U.S. patent application number 17/403771 was filed with the patent office on 2021-12-02 for system and method for permanent storage of carbon dioxide in shale reservoirs.
The applicant listed for this patent is Prostim Labs, LLC. Invention is credited to John F. Thrash.
Application Number | 20210372235 17/403771 |
Document ID | / |
Family ID | 1000005779268 |
Filed Date | 2021-12-02 |
United States Patent
Application |
20210372235 |
Kind Code |
A1 |
Thrash; John F. |
December 2, 2021 |
SYSTEM AND METHOD FOR PERMANENT STORAGE OF CARBON DIOXIDE IN SHALE
RESERVOIRS
Abstract
The present disclosure provides a system, method and apparatus
for the removal of natural gas/methane from in situ loci within
shale reservoirs to (i) provide fully de-carbonized surplus
electricity, and (ii) power re-injection of the resulting carbon
formed (CO.sub.2) upon combustion in an electric generator along
with large volumes of atmospheric CO.sub.2, such as for large scale
removal of CO.sub.2 from the Earth's surface/atmosphere.
Inventors: |
Thrash; John F.; (Houston,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Prostim Labs, LLC |
Houston |
TX |
US |
|
|
Family ID: |
1000005779268 |
Appl. No.: |
17/403771 |
Filed: |
August 16, 2021 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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15677474 |
Aug 15, 2017 |
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17403771 |
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15186162 |
Jun 17, 2016 |
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15677474 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 41/0064 20130101;
C09K 8/60 20130101; Y02C 20/40 20200801; C09K 8/80 20130101; E21B
43/40 20130101; E21B 43/267 20130101; C09K 8/62 20130101 |
International
Class: |
E21B 41/00 20060101
E21B041/00; E21B 43/40 20060101 E21B043/40; E21B 43/267 20060101
E21B043/267; C09K 8/60 20060101 C09K008/60; C09K 8/80 20060101
C09K008/80; C09K 8/62 20060101 C09K008/62 |
Claims
1-6. (canceled)
7. A system for storing and extracting carbon compounds in an
underground reservoir, said system comprising: a first supply
subsystem adapted to provide a fluid to the underground reservoir;
a second supply subsystem adapted to provide a proppant to the
underground reservoir; a third supply subsystem adapted to provide
a solvent for dissolving the proppant to the underground reservoir;
and a pressure subsystem comprising a pump in communication with
the fluid and the proppant for pressurizing at least one of the
fluid and the proppant to a pressure sufficient to stimulate the
underground reservoir, and for pressurizing the solvent sufficient
to deliver the solvent to the underground reservoir.
8. The system of claim 7, the pump is in further communication with
the solvent for pressurizing the solvent to a pressure sufficient
to deliver the solvent to the underground reservoir.
9. The system of claim 7, further comprising a removal subsystem to
remove hydrocarbons from the underground reservoir.
10. The system of claim 9, wherein the removed hydrocarbons being a
fuel source for production of electricity.
11. The system of claim 9, further comprising a power conversion
unit to produce electricity and byproducts from hydrocarbons.
12. The system of claim 11, wherein the byproduct produced includes
the carbon compounds.
13. The system of claim 11, the electricity providing a power
source for injection of the carbon compounds into the underground
reservoir.
14. The system of claim 7, wherein the underground reservoir being
a shale reservoir.
15. A method for storing carbon containing compounds in a formation
associated with a pre-existing fracturing well formed by hydraulic
fracturing, the method comprising: injecting a solution into the
formation, the solution capable of at least partially degrading the
structural integrity of proppant positioned within the formation;
injecting the carbon containing compounds into the formation; and
periodically reinjecting CO.sub.2 into the formation.
16. The method of claim 15, wherein the proppant being a
conventional proppant.
17. The method of claim 15, wherein the formation being a
shale.
18. The method of claim 15, wherein the solution being an alkaline
solution.
19. The method of claim 15, wherein the solution being an acidic
solution.
20. The method of claim 15, wherein the at least partially
degrading comprising comprises at least partially dissolving the
structural integrity of the proppant.
21. A method for storing and extracting carbon containing compounds
in a formation associated with a fracturing well formed by
hydraulic fracturing, the method comprising: injecting proppant
into the formation; fracturing the formation; removing hydrocarbons
from in situ loci within the formation; injecting the carbon
containing compounds into the formation; injecting a solution into
the formation, the solution capable of at least partially degrading
the structural integrity of the proppant positioned within the
formation; and periodically injecting CO.sub.2 into the formation;
wherein a volume of the carbon containing compounds is greater than
a volume of the removed hydrocarbons.
