Note: Descriptions are shown in the official language in which they were submitted.
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PROCESS FOR SEQUESTRATION OF FLUIDS IN GEOLOGICAL
FORMATIONS
FIELD OF THE INVENTION
[0001] The present invention relates to subsurface sequestration of fluids,
and in particular to the sequestration of water-soluble gases such as CO2 and
other greenhouse gases in water-laden geological formations.
BACKGROUND OF THE INVENTION
[0002] This invention claims priority to United States Patent Application
Nos. 61/159,335 filed on March 11, 2009 and 61/173,301 filed on April 28,
2009.
[0003] Human activities have an impact upon the levels of greenhouse
gases in the atmosphere, which in turn is believed to affect the world's
climate.
Changes in atmospheric concentrations of greenhouse gases have the effect of
altering the energy balance of the climate system and increases in
anthropogenic greenhouse gas concentrations are likely to have caused most of
the increases in global average temperatures since the mid-20th century.
Earth's
most abundant greenhouse gases include carbon dioxide, methane, nitrous
oxide, ozone and chlorofluorocarbons. The most abundantly-produced of these
by human industrial activity is CO2.
[0004] Various strategies have been conceived for permanent storage of
CO2. These forms include sequestration of gases in various deep geological
formations (including saline aquifers and exhausted gas fields), liquid
storage in
the ocean, and solid storage by reaction of CO2 with metal oxides to produce
stable carbonates.
[0005] In a process known as geo-sequestration, CO2, generally in
supercritical (SC) form, is injected directly into underground geological
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formations. Oil fields, gas fields, saline aquifers, un-minable coal seams,
and
saline-filled basalt formations have been suggested as storage sites. Various
physical (e.g., highly impermeable cap-rock), solubility and geochemical
trapping mechanisms are generally expected to prevent the CO2 from escaping
to the surface. Geo-sequestration can also be performed for other suitable
gases.
[0006] Saline aquifers contain highly mineralized brines, and have so far
been considered of little benefit to humans. Saline aquifers have been used
for
storage of chemical waste in a few cases, and attempts have been made to use
such aquifers to sequester CO2. The main advantage of saline aquifers is their
large potential storage volume and their common occurrence. One disadvantage
of any practical use of saline aquifers for this purpose is that relatively
little is
known about them. Leakage of CO2 back into the atmosphere may be a problem
in saline aquifer storage. However, current research shows that several
trapping
mechanisms immobilize the CO2 underground, reducing the risk of leakage.
[0007] The densest concentration of CO2 that can be placed in a porous
formation such as a saline aquifer is when CO2 is in a supercritical state -
referred to herein as SC-0O2. Most sequestration schemes are based on
injection of SC-0O2 in this supercritical state when the material behaves as a
relatively dense compressible liquid with an extremely low viscosity, far
lower
than any formation liquid. The object is to displace most or all of the water
in
the saline aquifer, replacing 100% or some fraction of the porosity with SC-
COB.
[0008] In a prominent example of such a geo-sequestration strategy, the
Sleipner project, operated by the Norwegian oil and gas company StatoilHydro,
separates CO2 (4 to 9.5 % in content) from the natural gas recovered from a
nearby gas well. The separated CO2 is converted to the supercritical (SC- CO2)
form and injected into a salt water-containing sand layer, called the Utsira
Formation, which lies 1000 m below the sea bottom. Several seismic surveys
have been undertaken to investigate whether the storage of CO2 remains secure.
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[0009] Injection of gaseous CO2 (i.e. not in supercritical form) into a
subsurface formation in solution with water at the maximum solubility limit is
a
desirable approach to sequestration of this gas that has been proposed with
mixed success in the past. Prior to the present invention, a problem of
sequestering of CO2 by dissolution in an aqueous solution within geological
formations has been that the porous volume of the formation is occupied far
less
efficiently than the occupation which occurs upon injection of SC-0O2. Once
the
active injection phase is completed, there is no more active mixing within the
porous medium. Thereafter, the dissolution of the CO2 within the formation
water is controlled by the concentration differences, the contact area, and
the
diffusion path length. Mass transfer rates associated with such concentration
gradient-driven diffusion processes in porous media are slow and it is
expected
that thousands of years may be required to approach full dissolution of the
CO2
in the aqueous phase within the geological formation.
