or
other supplied fuel such as supplemental CH.sub.4, or via the
recovery of waste heat in a heat exchanger/heater 218, to increase
the temperature, increase the pressure, or both, of the production
gas stream 210. Alternatively, the one or more fuels 219 can be
combusted in a conventional gas turbine or gas engine (not shown)
to produce electricity from the turbine or engine, and waste heat
(in the form of hot combustion gases and hot cooling jacket fluid)
from the turbine or engine can be added to the production gas
stream 210, such as via a heat exchanger, rather than directly
heating the production gas fluid 210 with a heater 218.
[0165] The heated or pressurized production gas stream 210 can be
fed through a primary energy-recovery system 220 to produce
electricity 222 directly from the production gas stream 210, such
as one or more of a turbine, a generator, or an energy-recovery
loop such as a Rankine power cycle, an organic Rankine cycle (ORC),
or a Kalina cycle. A description of several examples of primary
energy-recovery systems are described above with respect to FIGS.
1-4 and 8.
[0166] The system 200 of FIG. 9 can also include a secondary
energy-recovery loop 224 to recover additional energy from the hot,
low pressure production gas stream 210. The secondary
energy-recovery loop 224 can comprise any feasible type of
energy-recovery cycle, such as a Rankine power cycle, an Organic
Rankine Cycle (ORC), or a Kalina Cycle. In the example of FIG. 9,
the secondary energy-recovery loop 224 includes an ORC-type
energy-recovery loop where a secondary working fluid 226 is
circulated through the cycle loop 224. Examples of secondary
working fluids that can be used in the secondary energy-recovery
loop 224 include, but are not limited to, one or more of CO.sub.2,
isobutene, ammonia, or a variety of other fluids. The type of
secondary fluid can be selected and optimized depending on the
temperature of the production gas stream 210 directly downstream of
the primary energy-recovery system 220 as well as the flow rate of
the production gas stream 210.
[0167] The secondary working fluid 226 can be heated, via a heat
exchanger 228, with the hot production gas stream 210 after it has
been fed through the primary generator or turbine system 220. The
heated secondary working fluid 226 can then be fed into a secondary
turbine or generator 230 to produce additional electricity 232.
After passing through the secondary turbine and generator 230, the
secondary working fluid 226 can be cooled in a cooling unit 234,
and the pressure of the secondary working fluid 226 can be
increased with a pump or compressor 236 to increase the pressure of
the working fluid 226 before starting the cycle over and heating
the working fluid 226, such as with the hot, low pressure
production gas stream 210 in the heat exchanger 228.
[0168] Depending on the temperature of the production gas stream
210 immediately downstream of the primary energy-recovery system
220, the secondary energy-recovery loop 224 can comprise a
supercritical cycle, a transcritical cycle, a subcritical cycle, or
a subcritical with superheater cycle.
[0169] The secondary energy-recovery loop 224 can provide for
energy recovery from relatively lower-temperature sources.
Therefore, additional low-temperature heating sources can be
applied to further heat the secondary working fluid 226 beyond just
using the hot production gas stream 210. The additional heating
from lower-temperature sources can include geothermal energy
recovery via a heat exchanger 238 that uses the production fluid
202 substantially immediately after being produced from the
production well 204 to heat the secondary working fluid 226. The
secondary working fluid 226 can also be further heated in a
waste-heat heat exchanger 240 heated by waste heat from other parts
of the system 200. Waste heat sources that can be particularly
useful in the secondary energy-recovery loop 224 can include waste
heat 208 from the EOR facility 206 and waste heat 216 from the pump
or compressor 212.
[0170] It would be difficult to recover heat energy from the
relatively lower-temperature energy sources described above using
the primary energy-recovery system 220 because the CO.sub.2,
CH.sub.4, and other gases in the production gas stream 210 coming
out of the EOR facility 206 or the pump or compressor 212 can be
relatively hot. In contrast, for at least portions of the secondary
energy-recovery loop 224, the secondary working fluid 226 can be
relatively cool, particular after the cooling unit 234 but before
heating the secondary working fluid 226 in the heat exchanger 228
with the hot production gas stream 210.
