U.S. patent application number 12/875948 was filed with the patent office on 2011-08-18 for system and process for flue gas processing.
Invention is credited to Marc Vianello.
Application Number | 20110198095 12/875948 |
Document ID | / |
Family ID | 44368837 |
Filed Date | 2011-08-18 |
United States Patent
Application |
20110198095 |
Kind Code |
A1 |
Vianello; Marc |
August 18, 2011 |
SYSTEM AND PROCESS FOR FLUE GAS PROCESSING
Abstract
The present invention is directed to a new and improved method
for sequestration of carbon dioxide, the method including the steps
of injecting a carbon dioxide-containing injection gas into a
subsurface containment region with a series of captures zones;
providing sufficient time for said injection gas to at least
partially stratify and form constituent gas mixtures which at least
partially accumulate in the capture zones; providing a vent
associated with one of the capture zones; and, evacuating at least
a portion of the constituent mixtures through the associated
vent.
Inventors: |
Vianello; Marc; (Prairie
Village, KS) |
Family ID: |
44368837 |
Appl. No.: |
12/875948 |
Filed: |
September 3, 2010 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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61304580 |
Feb 15, 2010 |
|
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Current U.S.
Class: |
166/372 ;
405/53 |
Current CPC
Class: |
Y02C 10/14 20130101;
Y02C 20/40 20200801; E21B 41/0064 20130101 |
Class at
Publication: |
166/372 ;
405/53 |
International
Class: |
E21B 43/00 20060101
E21B043/00 |
Claims
1. A method for sequestration of carbon dioxide, said method
including the steps of: injecting a carbon dioxide-containing
injection gas into a subsurface containment region having a series
of captures zones; providing sufficient time for said injection gas
to at least partially stratify forming constituent gas mixtures and
for said constituent mixtures to at least partially accumulate in
said capture zones; providing a vent associated with one of said
capture zones; and, evacuating at least a portion of one of said
constituent mixtures through said vent.
2. The method of claim 1, wherein said injection gas is a flue
gas.
3. The method of claim 1, further comprising a compression source
for injecting said injection gas.
4. The method of claim 1, further comprising the step of
pressurizing said containment region.
5. The method of claim 1, wherein said evacuated constituent
mixture includes carbon dioxide, said method further including the
step of reinjecting said evacuated constituent mixture into said
containment region.
6. The method of claim 1, further comprising the step of enclosing
said containment region with a sealing surrounding surface.
7. A method for enhanced recovery of hydrocarbons and sequestration
of carbon dioxide, said method comprising the steps of: injecting a
carbon dioxide-containing injection gas into a subsurface
containment region, said containment region further comprising a
series of captures zones and being associated with a
hydrocarbon-bearing oil zone, whereby at least a portion of said
injection gas contacts said oil zone; providing sufficient time for
said injection gas to at least partially stratify forming
constituent gas mixtures and for said constituent mixtures to at
least partially accumulate in said capture zones; providing a vent
associated with one of said capture zones; evacuating at least a
portion of one of said constituent mixtures through said vent; and,
producing said hydrocarbons from said containment region.
8. The method of claim 7, wherein said injection gas is injected
into said containment region under conditions of miscibility with
at least a portion of said hydrocarbons.
9. The method of claim 7, further comprising the step of capturing
carbon dioxide from said produced hydrocarbons.
10. The method of claim 9, further comprising the step of
reinjecting said captured carbon dioxide into said containment
region.
11. The method of claim 7, wherein said injection gas is a flue
gas.
12. The method of claim 7, wherein said injection gas is injected
using a compression source.
13. The method of claim 7, further comprising the step of
pressurizing said containment region.
14. The method of claim 7, wherein said evacuated constituent
mixture further comprises a proportion of carbon dioxide, and said
method includes the step of reinjecting said constituent mixture
into said containment region.
15. The method of claim 7, further comprising the step of providing
a sealing surrounding surface enclosing said containment region.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims priority under 35 U.S.C. 119(e) and
37 C.F.R. 1.78(a)(4) based upon copending U.S. Provisional
Application, Ser. No. 61/304,580 for SYSTEM AND PROCESS FOR FLUE
GAS PROCESSING, filed Feb. 15, 2010, the disclosure of which is
incorporated herein by reference.