22. The method of claim 21, wherein the proppant being a
conventional proppant.
23. The method of claim 21, wherein the formation being a shale
reservoir.
24. The method of claim 21, wherein the solution being an alkaline
solution.
25. The method of claim 21, wherein the solution being an acidic
solution.
26. The method of claim 21, wherein the at least partially
degrading comprises at least partially dissolving the structural
integrity of the proppant.
27. A method for producing electricity by combustion of
hydrocarbons without releasing carbon containing compounds into the
atmosphere, the method comprising: injecting proppant into the
formation; fracturing the formation; removing hydrocarbons from in
situ loci within the formation; converting the hydrocarbons into
electricity, wherein the converting produces the carbon containing
compounds; powering components of the system of claim 7 with the
electricity; utilizing the system to pump the carbon containing
compounds into the formation subsequent to the converting; and
injecting a solution into the formation, the solution capable of at
least partially degrading the structural integrity of proppant
positioned within the formation.
28. The method of claim 27, wherein a volume of the carbon
containing compounds is greater than a volume of the removed
hydrocarbons.
29. The method of claim 27, wherein the proppant being a
conventional proppant.
30. The method of claim 27, wherein the formation being a
shale.
31. The method of claim 27, wherein the solution being an alkaline
solution.
32. The method of claim 27, wherein the solution being an acidic
solution.
33. The method of claim 27, wherein the at least partially
degrading comprising comprises at least partially dissolving the
structural integrity of the proppant.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation in part and claims
priority to the U.S. Non-Provisional patent application Ser. No.
15/186,162, docket no. PROS012USOTR, filed Jun. 7, 2016, and is
hereby incorporated by reference in it's entirety.
FIELD OF THE INVENTION
[0002] The present disclosure relates generally to systems and
methods for storing carbon dioxide, and more specifically, to
systems and methods for permanently storing carbon dioxide in shale
reservoirs.
BACKGROUND OF THE INVENTION
[0003] Carbon sequestration can be divided into two categories: the
enhancement of the natural sinking rates of CO.sub.2 and direct
discharge of human generated CO.sub.2.
[0004] The sequestration options in the first category include
terrestrial sequestration by vegetation, ocean sequestration by
fertilization, and an enhancement of the rock weathering process.
In the direct discharge options, the CO.sub.2 produced from large
point sources, such as thermal power stations, would be captured
and separated, then transported and injected either into the ocean
or underground. The sequestration options are less beneficial in
terms of cost per unit CO.sub.2 reduction compared to other
options.
[0005] Each option has advantages and disadvantages in terms of
capacity, cost, the time scale of the sequestration, the stability
of sequestered CO.sub.2, and additional environmental impacts,
which depend on the location, time, and amount of sequestration.
Reliable evaluations of the mitigation efficiency are desirable for
each sequestration option upon implementation (Yamasaki, et al.
2003).
[0006] It has been stated that biological sequestration is a
natural approach; however, despite this advantage it is now known
that there are significant disadvantages. For example, while
freshwater marshes have been shown to be strong sinks for carbon
dioxide (CO.sub.2) on an annual basis relative to other wetland
types, it is likely that these ecosystems are also strong emitters
of methane (CH.sub.4), reducing their carbon (C) sequestration
potential. Thus, the substantial CH.sub.4 emissions from marshes
need to be considered in national and global estimates of wetland
greenhouse gas contribution to the global carbon cycle (Strachan et
al, 2015).
[0007] Ocean sequestration is another approach that can be
characterized as being natural. Although the oceans represent
possibly the largest potential CO.sub.2 sink, ocean sequestration
involves problems including poorly understood physical and chemical
processes, efficiency, cost, technical feasibility, and possibly
the most worrying, long-term environmental impact. In addition,
ocean circulation poses legal, political and international
limitations to this technology. Carbon dioxide forms carbonic acid
when dissolved in water, so ocean acidification is a significant
consequence of elevated carbon dioxide levels, and limits the rate
at which it can be absorbed into the ocean.
[0008] The sequestration of CO.sub.2 by a sacrificial material that
will then be used or disposed of represents a crossover between the
two categories. For example, mineral CO.sub.2 sequestration, i.e.,
carbonation of alkaline silicate Ca/Mg minerals, may be considered
analogous to natural weathering processes. Mineral CO.sub.2
sequestration may be considered for the reduction of carbon dioxide
emissions to the atmosphere. However, the total volume of material
required to make an impact on global CO.sub.2 emissions would be
cost prohibitive (Huijens, et al., 2005).