[0171] The secondary working fluid 226 can also be further heated
by a high-temperature energy source, such as by combusting one or
more fuels 244, such as separated CH.sub.4, other hydrocarbons from
the EOR facility 206, or other fuels (such as purchased CH.sub.4),
in a secondary combustion heater 242. In an example, the secondary
combustion heater 242 operates at a higher temperature than the hot
production gas stream 210, so that the secondary heater 242 is
placed downstream of the heat exchanger 228 as the last source of
heat added to the secondary working fluid 226 in the secondary
energy-recovery loop 224. The secondary energy-recovery loop system
200 of FIG. 9 can be particularly well suited for very
low-temperature geothermal reservoirs, such as those at
temperatures below about 75.degree. C.
[0172] Additional energy recovery loops, e.g., a tertiary loop, a
quaternary loop, and so on, can be included in the system 200. For
example, the hot secondary working fluid 226 coming out of the
secondary turbine or generator 230 can be used to heat a tertiary
working fluid in a tertiary energy-recovery loop, and so on.
[0173] FIG. 10 shows an example of another system 250 for
geothermal energy recovery. The system 250 can be similar to the
system 200 described above with respect to FIG. 9, e.g., the system
250 can provide for energy recovery from a production fluid 202
produced via a production well 204 from a reservoir. The reservoir
is not shown in FIG. 10, but a person of ordinary skill in the art
will understand that the reservoir can be similar to the reservoirs
shown in FIGS. 1-4 and 8. The system 250 can be particularly suited
for an EOR reservoir, e.g., a reservoir including native fluids
including methane, oil or other hydrocarbons, and brine. Like the
system 200 of FIG. 9, the system 250 can also include an EOR
facility 206 that can separate the production fluid 202 into one or
more components, including a production gas stream 210, which can
include CO.sub.2, CH.sub.4, and other gaseous hydrocarbons from the
production fluid 202.
[0174] Similar to the system 200 of FIG. 9, the system 250 in FIG.
10 can include a compressor or pump 212 downstream of the EOR
facility 206 for increasing the pressure of the production gas
stream 210 before recovering energy from the production gas stream
210, e.g., if the output pressure of the production gas stream 210
from the EOR facility 206 has a relatively low output pressure. The
compressor or pump 212 can also compress the production gas stream
210 to desired injection conditions so that after energy recovery
the production gas stream 210 can be injected back into the
reservoir via an injection well 214.
[0175] Like the system 200 of FIG. 9, the system 250 can include
sending the production gas stream 210 through a primary
energy-recovery apparatus after the compressor or pump 212, if
present. For example, the production gas stream 210 can be heated
in a heater 252, such as by combusting one or more fuels 254 in the
heater 252 to increase the temperature, increase the pressure, or
both, of the production gas stream 210. The heated or pressurized
production gas stream 210 can be fed through a primary
energy-recovery system 256, such as a turbine and generator
combination, to produce electricity 258.
[0176] The system 250 can also include a recuperator heat exchanger
260 to recover heat energy from the hot production gas stream 210
downstream of the heater 252 and the primary energy-recovery system
256. The recuperator heat exchanger 260 uses the relatively high
temperature of the production gas stream 210 downstream of the
primary energy-recovery system 256 to increase the temperature of
the inlet flow of the production gas stream 210 before it enters
the heater 252 and the primary energy-recovery system 256, thus
increasing the overall efficiency of the system 250 compared to a
system that did not include a recuperator heat exchanger. The
recuperator heat exchanger system 250 of FIG. 10 can be
particularly well suited for very low-temperature geothermal
reservoirs, such as those at temperatures below about 75.degree.
C.
[0177] After recovering energy from the production gas stream 210,
such as via the secondary energy-recovery loop 224, as in FIG. 9,
or via the recuperator heat exchanger 260, as in FIG. 10, the
production gas stream 210 can be fed into a separator or separation
system 262 that can separate CO.sub.2 in the production gas stream
210 from CH.sub.4 and other gaseous components in the production
gas stream 210 to form a relative pure CO.sub.2 stream 264 and a
CH.sub.4 and other fuels stream 266. The CO.sub.2 stream can be
cooled in a cooling unit 268 and compressed in a pump or compressor
270, if desired, for reinjection back into the reservoir through
the injection well 214. The CH.sub.4/fuel stream 266 can be used to
supply heaters of the system 200, 250, such as to form all or part
of the fuel stream 219 for the heater 218 (FIG. 9), all or part of
the fuel stream 254 for the heater 252 (FIG. 10), or all or part of
the fuel stream 244 for the secondary heater 242 in the secondary
energy-recovery loop 224 (FIG. 9). A portion of the CH.sub.4/fuel
stream 266 can also be used in another part of the facility (such
as in the EOR facility 206, or in a co-located ethanol facility or
other co-located facility), or a portion or all of the
CH.sub.4/fuel stream 266 can be sold in the open market.