[0010] The "reduced-mixing, long-term concentration gradient diffusion"
problem persists even with injection of SC-0O2. At the high injection rates
proposed for SC-0O2 sequestration, the SC-0O2 will first displace water and
occupy the pore space directly, with only a small amount of convective and
dispersive-occurring mixing at the displacement fronts. As SC-0O2 is injected
over time, a growing area of contact is generated between the two fluids and a
dissolution zone is generated. The SC-0O2 then becomes dissolved into the
saline water along this contact area, largely as the result of diffusion and
dispersion associated with forced advection caused by pressure driven flow
(from
injection of the SC-0O2 under pressure).
[0011] Because of the density difference between saline water and SC-0O2,
there are also gravitational forces that will tend to segregate the liquids in
the
saline aquifer: the SC-0O2 will rise above the denser water, forming a
"pancake"
under zones that are finer-grained with poorer permeability (shale streaks,
siltstones, etc.). This not only suppresses part of the mixing component that
would arise in a more uniform displacement, it also leads to a significant
inefficiency in the access to the pore volumes in the formation: portions of
the
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formation remote from the injection point are largely inaccessible to any
storage
mechanism (displacement by or dissolving of CO2 into solution).
[0012] Once the injection ceases, only a small fraction of the SC-0O2 has
gone into solution because of the mixing and diffusive effects at the displace-
ment fronts, and because the advective driving force (injection pressure)
ceases.
The CO2 can no longer be advectively mixed with the water, and this leaves
only
diffusion effects that are driven solely by concentration gradients of CO2 in
the
water.
[0013] In a saline aquifer formation, after injection, the SC-0O2 remains
high in the zone above the injection site due to its lesser density. This
density-
graded system provides a stabilizing force that further reduces the rate of
any
diffusion process. Initially, the diffusion front is relatively narrow and
distinct
with large surface area between the CO2 and water and the solution process
happens relatively efficiently. But over time this front grows and widens
vertically. As a result, the front becomes less distinct. This produces a
thicker
diffusion or transition zone with less surface area between the CO2 and water
that has a low CO2 concentration (i.e. the transition-dissolution-contact area
between the SC-0O2 and the formation water becomes enriched with CO2. The
vertical distance between water from remote regions of the formation and SC-
CO2 grows as CO2-unsaturated water is further away from the SC-0O2. Hence
the diffusion/solution process slows considerably. As a result it can take
many
thousands of years for CO2 to enter into solution, since in situ movement of
water at remote regions of the formation (to facilitate the CO2 in solution
with
water process) is very slow. At this stage, there is no convective mixing
between
the SC-0O2 and the formation water due to the density graded system,
[0014] Density graded systems in porous media are extremely stable over
long times. Once active mixing ceases, it will take thousands of years for SC-
0O2
to become dissolved in the water phase under typical sequestration conditions.
There is simply no mechanism to bring "new water" into contact with the SC-
CO2, and the process becomes totally dominated by slow diffusion.
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SUMMARY OF THE INVENTION
[0015] Although the safe and permanent disposal of CO2 represents an
important challenge, as referred to in detail above, long-term disposal of
other
water-soluble gases and fluids also presents similar challenges, to address
the
greenhouse effect as well as other needs. The present invention thus relates
to
the (essentially) permanent disposal of a wide variety of water-soluble
fluids, by
providing processes and systems for mixing and dispersing of such fluids
within
a water-laden geological formation such as a saline aquifer to improve
sequestration conditions.