[0009] At this time, CO.sub.2 sequestration in geological media
appears to be an option for long-term sequestration of CO.sub.2. In
such a system it is proposed that CO.sub.2 may be stored deep
underground. At depth, hydrostatic pressure acts to keep it in a
liquid state (White, et al., 2005).
[0010] Sequestration in deep underground formations of large
amounts of CO.sub.2, captured from large stationary sources, such
as power plants, oil upgraders and refineries, is one method that
is under consideration for reducing greenhouse gas emissions to the
atmosphere in Canada and United States (Bennion and Bachu,
2005).
[0011] While hydrostatic pressure acts to keep CO.sub.2 in a liquid
state, this does not ensure that leakage cannot occur. In fact,
this is one of the biggest problems with the technology. Reservoir
design faults, rock fissures and tectonic processes may act to
release the gas stored into the ocean or atmosphere. Leak detection
using direct measurements, chemical tracers, and seismic monitoring
are therefore critical. The Weyburn-Midale Carbon Dioxide Project
(or IEA GHG Weyburn-Midale CO.sub.2 Monitoring and Storage Project)
as of 2008, was the world's largest carbon capture and storage
project. However, questions of CO.sub.2 leaks from the project have
been raised.
[0012] While in a typical well, the CO.sub.2 would be sealed by
capping the well with cement, degradation of the cement may prevent
such wells from being a long-term solution. Exposure of well
cements to CO.sub.2 results in the formation of different
CaCO.sub.3 modifications, proving carbonation. Carbonation rates
were relatively low, but most detrimental were the cracking of
specimens as a result of massive CaCO.sub.3 formation which comes
along with expansion (Lesti et al., 2013). Although some of the
reactions with cement can be beneficial, a loss of compressive
strength of the cement is observed (Condor and Asghan, 2009).
[0013] In summary, current CO.sub.2 geologic sequestration
technology suffers various problems and inadequacies. Failure of
the geologic formation or reservoir to contain the CO.sub.2 due to
cement failure may result in catastrophic release of vast
quantities of CO.sub.2 at some undetermined point in the
future.
BRIEF SUMMARY OF THE INVENTION
[0014] Subject matter of this disclosure provides a method for
sequestration in deep underground formations of large amounts of
CO.sub.2, with improved risk of leakage such as, for example,
long-term leakage.
[0015] In an embodiment, a sequestration method may include storing
CO.sub.2 in an underground formation by introducing the CO.sub.2
into a well formed in the formation by hydraulic fracturing, and
closing the hydraulic fractures to seal the well with the CO.sub.2
stored in the formation and prevent escape of the stored CO.sub.2
through the well fractures. In an embodiment, such a sequestration
method may include introducing the CO.sub.2 into a well formed by
hydraulic fracturing for the production of shale gas from a
reservoir of the underground formation. In an embodiment, a method
for large-scale sequestration of CO.sub.2 may include introducing
the CO.sub.2 into a plurality of wells formed by hydraulic
fracturing associated with production of shale gas from reservoirs
of at least one underground formation, such as a regional
formation, wherein the well includes sealed hydraulic fractures
preventing escape of stored CO.sub.2 from the formation through the
hydraulic fractures.
[0016] In an embodiment, a sequestration system may include a well
formed in the formation by hydraulic fracturing, CO.sub.2 stored in
the formation by introducing the CO.sub.2 through the well, and a
closed hydraulic fracture of the well sealing the stored CO.sub.2
in the formation to prevent escape of the stored CO.sub.2 through
the well fracture. In an embodiment, a sequestration system may
include a well formed by hydraulic fracturing associated with
production of shale gas from a reservoir of the underground
formation. In an embodiment, a large-scale sequestration system may
include a plurality of wells formed by hydraulic fracturing
associated with production of shale gas from reservoirs of at least
one underground formation, such as a regional formation, wherein
the well includes sealed hydraulic fractures preventing escape of
stored CO.sub.2 from the formation through the hydraulic
fractures.
[0017] In an embodiment, a CO.sub.2 sequestration system includes a
well formed in the formation by hydraulic fracturing, CO.sub.2
stored in the formation, and the well including sealed hydraulic
fractures preventing escape of stored CO.sub.2 from the formation
through the hydraulic fractures. In an embodiment, such a
sequestration system may include a well formed by hydraulic
fracturing associated with production of shale gas from a reservoir
of the underground formation. In an embodiment, a large-scale
sequestration system may include a plurality of wells formed by
hydraulic fracturing associated with production of shale gas from
reservoirs of at least one underground formation, such as a
regional formation, wherein the well includes sealed hydraulic
fractures preventing escape of stored CO.sub.2 from the formation
through the hydraulic fractures.