FIELD OF THE INVENTION
[0002] The present invention relates to a system and process for
flue gas processing, more specifically to a system and process for
processing and sequestration of flue gas constituents in subsurface
structures. The present invention also relates to a system for
using the gas processing to enhance hydrocarbon recovery from low
pressure subsurface geological formations.
BACKGROUND OF THE INVENTION
[0003] Increasing concentrations of greenhouse gases, including
carbon dioxide, in the atmosphere are a subject of concern. It is
feared that emission of these gases into the atmosphere could lead
to global warming, sea-level changes, and different weather
patterns, among other detrimental effects. Controlling the release
of these gases into the atmosphere is thus an increasingly
important concern. Response to this concern has lead to
governmentally limited prohibitions and restrictions on carbon
dioxide emissions, or fees associated with the emissions of such
gases. Those approaches lead to high economic costs for industries
that emit green house gases, especially those that emit flue gases
into the atmosphere.
[0004] In order to meet past and new emissions standards, several
approaches have been developed to make flue gases cleaner. Some
approaches to reduce the emissions of undesired particulates within
various gases include using above ground technologies such as
adsorption by micro porous solids and absorption by chemical
solvents. Other approaches include the geosequestration of purified
gas in underground formations. However, current technologies have
not developed systems or processes that make large scale
sequestration of CO.sub.2 financially feasible.
[0005] Rather than sequestering the CO.sub.2, which currently is
not financially feasible for most large-scale operations, some
methods utilize it in purified form to enhance oil recovery from
underground formations. However, using purified CO.sub.2 for this
purpose also presents a number of problems for the producer of the
well. In most large-scale enhanced oil recovery operations
utilizing purified CO.sub.2, the primary cost of the recovery is
the purchase of CO.sub.2, which may represent operating costs as
much as 68% of the total cost of the revenue from the project. The
cost of acquiring purified CO.sub.2 in large quantities is driven
by the very high cost of separation of CO.sub.2 from flue gases and
its subsequent transportation to the sequestration site where it
can then be injected into the subsurface formation. Moreover, the
relative cost of large scale CO.sub.2 capture, injection, and
sequestration increases as oil prices decline.
[0006] Traditional configurations for hydrocarbon recovery
processes require subterranean depths of greater than eight hundred
meters, with a sufficient trapping mechanism and sufficiently
porous geological texture to handle large volumes of injected
gases. Different trapping mechanisms occur which vary depending on
the associated structure and desired duration of the sequestration.
In addition, traditional configurations require subsurface
containment regions capable of receiving high flow injection rates
under very high injection pressures to sustain CO.sub.2
sequestration. Using the present invention, CO.sub.2 sequestration
is achievable at relatively shallower levels with reduced injection
flow rates and pressures.
[0007] Despite the prior art's predominant usage of purified
CO.sub.2 in enhanced recovery methods, it is also possible to
enhance the oil recovery process by using gases of differing
compositions, such as those with compositions similar to common
flue gases. Constituents of these mixtures may be at least
partially soluble in hydrocarbons contained in the underground
formation and in many situations the resulting solutions will
experience a more favorable mobility due to decreased viscosity. In
addition, the resulting low-cost pressurization of the underground
containment region may promote increased recovery.
[0008] Moreover, potential sequestration locations for CO.sub.2
injection are seldom located in close proximity to coal-fired
electric power plants and other large scale flue gas sources. The
cost of transporting purified liquid CO.sub.2 by truck or pipeline
is considerable. This circumstance exists for nonsequestration
commercial markets of CO.sub.2 as well. Therefore, the significant
costs of carbon capture include the additionally significant costs
of transporting liquefied CO.sub.2 by tanker truck or pipeline. The
combination of such energy costs and limited commercial demand for
CO.sub.2 do not make the sale of CO.sub.2 captured by above-ground
mechanical technologies commercially viable in many situations. For
these reasons, neither sequestration nor the commercial sale of
purified CO.sub.2 are generally considered sufficient, practical,
or financially feasible for utilizing all of the CO.sub.2 contained
in flue gases.