[0178] A direct CO.sub.2 turbine may be used after the compressor
that is required in all CO.sub.2-EOR operations. This configuration
may require inclusion of a pump/compressor before the turbine
(preferably before the methane heater and waste heat capture unit,
as well) if the existing EOR compressor has an insufficient output
pressure. A pump could, alternatively, be included after the
cooling unit--this configuration may be preferable, since the cold
liquid/supercritical stream could relatively easily be recompressed
to required injection conditions. Note that the presence of a pump
after the power system is defined in the application in some cases,
but the case of a direct turbine after the compressor is not
explicitly specified.
EXAMPLES
[0179] The invention will be further described by reference to the
following examples, which are offered to further illustrate various
embodiments of the present invention. It should be understood,
however, that many variations and modifications may be made while
remaining within the scope of the present invention. The Examples
include numerical modeling of electricity production from various
working fluids or production fluids. The modeling was created using
Matlab, sold by The MathWorks Inc., Natick, Mass., USA, together
with the National Institute of Standards and Technology (NIST)
Reference Fluid Thermodynamic and Transport Properties Database
(REFPROP), Version 9.0.
Example 1
[0180] FIG. 11A shows the electricity produced (in megawatts (MW))
depending on the wellhead temperature of the working fluid or the
production fluid immediately after it is produced to the surface.
FIG. 11B shows the electricity produced depending on the bottomhole
temperature. The difference in temperature between the well bottom
temperatures (FIG. 11B) and the wellhead temperature (FIG. 11A) are
due to Joule-Thompson cooling, which occurs as the fluid pressure
decreases during fluid ascent in the production well, such that the
fluid bottomhole temperature and pressure are greater than the
wellhead temperature and pressure. The calculations employed to
create FIGS. 11A and 11B account for the Joule-Thompson behavior,
which does not occur with water-based geothermal working
fluids.
[0181] The modeling assumed a reservoir depth of 1500 m, a flow
rate of the production fluid of 200 kg/s, that the production fluid
is 99 wt % CO.sub.2 and 1 wt % methane, that 2.0 kg/s of the
methane is separated and combusted to boost the temperature, the
pressure, or both of the production fluid. The expansion device and
generator are assumed to have a power system efficiency of 50% of
the Carnot efficiency.
[0182] FIGS. 11A and 11B both include data lines for the
electricity produced by a methane-enhanced CO.sub.2 Plume
Geothermal (ME-CPG) system, similar to the system 10 shown in FIG.
1. Two data lines are shown for ME-CPG systems, a first line 300
shows the electricity produced if the CO.sub.2 if the exhaust
stream 56 from the heater 48 is not captured, such as in a CO.sub.2
capture system 58, and a second line 302 shows the electricity
produced if the CO.sub.2 is captured. If a CO.sub.2 capture system
58 is used, it can use up some of the electricity produced by the
energy recovery system 32, for example to capture and compress the
CO.sub.2, which is demonstrated by data line 302 in FIGS. 11A and
11B being lower than the line 300. For the models, it is assumed
that the CO.sub.2 capture system 58 provides 90% capture
effectiveness, e.g., 90% of the CO.sub.2 created in the heater 48
is captured by the CO.sub.2 capture system 58, and that the
captured CO.sub.2 is compressed and injected into the reservoir.
For both the CO.sub.2 capture data line 302 and the non-CO.sub.2
capture data line 300, it is assumed that all of the methane in the
production fluid is separated and combusted to increase the
temperature of the production fluid, increase the pressure of the
production fluid, or both. 90% of the heat of methane combustion is
assumed to be transferred to the production fluid and captured by
the power cycle.
[0183] FIGS. 11A and 11B also show data for geothermal recovery
system that does not separate and combust released methane, e.g., a
CPG only system, represented by line 304, and lines for electricity
production from the methane combustion alone, both without CO.sub.2
capture (line 306) and with CO.sub.2 capture (line 308).