[0018] It will be understood that shale gas represents the largest
fraction of natural gas in the continental United States. With an
estimated 482 trillion cubic feet (Tcf) of hydrocarbon (Nicot and
Scanlon, 2012), shale gas has the potential to be the primary
energy source for power generation in the US for the coming
decades. The ability to extract shale gas in an economic and timely
manner has been achieved by the development and use of hydraulic
fracturing and horizontal drilling techniques. Hydraulic fracturing
(also known as "fracing" or "fracking") uses water, proppant, and
various chemical additives, pumped at high pressures into the well
bore, to induce fracturing of the shale source rock and thus create
greater permeability so the gas can migrate into the well bore and
to the surface. The fracturing fluid chemistry is tailored on a
case-by-case basis for each geographical area and sometimes even on
a well-by-well basis.
[0019] The reason that fracking is necessary is that shale has very
low permeability (concrete is 102-104 more permeable) and there has
been little or no movement of fresh water (or waters of a different
mineral content) since the rock was formed. Furthermore, shale is
under-saturated to water and the level of salt in the connate water
within the shale is often at salinity equal to the seawater the
shale was deposited from. In other words, shale is a reactor
waiting for an influx of fresh ingredients, and thus when under
saturated fresh water or even moderate salinity water is introduced
during a frac, salts, some organics, and other minerals that were
in equilibrium with the connate waters are solubilized. What is
most important is that the shale reservoir has been "isolated" from
external chemistry for several million years. In other words, until
the reservoir was fracked there is no route for the gas to escape,
meaning that if the natural gas could be exchanged for CO2 and the
reservoir returned to its pre-frack state the CO2 would be
contained by the same forces that contained the gas for millions of
years. Given that shale gas in the U.S. is formed during the
Jurassic period this gives an estimated stability of over 100
million years.
[0020] The present disclosure provides a system, method and
apparatus for the removal of natural gas/methane from in situ loci
within wells to (i) provide fully de-carbonized surplus
electricity, and (ii) power the re-injection of the resulting
carbon formed (CO.sub.2) upon combustion in the electric generator
along with large volumes of atmospheric CO.sub.2, culminating in a
technically and commercially feasible, permanent, in terms of
geologic time, large scale removal of CO.sub.2 from the Earth's
surface/atmosphere.
[0021] For the methane molecules produced, this is a
cradle-to-grave cycle wherein the same carbon atoms that are
harvested and used for power generation are then returned to their
original geologic resting place through the same fracture system,
pipe and compression that delivered them into power generation
service.
[0022] Once the shale reservoir and fracture systems are at or near
full volumetric storage capacity with sequestered CO.sub.2 (at or
near discovery pressure), the specialized proppant used in this
invention is dissolved by injecting an acidic aqueous solution,
thus allowing the geologic forces, previously resisted by the
proppant, to collapse and seal closed the fracture system,
permanently trapping the CO.sub.2 within the rock.
[0023] Concerning de-carbonization, the result of this process via
this invention is the permanent, in terms of geologic time, storage
of CO.sub.2 that is not dependent upon wellbore sealing or the long
term integrity thereof. Concerning fully de-carbonized power
generation, this system fully supports the continued and economic
use of intermittent supplies of electricity such as wave, wind and
solar generators.
[0024] The components of an embodiment may include large cohorts of
hydrocarbon productive shale wells that may be stimulated by
hydraulic fracturing utilizing certain select reservoir fluids
suffused with specialized proppant (the particles maintaining
fracture patency during production and re-injection) which may be
dissolved at the end of the CO.sub.2 sequestration cycle with a
small volume of an acidic aqueous solution. Embodiments may further
include natural gas and carbon dioxide compatible surface
facilities such as compression, dehydration, filter/separators and
measurement equipment which may be functionally bi-directional.
[0025] Embodiments may optionally include, in certain
circumstances, natural gas and/or carbon dioxide smaller scale
temporary storage reservoirs or surface facilities which may
facilitate the logistics of material movements and placement.
[0026] Embodiments may optionally include large (e.g. multi-hundred
MW F-class combined cycle turbines) and/or small (peaking gas fired
generators) scale electric power generating and ancillary
equipment.
[0027] Embodiments may optionally include pre-combustion (e.g.
oxy-fuel systems which provide O.sub.2 for combustion with the
natural gas) and/or post-combustion carbon dioxide capture systems
(e.g. electrolytic amine or Ca(OH).sub.2 systems).sub..
[0028] Embodiments may optionally include freshwater surface
handling facilities.