[0009] Additionally, the capital costs of the equipment necessary
for large-scale separation and capture of CO.sub.2 from power plant
flue gases are enormous, generally in excess of $1.2 billion per
plant.
[0010] Furthermore, the cost of large-scale separation and capture
of CO.sub.2 from flue gases has generally been considered
commercially prohibitive for waste disposal due to the enormous
volumes of energy required to condense the gases to the point where
liquid CO.sub.2 can be extracted. For a coal-fired electric power
plant, estimates are that the energy cost of CO.sub.2 separation
can exceed by 30% to 40% the electricity production capacity of the
plant. The result of combined capital and energy cost of
large-scale CO.sub.2 separation and capture from power plant flue
gases could be very substantial increases in the price of
electricity to consumers. Some estimates are that costs to
consumers would need to double for the method of disposal to become
commercial viability.
[0011] Some prior attempts at utilizing hydrocarbon recovery
techniques have been described in Screening and Ranking of
Hydrocarbon Reservoirs for CO.sub.2 Storage in the Alberta Basin,
Canada by Buchu, which is incorporated by reference.
[0012] Heretofore, there exists a need for an improved system and
process for hydrocarbon recovery using emission gases sequestered
in geological strata.
SUMMARY OF THE INVENTION
[0013] The present invention is directed to a method for
sequestration of carbon dioxide, said method comprising the steps
of injecting a carbon dioxide-containing injection gas into a
subsurface containment region, said containment region further
comprising a series of captures zones; providing sufficient time
for said injection gas to at least partially stratify forming
constituent gas mixtures and for said constituent mixtures to at
least partially accumulate in said capture zones; providing a vent
associated with one of said capture zones; and, evacuating at least
a portion of one of said constituent mixtures through said
vent.
DETAILED DESCRIPTION OF THE INVENTION
[0014] As required, detailed embodiments of the present invention
are disclosed herein; however, it is to be understood that the
disclosed embodiments are merely exemplary of the invention, which
may be embodied in various forms. Therefore, specific structural
and functional details disclosed herein are not to be interpreted
as limiting, but merely as a representative basis for teaching one
skilled in the art to variously employ the present invention in
virtually any appropriately detailed structure.
[0015] An exemplary embodiment of the system and process for
production of hydrocarbon using the sequestration of carbon dioxide
is comprised of a flue gas source, a subsurface containment region,
which may include a brine zone, an oil zone, and plural capture
zones. The subsurface containment region is in communication with a
compression source spaced apart from the subsurface containment
region. Additionally, the subsurface containment region includes a
vessel, a formation, or other structure which surrounds its
perimeter. As illustrated, the flue gases are injected into the
subsurface containment region from the compression source and are
dispersed throughout. Flue gases associated with a brine zone would
permeate through the brine material separating some of the
constituent gases from the flue gas into soluble CO.sub.2 and other
insoluble gases. As these constituent gases are separated, they are
allowed to migrate. Exemplary processes include the migration of at
least a portion of the insoluble gases into a hydrocarbon fluid
reservoir, where the additional soluble CO.sub.2 permeates the
fluid hydrocarbons, enhancing the transport characteristics of the
hydrocarbon and thereby enhancing the hydrocarbon production. In
other processes, the insoluble CO.sub.2 is allowed to migrate to
structurally higher areas of the subsurface containment region. Any
CO.sub.2 retained in the hydrocarbon zone may be extracted through
hydrocarbon production, captured at the surface, and reinjected
into the subsurface containment region for use in various
embodiments of this invention.
[0016] Flue gases from various industrial processes may be utilized
in the present invention and may be processed prior to introduction
into the subsurface containment region. Alternatively, the present
invention may remove some contaminants from the flue gas through a
filtering or separation processes. Typically, the industrial flue
gas may be processed during or in association with the industrial
process by strippers or scrubbers.
[0017] In one embodiment, the flue gas 14 is processed to remove at
least a portion of (1) undesirable particles, (2) sulfur dioxide,
(3) nitrous oxides and (4) moisture content. The resulting flue gas
may have a composition that is, for example, 10.73% CO.sub.2, 1.39%
CO 0.76% NO.sub.x, 0.03% SO.sub.2, and 87.09% air, although
percentages of constituent gases may vary. The greater the
concentration of CO.sub.2, the more desirable the flue gas is for
application of this invention. Carbon Capture And Storage (CCS) in
Nigeria: Fundamental Science and Potential Implementation Risks,
Galadima & Garba (2008 SWJ Vol 3, No. 2): pgs 95-99; and The
Future of Carbon Capture and Storage (CCS) in Nigeria, Anastassia
et al., (2009 SWJ Vol. 4, No. 3):1-6 which are attached hereto and
incorporated by reference.