[0184] As shown in FIGS. 11A and 11B, it has been surprisingly
found that the recovery of geothermal energy using a CO.sub.2 and
methane production fluid in conjunction with the separation and
combustion of a portion of the methane can produce more electricity
than the combination of both the CO.sub.2 geothermal energy
recovery and combustion of methane alone. In other words, the
combination of both geothermal energy recovery with a CO.sub.2
plume and separation and combustion of methane to boost the
temperature or pressure, or both, of the production fluid is
surprisingly more efficient than what would be expected for the
combination of each of these energy components by themselves. For
example, in FIG. 11A at a wellhead temperature of about 100.degree.
C., the CPG-only data line 304 shows electricity production of
about 17 MW and the methane combustion with CO.sub.2 capture data
line 308 shows electricity production of about 18 MW so that the
expected combined electricity production for geothermal energy
recovery using CPG and methane combustion is about 35 MW. However,
as shown in FIG. 11A, the methane-enhanced geothermal energy
recovery with CO.sub.2 capture data line 302 shows electricity
production at a 100.degree. C. wellhead temperature of about 44 MW,
which is about 25% higher than the 35 MW that would be
expected.
Example 2
[0185] FIGS. 12A and 12B show similar data comparing a ME-CPG
system without CO.sub.2 capture (data line 310) and with CO.sub.2
capture (data line 312), CPG-only geothermal energy recovery (data
line 314), and methane combustion only without CO.sub.2 capture
(data line 316) and with CO.sub.2 capture (data line 318), but at a
reservoir depth of 2500 m, rather than the 1500 m in FIGS. 11A and
11B.
Example 3
[0186] FIG. 13 shows the electricity produced (in megawatts (MW))
depending on the wellhead temperature of the production fluid. FIG.
13 includes data for methane-enhanced geothermal energy production
from an EOR application, where the geothermal energy recovery is
further supplemented by waste heat capture from a CO.sub.2
compressor.
[0187] The modeling for this example assumed a reservoir depth of
1500 m, a flow rate of the production fluid of 100 kg/s. The
production fluid is assumed to be 20 wt % CO.sub.2, 1 wt %
CH.sub.4, and the remainder liquid hydrocarbons and brine. The flow
rate of methane separated from the production fluid and combusted
is assumed to be 0.5 kg/s. The energy recovery system for the EOR
system is assumed to be a binary system with a secondary working
fluid such that energy recovery is less efficient than the direct
turbine system that can be used for Examples 1 and 2. Therefore,
the energy recovery system is assumed to have a power system
efficiency of 33% of the Carnot efficiency. The waste heat is
generated by a high ratio (10:1) compressor with heat capture only
off the final stage of compression, with no heat capture of any
compressor intercoolers. Therefore, additional heat capture from
the compressor beyond that shown in FIG. 13 may be possible.
[0188] FIG. 13 includes data for methane-enhanced and waste-heat
enhanced geothermal energy recovery without CO.sub.2 capture of any
CO.sub.2 produced by methane combustion (data line 320) and
methane-enhanced and waste-heat enhanced geothermal energy recovery
with CO.sub.2 capture (data line 322). A data line 324 is also
included to show the electricity produced just from the
methane-enhanced geothermal energy recovery, e.g., with no waste
heat capture, and without CO.sub.2 capture. FIG. 13 further
includes data for geothermal recovery system that does not separate
and combust released methane, e.g., a CPG only system, represented
by line 326, data for electricity production from the methane
combustion alone without CO.sub.2 capture (line 328), and data for
the electricity produced via the waste heat capture alone (line
330).
[0189] As shown in FIG. 13, it has been surprisingly found that the
capturing waste heat to further heat a working fluid in addition to
geothermal energy recovery can produce more electricity than the
combination of both the geothermal energy recovery and the captured
waste heat alone. In other words, the combination of both
geothermal energy recovery and waste heat capture is surprisingly
more efficient than what would be expected for the combination of
each of these energy components by themselves. For example, in FIG.