[0029] Sequestration of CO.sub.2 underground is hampered by the
paucity and adverse locational distribution of suitable reservoirs
to serve as economically feasible containers of large volumes of
CO.sub.2. Certainly depleted conventional reservoirs and deep
aquifers could serve in this role. However, their relative limited
capacity to meet the magnitude of the need and/or difficulties in
overcoming discovery pressures are very challenging aspects to
their utilization, irrespective of availability and location.
[0030] It may be vastly more efficient to store CO.sub.2 in shales
depleted of methane or CH.sub.4. Results have shown that CO.sub.2
has approximately two to three times the adsorptive capacity of
CH.sub.4 in both the pure mineral constituents and actual shale
samples (R. Heller and Zoback, 2014). This does not include the
volume attained by the proppant.
[0031] Given that natural gas is predominantly methane (CH.sub.4),
its combustion during power generation would result in one molecule
of CO.sub.2 per molecule of CH.sub.4 combusted. Combustion may be
represented by the following equation:
CH.sub.4+2O.sub.2.fwdarw.CO.sub.2+2H.sub.2O. Based upon this, it
can also be assumed that for every two to three molecules that can
be adsorbed within a well, one of the CO.sub.2 molecules was
generated during power generation using the produced methane or
CH.sub.4. Therefore, shale can be used for an over adsorption of
one to two equivalents of CO.sub.2 per each CH.sub.4 produced from
the original wells. This makes the entire process profoundly net
reductive of atmospheric CO.sub.2. In this regard, it is possible
to make natural gas electricity production, using shale gas and
current infrastructure, a large contributor of net negative
emissions of CO.sub.2.
[0032] While embodiments usable within the scope of the present
disclosure can be powered using on-site using reciprocating engines
(e.g., diesel engines), coupled with turbine generators and/or
similar power systems, in an embodiment, one or more system
components can be configured for use with electrical power. For
example, the pressure subsystem can include an electric-powered
driver (e.g., an electric motor or similar source of force) in
communication with and actuating the pump, while an electrical
power source powers the electric-powered driver. In an embodiment,
a turbine generator (e.g., a natural gas turbine or similar source)
can be used to provide power to an electric motor, which in turn
drives the pump. Alternatively or additionally, a grid-based power
source can be used to power the electric-powered driver. In an
embodiment, an electric-powered driver can be configured for
selective and/or simultaneous operation using a grid-based or an
on-site power source. Where a grid-based power sourced is used, in
an embodiment, one or more additional transformers can be used to
convert power from the grid-based power source to a desired
voltage. In use, a single pump can be actuated using a single
electric-powered driver or multiple electric-powered drivers, and
multiple pumps can be actuated using a single electric-powered
driver or multiple electric-powered drivers. Similarly, a single
power source can power one or multiple electric-powered drivers, or
one or multiple electric-powered drivers can be powered by multiple
power sources.
BRIEF DESCRIPTION OF THE DRAWINGS
[0033] The novel features believed characteristic of the disclosed
subject matter will be set forth in any claims that are filed. The
disclosed subject matter itself, however, further objectives, and
advantages thereof, will best be understood by reference to the
following detailed description of an illustrative embodiment when
read in conjunction with the accompanying drawings, wherein:
[0034] FIG. 1 illustrates an exemplary components diagram of the
present disclosure.
[0035] FIG. 2 illustrates an exemplary production flowchart diagram
of the present disclosure.
[0036] FIG. 3 illustrates an exemplary CH.sub.4 recovery flowchart
diagram of the present disclosure.
[0037] FIG. 4 illustrates an exemplary CO.sub.2 top-off flowchart
diagram of the present disclosure.
[0038] FIG. 5 illustrates an exemplary dissolve proppant flowchart
diagram of the present disclosure.
[0039] FIG. 6 displays a method for storing carbon compounds in an
underground reservoir.
[0040] FIG. 7 illustrates an exemplary production flowchart diagram
of the present disclosure.
[0041] FIG. 8 illustrates an exemplary production flowchart diagram
of the present disclosure.
[0042] FIG. 9 illustrates an exemplary production flowchart diagram
of the present disclosure.
DETAILED DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
[0043] Reference now should be made to the drawings, in which the
same reference numbers are used throughout the different figures to
designate the same components.
[0044] Before describing selected embodiments of the present
invention in detail, it is to be understood that the present
invention is not limited to the particular embodiments described
herein. The disclosure and description herein is illustrative and
explanatory of one or more presently preferred embodiments of the
invention and variations thereof, and it will be appreciated by
those skilled in the art that various changes in the design,
organization, order of operation, means of operation, equipment
structures and location, methodology, and use of mechanical
equivalents may be made without departing from the spirit of the
invention.