[0018] The composition and proportions of the flue gas and its
contaminants may vary depending on the specific industrial process
utilized. If solvent absorption of carbon dioxide is used for the
sequestration, and monoethanolamine is the solvent, reactions with
diatomic oxygen, nitrous oxides, and sulfoxides may lead to
numerous operational problems such as foaming, fouling, increased
viscosity, and formation of undesirable salts. Diatomic oxygen
concentrations in the range of about 3% to 12% in typical flue gas
streams are known to induce oxidative degradation of alkanolamines,
resulting in severe corrosion of associated piping. Thus the
proportion of oxygen should be minimized or oxygen inhibitors
employed. Additional information on contaminants and flue gas
processing is disclosed in Supap, T; Idem, R.; Tontiwachwuthikul,
P.; Saiwan, C. Analysis of monoethanolamine and its oxidative
degradation products during CO.sub.2 absorption from flue gases: A
comparative study of GC-MS, HPLC-RID, and CE-DAD analytical
techniques and possible optimum combinations. Industrial &
Engineering Chemistry Research, 2006, 45 (8), 2437 which is
incorporated by reference.
[0019] While the invention discloses using flue gas, other CO.sub.2
containing gases may be utilized in the present invention. While
pressurization of subterranean formations may be generally
understood, by using a CO.sub.2 enriched gas, unexpected benefits
may be achieved through the enhanced liquidity of the fluid
hydrocarbon as well as a reduction in the pressures necessary to
achieve hydrocarbon recovery.
[0020] In one embodiment, the flue gases may be injected into the
subsurface containment region through a compression source such as
an injection well extending from the surrounding structure opposite
the subsurface containment region into the subsurface containment
region. See for example American Petroleum Institute, 2007,
Background Report, "Summary of Carbon Dioxide Enhanced Oil Recovery
(CO.sub.2 EOR) Injection Well e Technology", 1220 L Street NW,
Washington, DC, attached hereto and incorporated by reference. In
addition, various textured surfaces may enhance the capacity of the
subsurface containment region as well as allowing for an increase
in the efficiency of the sequestration and hydrocarbon recovery.
Some exemplary subsurface containment regions may include depleted
oil and gas reservoirs, saline aquifers, coal beds and artificial
vessels designed to sustain the hydrocarbon production. The
injection well, which may be in communication with a production
well, would inject the flue gases into the subsurface containment
region. As the flue gases enter the subsurface containment region,
through the process described above, the flue gas would separate
for immersion of the fluid hydrocarbon by the separated soluble
CO.sub.2. Optionally, the subsurface containment region may be
sealed from the ambient surface environment allowing for additional
separation of the CO.sub.2 from the flue gas and for additional
saturation of the fluid hydrocarbon by soluble portions of the
separated CO.sub.2.
[0021] The flue gas when initially injected into the subsurface
containment region is a mixture of constituent gases. Subsequent to
the injection, the flue gas stratifies, at least partially, into
zones of concentration of individual constituent gases dispersed
throughout the subsurface containment region. Multiple molecular
processes contribute to the stratification. Additionally, the
proportions of a constituent gas in a zone of concentration vary
over time depending on the stratifying molecular process. The
constituent gases have different relative densities, thus after
being injected into the subsurface containment region, there is
some tendency for the constituent gases to partially stratify over
time. Because CO.sub.2 is about 50% heavier than the average
molecular weight of other constituent gases in air, those other
constituent gases will tend to rise relative to the CO.sub.2
resulting in at least two zones of concentration, with air
concentrating above the CO.sub.2. Because gaseous CO.sub.2 is
lighter than oil and water, insoluble CO.sub.2 will tend to rise
above those oil and water zones.