13 at a wellhead temperature of about 100.degree. C., the
methane-enhanced geothermal alone (with no waste heat capture and
no CO.sub.2 capture) data line 324 shows electricity production of
about 8.5 MW and the waste heat captured data line 330 shows
electricity production of about 1.5 MW so that the expected
combined electricity production for geothermal energy and waste
heat capture is about 10 MW. However, as shown in FIG. 13, the
methane-enhanced geothermal energy recovery with waste heat capture
and no CO.sub.2 capture results in electricity production at a
100.degree. C. wellhead temperature of about 11 MW, which is about
10% higher than the 10 MW that would be expected.
[0190] Various combinations of compressor stages can be used to
capture waste heat for supplementing geothermal energy recovery.
FIG. 14 shows the available energy (in kJ per kg of produced fluid)
from various sources at various bottomhole temperatures. The
example energy sources include methane combustion (line 350),
geothermal energy (line 352), waste heat from the compressor outlet
of a high-ratio, e.g., 10:1, CO.sub.2 compressor (line 354), waste
heat from an intercooler for a high-ratio, e.g., 10:1, CO.sub.2
compressor (line 356), waste heat from the compressor outlet of a
low-ratio, e.g. 2:1, CO.sub.2 compressor (line 358), and waste heat
from an intercooler for a low-ratio, e.g., 2:1, CO.sub.2 compressor
(line 360).
Example 4
[0191] FIG. 15 shows the electricity produced (in megawatts (MW))
depending on the volume of methane (in million standard cubic feet
per year) combusted. FIG. 15 includes data for methane-enhanced
geothermal energy production from an EOR application, where the
geothermal energy recovery is further supplemented by waste heat
capture from a CO.sub.2 compressor.
[0192] FIG. 15 includes data lines for the electricity produced by
a methane-enhanced CO.sub.2 Plume Geothermal (E-CPG) system,
similar to the system 200 shown in FIG. 9, e.g., a CO.sub.2-based
production fluid 210 is assumed to be produced from a production
well 204, pass through the EOR facility 206, and then into a
methane combustion heater 218 and a direct CO.sub.2 turbine (e.g.,
the primary energy-recovery system 220), and is then is used to
heat a secondary energy-recovery loop 224 with ammonia as the
working fluid. The CO.sub.2-based production fluid 210 can then be
cooled, if needed, compressed, and reinjection into the
reservoir.
[0193] A first data line 370 in FIG. 15 shows the electricity
produced for methane-enhanced CPG (E-CPG) for a CO.sub.2 flow rate
of 100 kg/sec and including waste heat capture of excess heat from
a CO.sub.2 compressor intermediate stage of the EOR facility being
added to the enhanced CPG power system rather than exhausted to the
atmosphere, as is commonly done in EOR operations. A second data
line 372 shows the electricity produced for an E-CPG system for a
CO.sub.2 flow rate of 75 kg/sec, also with waste heat capture. A
conservative estimate of 75% of the compressor waste heat is
assumed to be transferred to the enhanced CPG power system. The
waste heat translates to 109 kJoules/kg CO.sub.2. Note that this
waste heat quantity is a conservative assumption in some cases, as
EOR sites may have multiple CO.sub.2 compression steps. Third and
fourth data lines 374 and 376, respectively, show the electricity
produced at 100 kg/sec and 75 kg/sec, respectively, without waste
heat capture from the CO.sub.2 compressor.
[0194] For each of the data lines 370, 372, 374, 376, the
CO.sub.2-based working fluid is assumed to leave the EOR facility,
including CO.sub.2 compressors, at 2000 psia (about 13.8 MPa) and
300.degree. F. (about 149.degree. C.), which is a moderate CO.sub.2
injection pressure and a reasonable pre-cooling compressor outlet
temperature. The CO.sub.2 mass flow rate is shown for 100 kg/second
(data lines 370 and 374) and 75 kg/second (data lines 372 and 376),
which are consistent with a moderately-sized CO.sub.2 EOR facility.
Parasitic energy requirements of the compressors or pumps within
the system are accounted for in the results, but the compressor
power required by the EOR facility to raise CO.sub.2 pressure from
separation to injection conditions is not included because the
facility requires this energy regardless of whether an enhanced CPG
system is included. Either the primary energy-recovery or the
secondary energy-recovery loop can be used to gather the geothermal
and, if applicable, waste heat.