[0045] As well, it should be understood the drawings are intended
illustrate and plainly disclose presently preferred embodiments of
the invention to one of skill in the art, but are not intended to
be manufacturing level drawings or renditions of final products and
may include simplified conceptual views as desired for easier and
quicker understanding or explanation of the invention. As well, the
relative size and arrangement of the components may differ from
that shown and still operate within the spirit of the invention as
described throughout the present application.
[0046] Moreover, it will be understood that various directions such
as "upper", "lower", "bottom", "top", "left", "right", and so forth
are made only with respect to explanation in conjunction with the
drawings, and that the components may be oriented differently, for
instance, during transportation and manufacturing as well as
operation. Because many varying and different embodiments may be
made within the scope of the inventive concept(s) herein taught,
and because many modifications may be made in the embodiments
described herein, it is to be understood that the details herein
are to be interpreted as illustrative and non-limiting.
[0047] The present disclosure may provide to the oil/natural gas
industry efficient systems and methods for storing CO.sub.2 in
shales depleted of CH.sub.4.
[0048] The U.S. Energy Information Administration (EIA) estimates
in the Annual Energy Outlook 2015 that about 11.34 trillion cubic
feet of dry natural gas was produced directly from shale and tight
oil resources in the United States in 2013. If we assume that 11
trillion cubic feet of CH.sub.4 is produced, this is equivalent to
311 trillion L. At standard temperature and pressure, 22.4 L is
equal to 1 mole of any gaseous material. Thus, 311 trillion L of
CH.sub.4 is equal to 13.884 trillion moles CH.sub.4 produced.
[0049] The molar mass of CO.sub.2 is 44 g/mol. If we assume a
1-fold excess of CO.sub.2 would be sequestered in addition to the
CO.sub.2 generated in CH.sub.4 combustion. Then 13.884 trillion
moles CO.sub.2 would equal 610 trillion g of CO.sub.2. 610 trillion
g of CO.sub.2 is equal to 610 million (metric) ton of CO.sub.2.
This would represent the amount of excess CO.sub.2 sequestered into
the shale reservoirs once the process reaches steady state per year
assuming a two-fold exchange. If the value is closer to three-fold
then the amount of CO.sub.2 sequestered in excess of that used in
power generation would be 1,220 million tons of CO.sub.2.
[0050] On average the US emits 5,000 million ton of CO.sub.2 per
year from all sources. The main source is power generation.
Assuming the ability of shale reservoirs to sequester two to three
times the adsorptive capacity of CH.sub.4 in the wells, then this
process would result in a roughly 12-24% reduction in CO.sub.2
emissions in the US. The EU has set a target of reducing greenhouse
gas emissions by 40% by 2030. It was intended that this should be
simply by generation changes. However, using this process almost
half of this target could be achieved without alteration of the
infrastructure needs of the power generation or chemical industry
who are the major uses of hydrocarbon combustion for electricity
and energy (heat) generation.
[0051] FIG. 1 illustrates an exemplary components diagram of a
system 100 for storing carbon compounds in an underground reservoir
200 in accordance with embodiments. In embodiments, system 100 may
include components to inject a fluid under pressure into an
underground reservoir via a well 110. For example, system 100 may
be used to stimulate the production (e.g., of hydrocarbons) by
forming fractures in the well 110 through the provision of a
pressurized proppant (that may be mixed with a fracturing fluid)
through the well 110 and into the underground reservoir 200 to
maintain and/or support the fractures while permitting the flow of
hydrocarbons or other fluids from the formation into the well 110
and toward the surface. FIG. 1 may subdivide the depicted system
into a first subsystem: a fluid addition subsystem 120 for
providing fracturing fluid or a similar medium to the underground
reservoir 200, a second subsystem: a proppant addition subsystem
130 for providing proppant or a similar medium into the fracturing
fluid, a third subsystem: a solvent addition subsystem 140 adapted
to provide a solvent for dissolving the proppant to the underground
reservoir 200, a power subsystem 150 for providing power to one or
more components of the system 100, and a pressure subsystem 160 for
pressurizing fluid for injection into the underground reservoir
200. The pressure subsystem 160 may comprise a pump in
communication with the fluid and the proppant in order to
pressurize at least one of the fluid and the proppant to a pressure
sufficient to stimulate the underground reservoir 200. In
embodiments, the pump may be in further communication with the
solvent for pressurizing the solvent to a pressure sufficient to
deliver the solvent to the underground reservoir 200.
[0052] It should be understood that the number, type, and
arrangement of components shown in FIG. 1 is only one exemplary
embodiment, and that the depicted illustration is diagrammatic,
intended to conceptually depict one embodiment of the present
system. As such, it should be noted that any number, type, and
arrangement of identical or similar components could be used
without departing from the scope of the present disclosure.