[0022] Other molecular processes that contribute to zones of
concentration include but are not limited to adsorption. The
adsorption properties of constituent gases in relationship to the
within the subsurface containment region leads to zones of
concentration. For example, if the subsurface containment region is
an abandoned coal seam, affinity for adsorption of carbon dioxide
over methane may be exploited to achieve a zone of concentration of
carbon dioxide. This affinity may result in enhanced production of
methane gas form the coal seam. If the subterranean structure has
capillary structure, the different constituent gases of the flue
gas travel through that capillary structure at different rates and
thus zones of concentration may form. Further disclosure of
apparatus and processes in separation of gases in this environment
is in Effect of Heterogeneity in Capillary Pressure on Buoyancy
Driven Flow of CO.sub.2, Ehsan Saadatpoor, Steven L. Bryant, Kamy
Sepehrnoori, available at
http://www.cpge.utexas.edu/gcs/pubs/buoyancy_driven_flow_slides.pdf,
which is incorporated by reference.
[0023] Upon stratification, a capture zone is associated with a
given constituent gas. The constituent gas can then be directed for
containment, reinjection, or elsewhere in the process. Gas vents,
such as evacuation ducts, are associated with a desired capture
zone in order to direct the contents of the capture zone to another
desired location. In the case of a capture zone associated with
carbon dioxide, the gas may be redirected to an injection well for
resequestration into a non-capture zone such as a hydrocarbon zone
to achieve incrementally enhanced hydrocarbon recovery. It may also
be directed to a system for enhanced hydrocarbon recovery. The
evacuation ducts are associated with capture zones and thus may be
placed at varying depths or associated with any location where
stratification may occur.
[0024] After a portion of the CO.sub.2 is sequestered from the flue
gas, it may diffuse through the pores of the subsurface containment
regions or the associated brine and hydrocarbon zones. Saline
structures may also present additional characteristics for
containing the sequestered CO.sub.2 or an impermeable capping
material may be located between the injection well and the injected
flue gases to seal the injected gases. The impermeable cap may
include but is not limited to solid, liquid, or gaseous materials
which limit undesired migration of sequestered CO.sub.2.
[0025] In an alternative embodiment, surface compression may be
utilized to inject the flue gas into the subsurface containment
region passing at least one subsurface geological zones comprised
of brine, hydrocarbons, a mixture of brine and hydrocarbons, air,
soil, or artificial structures. Generally, "brine" consists of
non-potable water and "hydrocarbons" consist of crude oil and/or
natural gas. "Miscibility" is the ability of two or more substances
to form a single homogeneous phase when mixed in certain
proportions. For petroleum reservoirs, miscibility is the physical
condition between two or more fluids that will permit them to mix
in certain proportions without the existence of an interface. If
two fluid phases form after some amount of one fluid is added to
others, the fluids are considered "insoluble" under those
conditions.
[0026] In order to enhance the oil recovery, the carbon dioxide is
preferably soluble with the associated reservoir oil. The
solubility of CO.sub.2 and other injected gases depends upon
factors such as reservoir temperature, reservoir pressure, injected
gas composition, and oil chemical composition. The enhanced
recovery processes involve manipulating these conditions to achieve
miscibility between the injected gas and the oil.
[0027] The oil reservoir pressure at the start of a conventional
CO.sub.2 flood should be at least 1.38 MPa above the minimum
miscibility pressure (MMP) to achieve miscibility between CO.sub.2
and reservoir oil. This means that the ratio between reservoir
pressure and minimum miscible pressure normally should be >1.
During the enhanced oil recovery (EOR) also referred to as the
secondary stage of oil recovery, the typical subsurface containment
region for EOR may have various degrees of suitability, depending
on the intrinsic subsurface characteristics and the chemical
composition of the oil mixture. The range of reservoir and fluid
properties suitable for CO.sub.2 miscible injection is quite wide;
however, exemplary reservoirs should have oil API gravity
>27.degree. (light oils with density <900 kg/m3), oil
saturation So >25%, reservoir pressure >7.6 MPa and ideally
1.4 MPa higher than the minimum miscible pressure (MMP) at the time
of CO.sub.2 injection. In addition, the containment barrier
porosity should be greater than 15% with permeability >1 md.