[0195] Each of the data lines 370, 372, 374, and 376 also includes
an assumption of geothermal heat input in the system, the reservoir
is assumed to be a relatively low temperature EOR field with
moderate oil and water production (6000 barrels/day of each
constituent). Geothermal energy is extracted from the combined
CO.sub.2, hydrocarbon, and water production stream, cooling the
stream from 57.degree. C. (about 135.degree. F.) to ambient
conditions. A conservative estimate of 75% of the geothermal energy
is assumed to be transferred to the enhanced CPG power system.
[0196] FIG. 15 also include a data line 378 for how much
electricity the waste heat alone could conceivable produce, and a
data line 380 for how much electricity the geothermal energy alone
could potentially produce. Finally, for reference, FIG. 15 also
shows the amount of electricity that could be produced using an
off-the-shelf gas turbine (data line 382) assumed to have 34%
efficiency, and an off-the-shelf gas engine (data line 384) assumed
to have 25% efficiency.
[0197] As can be seen in FIG. 15, the methane-enhanced CPG system
including a secondary energy-recovery loop can provide for
dramatically more electricity production compared to the geothermal
energy alone, the waste heat alone, or the expected electricity
production from methane combustion alone. As is further shown in
FIG. 15, the enhanced CPG system with waste heat capture is more
efficient than the expected combination of the enhanced CPG system
alone and the waste heat alone. Finally, as shown in FIG. 15, the
total energy produced in the enhanced CPG system with a secondary
energy-recovery loop, including waste heat, is more than would be
expected for each energy input by itself. FIG. 15 therefore shows
that the enhanced CPG system with a secondary energy-recovery loop
and waste heat recovery provides an unexpected synergistic benefit
beyond what is expected for the combination of each individual
energy input.
[0198] The above Detailed Description is intended to be
illustrative, and not restrictive. For example, the above-described
examples (or one or more elements thereof) can be used in
combination with each other. Other embodiments can be used, such as
by one of ordinary skill in the art upon reviewing the above
description. Also, various features or elements can be grouped
together to streamline the disclosure. This should not be
interpreted as intending that an unclaimed disclosed feature is
essential to any claim. Rather, inventive subject matter can lie in
less than all features of a particular disclosed embodiment. Thus,
the following claims are hereby incorporated into the Detailed
Description, with each claim standing on its own as a separate
embodiment. The scope of the invention should be determined with
reference to the appended claims, along with the full scope of
equivalents to which such claims are entitled.
[0199] In the event of inconsistent usages between this document
and any documents so incorporated by reference, the usage in this
document controls.
[0200] In this document, the terms "a" or "an" are used, as is
common in patent documents, to include one or more than one,
independent of any other instances or usages of "at least one" or
"one or more." In this document, the term "or" is used to refer to
a nonexclusive or, such that "A or B" includes "A but not B," "B
but not A," and "A and B," unless otherwise indicated. In this
document, the terms "including" and "in which" are used as the
plain-English equivalents of the respective terms "comprising" and
"wherein." Also, in the following claims, the terms "including" and
"comprising" are open-ended, that is, a system, device, article,
composition, formulation, or process that includes elements in
addition to those listed after such a term in a claim are still
deemed to fall within the scope of that claim. Moreover, in the
following claims, the terms "first," "second," and "third," etc.
are used merely as labels, and are not intended to impose numerical
requirements on their objects.
[0201] Method examples described herein can be machine or
computer-implemented, at least in part. Some examples can include a
computer-readable medium or machine-readable medium encoded with
instructions operable to configure an electronic device to perform
methods or method steps as described in the above examples. An
implementation of such methods or method steps can include code,
such as microcode, assembly language code, a higher-level language
code, or the like. Such code can include computer readable
instructions for performing various methods. The code may form
portions of computer program products. Further, in an example, the
code can be tangibly stored on one or more volatile,
non-transitory, or non-volatile tangible computer-readable media,
such as during execution or at other times. Examples of these
tangible computer-readable media can include, but are not limited
to, hard disks, removable magnetic disks, removable optical disks
(e.g., compact disks and digital video disks), magnetic cassettes,
memory cards or sticks, random access memories (RAMs), read only
memories (ROMs), and the like.
[0202] The Abstract is provided to comply with 37 C.F.R. .sctn.
1.72(b), to allow the reader to quickly ascertain the nature of the
technical disclosure. It is submitted with the understanding that
it will not be used to interpret or limit the scope or meaning of
the claims.
* * * * *
References