Further, while the depicted embodiment includes multiple subsystems
(120, 130, 140, 150, 160) used in combination, it should be
understood that in various embodiments, the fluid addition
subsystem 120 could be used in the absence of the other subsystems
(130, 140, 150, 160) and/or in combination with conventional
systems and/or components. Similarly, the proppant addition
subsystem 130, the solvent addition subsystem 140, and the power
and pressure subsystems 150, 160 may be used independently or in
combination with conventional systems and/or components without
departing from the scope of the present disclosure.
[0053] In embodiments, the solvent addition subsystem 140 may
comprise elements similar to that of the fluid addition subsystem
120 and the proppant addition subsystem 130. But due to the
corrosive nature of the solvent, embodiments of the solvent
addition subsystem 140 may comprise components including corrosive
resistant interiors. This may reduce the frequency that components
of the solvent addition subsystem 140 may need to be replaced.
[0054] In embodiments, system 100 may comprise a removal subsystem
170 to remove the natural gas from the underground reservoir 200.
The removal subsystem 170 may be incorporated within the pressure
subsystem 160. In embodiments, the mechanism to pump fluids or
other materials may be reversed in order to pump hydrocarbons out
of the underground reservoir 200.
[0055] It is noted that, in embodiments, the removed natural gas
may act as a fuel source for the production of electricity. This
electricity may be used as a power source by system 100 and may be
utilized to run components of system 100 to pump carbon compounds
back into the underground reservoir 200, thus saving money on the
cost of running system 100. A power conversion unit 155 may aid in
this production of the electricity. The power conversion unit 155
may break down the hydrocarbons pumped out of the well 110 (via
combustion) and may produce electricity as well as byproducts, such
as, but not limited to, carbon compounds including CO.sub.2 and
H.sub.2O. The carbon compounds may be captured and subsequently
pumped back into the underground reservoir 200 with the aid of the
electricity (acting as a power source) produced by the power
conversion unit 155. In embodiments, the power subsystem 150 may
encompass the power conversion unit 155.
[0056] Once the underground reservoir 200 is at or near full
volumetric capacity with sequestered CO.sub.2 (at or near discovery
pressure), in embodiments, the proppant may be dissolved by
injecting the aqueous solvent into the well, which may allow the
geologic forces previously resisted by the proppant to collapse and
seal closed the underground reservoir 200. The CO.sub.2 thus may be
trapped within the rock underground.
[0057] FIG. 2 illustrates an exemplary production flowchart diagram
200 of the present disclosure. As shown, produced gas may be
removed using pressure subsystem 160. Once removed, the gas may be
transferred to the power subsystem 150. It is at this point that
the gas may be burned, which may produce CO.sub.2 and H.sub.2O
(1BCF of CH.sub.4 generates 11 MM gallons of pure fresh H.sub.2O),
both of which may be captured and at least temporarily stored in
appropriate storing chambers 210.
[0058] FIG. 3 illustrates an exemplary CH.sub.4 recovery flowchart
diagram 300 of the present disclosure. In some instances, it may be
feasible/desirable to periodically re-inject CO.sub.2 into the
depleting shale reservoir which induces greater desorption of
CH.sub.4 and thus more natural gas production. This may be carried
out using pressure subsystem 160. The pressure subsystem 160 may
comprise a dual inlet/outlet and associated transferring equipment
that may allow simultaneous extraction and transport of CH.sub.4
and CO.sub.2. This is because shale reservoirs often more
adsorptive of CO.sub.2 than CH.sub.4. See reference below.
[0059] FIG. 4 illustrates an exemplary CO.sub.2 top-off flowchart
diagram 400 of the present disclosure. Upon completion of the
cycle, according to an embodiment a process may result in the
sequestration of more CO.sub.2 than is generated from electric
power made with the produced CH.sub.4. In one aspect, a result may
be low cost ubiquitously available electricity accompanied by
profound net decreases in planetary CO.sub.2.
[0060] According to disclosed subject matter, produced/vacating gas
provides a permanent container or containment for all of the
CO.sub.2 this production creates upon combustion, and further may
provide containment for even greater volumes of CO.sub.2 removed
directly from the atmosphere by the system 100 when electric
generation operations are not fully underway or idled. In
embodiments, machinery that may extract additional CO.sub.2 from
the atmosphere may be utilized in connection with other components
of system 100.