Immiscible CO.sub.2 flooding is much less common; nevertheless it
may be applied to heavy and medium oils (10-25.degree. API;
900-1000 kg/m3 density) and in-situ viscosities of 100 to 1000
mPa/s (cp).
[0028] Some limited studies have shown that, under cyclic
immiscible recovery conditions, gas injection mixtures containing
from 10-25% CO.sub.2 have achieved exceptional oil recovery. More
discussion on enhanced oil recovery results in varying conditions
is disclosed in Rivas, O., Embid, S., and Bolivar, F., 1994.
Ranking reservoirs for carbon dioxide flooding processes. SPE Paper
23641, SPE Advanced Technology Series, v. 2 (Rivas et al., 1994),
which is incorporated by reference.
[0029] In another alternative embodiment, the flue gas may be
injected directly into an oil zone or a brine zone of the
subsurface containment region, where at least some quantity of
CO.sub.2 from a capture zone is employed. Disclosure of
sequestration of CO.sub.2 is included in U.S. Pat. App. Nos.
20070215350 and 20100000737, which are incorporated by
reference.
[0030] After sequestering the CO.sub.2 from the flue gases, the
sequestered gases may be further separated by the Brine Zone,
physically, mechanically or chemically through a reaction process
such as but not limited to forming carbonic acid, and then any
remaining sequestered gases may be transported to the Oil Zone,
where at least some additional quantity of CO.sub.2 is extracted
from the flue gas via a molecular process. The non-soluble gases
may be separated from the Oil Zone and be transported for capture
at Zones 1, 2 or 3 depending on the specific configuration and
relative density of the separated gases.
[0031] Optionally, the extraction of quantities of CO.sub.2 from
the flue gas injected into the brine zone or oil zone may be
further increased if the subsurface containment region is
pressurized. The pressurization may be increased to a point
approaching but not equaling the fracture gradient of the
subsurface containment region in order to achieve pressures and
temperatures of greater solubility of CO.sub.2 with formation
liquids and/or to increase the drive mechanism to enhance the
recovery of hydrocarbons. "Fracture gradient," measured in pounds
per square inch per feet depth, is the pressure that if applied to
rock or similar object within a subsurface containment region, will
cause that rock to physically fracture. The subsurface pressure of
said subsurface containment region may be increased by one or more
means such as mechanical compression at the surface of the injected
flue gas, flooding the formation with water, and adding chemical
agents to the flue gas and/or to the subsurface brine and/or
hydrocarbon bearing zones. U.S. Pat. Nos. 6,491,053, 7,506,690,
7,341,102, 6,318,468 and 4,744,417 involve processes and apparatus
for enhanced hydrocarbon recovery using CO.sub.2 at varying
pressures and is incorporated by reference.
[0032] In yet another embodiment, the non-soluble gases that filter
through the brine zone or through the oil zone may be isolated from
the ambient environment to allow the CO.sub.2 and other gases to
separate according to their relative densities. Because CO.sub.2 is
about 50% heavier than air, the air component of the flue gas will
tend to rise relative to the CO.sub.2 resulting in at least two
zones of concentration, with air concentrating above the CO.sub.2.
Because CO.sub.2 is lighter than oil and water, non-soluble
CO.sub.2 will tend to rest on top of those zones.
[0033] In yet another embodiment, the contents of a capture zone
having a constituent gas other than CO.sub.2 may be directed
outside the subsurface containment region into the atmosphere under
controlled conditions, making the evacuated capture zones available
for receipt of additional gasses. In this embodiment, at least one
vent associated with at least one of the capture zones and
associated with at least one constituent gas is used to extract at
least some of the constituent gas through the associated vent at
the desired capture zone.
[0034] The nature of CO.sub.2 leakage behavior will depend on
properties of the subterranean structure, primarily its
permeability, and on the thermodynamic and transport properties of
CO.sub.2 as well as other fluids with which it may interact in the
subsurface. At typical temperature and pressure conditions in the
shallow crust (depth <5 km), CO.sub.2 is less dense than water,
and therefore is buoyant in most subsurface environments. Upward
migration of CO.sub.2 will occur whenever appropriate vertical
permeability is available. Potential pathways for CO.sub.2
migration to structurally high areas of subsurface containment
regions include (1) migration through porous rock, and (2)
migration along faults or fractures. More disclosure on CO.sub.2
migration is in Assessment of the CO.sub.2 Sealing Efficiency of
Pelitic Rocks: Two-Phase Flow and Diffusive Transport, paper 536,
presented at 7th International Conference on Greenhouse Gas Control
Technologies, Vancouver, Canada. Sep. 5-9, 2004; Zweigel, P., E.