[0061] FIG. 5 illustrates an exemplary dissolved proppant flowchart
diagram 500 of the present disclosure. In a final stage, the
proppant may be dissolved to allow permanent closure of the
fractures by the enormous geologic pressure that has been
temporarily resisted by the proppant particles. Once sealed, the
CO.sub.2 may be stored in the rock throughout geologic time and may
not be vulnerable to loss of the integrity of the well bores used
to access the reservoir.
[0062] FIG. 6 displays a method 600 for storing carbon compounds in
an underground reservoir. Method 600 may comprise injecting
proppant into an underground reservoir 200. The proppant may be
injected using a proppant addition subsystem 130. Additionally, a
fluid addition subsystem 120 may provide fluid to the underground
reservoir in addition to the proppant. Once injected, the proppant
may fracture the underground reservoir 200, allowing for
accessibility of hydrocarbons. The hydrocarbons may be removed from
in situ loci within the underground reservoir 200 using a pressure
subsystem 160.
[0063] Once extracted, the hydrocarbons may be converted into
electricity via processing of the hydrocarbons. The conversion may
include, in embodiments, capturing a byproduct from the converting
of the hydrocarbons into electricity. In embodiments, the byproduct
may include carbon compounds. Once the hydrocarbons are processed,
carbon compounds created during the processing may be injected into
the underground reservoir 200. This may be carried out using the
pressure subsystem 160. In embodiments, the pressure subsystem 160
may comprise reversible components so that pumping out of the
ground and into the ground may be accomplished. After the desired
amount of carbon compounds have been injected into the underground
reservoir 200, the proppant transferred into the underground
reservoir may be dissolved. This may allow for the collapsing of
the underground reservoir 200 and the trapping of the carbon
compounds.
[0064] FIG. 7 illustrates an exemplary production flowchart diagram
of the present disclosure. The natural gas/methane which has been
extracted may be used for electric power generation. The CO.sub.2
that is formed upon combustion of the natural gas in the electric
generator may be separated and captured to be re-injected into the
shale fractures for permanent sequestration. Large quantities of
pure water (H.sub.2O) may also be formed when the natural gas is
burned with pure oxygen (O.sub.2) rather than air.
[0065] FIG. 8 illustrates an exemplary production flowchart diagram
of the present disclosure. Additional ambient CO.sub.2 captured
from the atmosphere may be added to the sequestration injection
stream, given the shales may be many times more absorptive of
CO.sub.2 than the original methane.
[0066] FIG. 9 illustrates an exemplary production flowchart diagram
of the present disclosure. Additional ambient CO.sub.2 captured
from the atmosphere may be added to the sequestration injection
stream, which may be shown being injected into the shales.
[0067] Further, in an embodiment, system 100 may provide back-up
electrical power for the intermittent interruption in power
generation provided by wind, wave, and solar devices.
[0068] In embodiments, underground reservoir 200 may be a shale
reservoir.
[0069] In embodiments, hydrocarbons other than CH.sub.4 may be
extracted from one or more underground reservoirs 200 and
subsequently processed.
[0070] In embodiments, the fracturing fluid may comprise light
weight alkanes.
[0071] In embodiments, the specialized proppant may be dissolved by
injecting a low pH fluid into a fracture system.
[0072] In embodiments, the light weight alkanes may be
recoverable.
[0073] In embodiments, pumps may be needed for the CO.sub.2.
[0074] The following references are relied upon, and are hereby
incorporated in their entirety:
[0075] Numerical Simulation and Modeling of Enhanced Gas Recovery
and CO.sub.2 Sequestration in Shale Gas Reservoirs (Amirmasound K.
Dahaghi, West Virginia University, Society of Petroleum Engineers
2010).
[0076] Carbon Dioxide Storage Capacity of Organic-Rich Shales (S.
M. Kang, E. Fathi, R. J. Ambrose, I. Y. Akkutlu, and R. F. Sigal,
The University of Oklahoma, Society of Petroleum Engineers
2011).
[0077] https://www.netl.doe.gov/publications/proceedings/01/c
arbon_seq/7bl.pdf
[0078]
http://mitei.mit.edu/news/new-way-capture-co2-emissions-lower-costs-
-easier-installation
[0079]
https://www.globalccsinstitute.com/content/how-ccs-works-capture
[0080]
http://www.ccsassociation.org/index.php/what-is-ccs/capture/post-co-
mbustion-capture/
[0081]
http://www.ccsassociation.org/what-is-ccs/capture/oxy-fuel-combusti-
on-systems/
[0082] In embodiments, the proppant may be boron laced meso-porous
amorphous silica.
[0083] While various embodiments usable within the scope of the
present disclosure have been described with emphasis, it should be
understood that within the scope of the appended claims, the
present invention can be practiced other than as specifically
described herein.
* * * * *
References