Lindeberg, A. Moen and D. Wessel-Berg. Towards a Methodology for
Top Seal Efficacy Assessment for Underground CO.sub.2 Storage,
paper 234, presented at 7th International Conference on Greenhouse
Gas Control Technologies, Vancouver, Canada. Sep. 5-9, 2004;
Gibson-Poole, C. M., R. S. Root, S. C. Lang, J. E. Streit, A. L.
Hennig, C. J. Otto and J. Underschultz; Conducting Comprehensive
Analyses of Potential Sites for Geological CO2 Storage, paper 321,
presented at 7th International Conference on Greenhouse Gas Control
Technologies. Vancouver, Canada. Sep. 5-9, 2004; Lindeberg, E. The
Quality of a CO.sub.2 Repository: What is the Sufficient Retention
Time of CO2 Stored Underground?, in: J. Gale and Y. Kaya (eds.),
Greenhouse Gas Control Technologies, Elsevier Science, Ltd.,
Amsterdam, The Netherlands, 2003; and Espie, T. Understanding Risk
for the Long-Term Storage of CO.sub.2 in Geologic Formations, paper
42, presented at 7th International Conference on Greenhouse Gas
Control Technologies. Vancouver, Canada. Sep. 5-9, 2004, which are
incorporated by reference.
[0035] In yet another embodiment, a portion of any CO.sub.2 and
other constituent gases not associated with capture zones is
captured proximately in the upper portion of the subsurface
containment region. The gas composition is optionally monitored to
detect higher proportions of the flue gas constituent gases and
pressure flows. The subsurface containment region may be provided
with a mechanical body, such as a gas containment layer, disposed
near its upper portion. Disclosure of monitoring and gas
containment systems is in U.S. Pat. Nos. 7,448,828 and 5,063,519,
which are incorporated by reference. The contents of the mechanical
body are re-injected through secondary compression back into the
subsurface containment region under miscible or immiscible
conditions, repeating the injection process previously described as
desired.
[0036] In yet another embodiment, the contents of a CO.sub.2
associated capture zone are directly produced via conventional gas
production means. In this embodiment, at least one vent associated
with a CO.sub.2 capture zone within the subsurface containment
region is used to direct at least some of the constituent gas
through the associated vent. In a further embodiment, the
constituent gas directed from a CO.sub.2 associated capture zone is
re-injected through secondary compression back into the subsurface
geological formation under miscible or immiscible conditions using
secondary compression. Optionally, the gas directed from the
CO.sub.2 associated capture zone is injected directly into an oil
zone.
[0037] In yet another embodiment, the injected flue gas may be
shut-in for a period of time to allow the injected gases to soak in
the brine and/or hydrocarbon zones of the subsurface containment
region. The injected flue gas may alternatively be shut-in for a
period of time to allow the partial or complete stratification of
flue gases, where the constituent gases stratify according to their
relative densities. Each constituent gas is associated with a
relative capture zone for release from the subsurface containment
region.
[0038] In yet another embodiment, gaseous CO.sub.2 from the flue
gas not associated with a capture zone or not directed from a
capture zone is stored in the subsurface containment region by
sealing its surrounding surface using known techniques, such as a
containment barrier around the perimeter of the subsurface
containment region. The containment barrier is composed of material
with low gas permeability. The barrier may be composed of existing
natural material such as caliche, calcrete, silicrete.
Alternatively, the containment barrier may be composed of manmade
material. U.S. Pat. App. No. 20090220303 discloses using
containment barriers in sequestration and is incorporated by
reference.
[0039] While the foregoing detailed description has disclosed
several embodiments of the invention, it is to be understood that
the above description is illustrative only and not limiting of the
disclosed invention. It will be appreciated that the discussed
embodiments and other unmentioned embodiments may be within the
scope of the invention.
* * * * *
References