[0016] Objects of the present invention include:
a) To provide a method for geo-sequestration of water-soluble
fluids, in particular but not limited to gases, by injection of the fluid into
a water-
laden formation in a manner which improves the mixing of the fluid with
formation water to improve the dissolution of the fluid, through the
generation of
in situ convection currents or convection cells.
b) To increase the volumetric extent of the dissolution process
in the geological formation, thereby improving the storage capacity for water-
soluble fluids (such as CO2) within the formation.
c) To provide a process to enhance both the separation of
water-soluble gases from a mixture of soluble and insoluble gases and the
sequestration of the soluble gases in a geological formation, and to withdraw
the
insoluble gas from the geological formation to preserve the volume of the
geological formation available to accommodate dissolved soluble gas.
d) To provide a method for determining conditions for
sequestration of a water-soluble fluid in a geological formation using a
computer
model of the formation and computer simulations of injection of fluids.
e) To provide an alternative method for enhanced sequestration
of water-soluble gases in geological formations which does not require pre-
injection separation of gases nor conversion of the injected gases to a
supercritical form.
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[0017] In one aspect of the invention, there is provided a process for
sequestration of a water-soluble fluid by injection of the fluid from an
injection
well into a water-laden geological formation under conditions of temperature
and/or pressure selected to cause the fluid to enter and disperse within the
formation with sufficient volume, pressure, and density-contrast with the
formation water to generate a convection current or convection cell within the
formation. A target geological formation comprising an aquifer .is selected
which
is bounded above and optionally also below by layers of low permeability for
containing the water bearing formation in a stable state. The said low
permeability layer can be located either directly above or below the aquifer
or
separated from the aquifer by one or more layers. The injection well extends
into the target formation. The fluid is pressurized and/or heated, and
introduced
into the formation from the injection well so as to generate one or more
convection cells and thereby to enhance dispersal, dissolution and
sequestration
of the fluid, or a water-soluble fraction thereof, within a large region in
the
formation.
[0018] According to this aspect, initial movement of the fluid in the
formation is expected to occur as a low-density displacement front moving
outwardly in the formation as the fluid percolates through the formation. In
the
case of a gas, the gas may disperse initially as bubbles or pockets of
undissolved
gas. This displacement front will displace water within the pore spaces of the
formation which is then driven to flow outwards and away from the percolation
area. This associated water flow contributes to the development of in situ
convention cells or convection currents. The injected fluid will subsequently
develop into a low density plume that spreads laterally as well as moving
vertically upwardly through the formation. This plume is a region of lower
density than the water within adjacent parts of the formation where the
injected
fluid is not present. A lateral contrast in the average fluid density is thus
generated. This process induces a density contrast-driven convective flow
cell.
Hence, a density-driven flow cell is generated wherein the region of lower
density fluid (such as water which is heated and/or contains undissolved gas)
rises vertically because it is less dense than the adjacent formation water.
This
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more dense water then flows laterally to replace the lower density fluid that
flows vertically, sustaining a large-scale convection cell.
[0019] The density contrast driven convection process described herein
enhances mixing of the water-soluble fluid with formation water as the
convection current develops in the formation and enhances the mixing between
the injected fluid and the formation water. The undissolved soluble fluid
enters
into solution, and fresh, fluid-unsaturated water from remote regions of the
formation is brought into contact with additional undissolved soluble fluid.
[0020] In one embodiment, CO2 (usually combined with other gas) is
injected under suitable conditions as described above into a formation that
contains water which is unsaturated with CO2. Unsaturated water from remote
regions in the formation then moves into the region of the injection well as
the
result of the action of the large convection cell, and replaces local (in the
vicinity
of the injection well) CO2-rich water with CO2-free water, which can strip the
CO2
out of the injected gas more efficiently. Furthermore, the large-scale
convection
cell not only increases the diffusive mass transfer of CO2 into solution, it
also
acts to bring remote CO2-free water into the injection well bore region,
thereby
increasing the effective volume in the formation that can be accessed through
one injection well as a result of this flushing action. Thus the density-
driven
convection process provides rapid mass transfer of CO2 into solution and
enhanced storage capacity for geo-sequestration.
[0021] The consequences of implementing this density-driven convection
process are that the short-term storage capacity of the formation increases
and
the long-term capacity also increases through access to lateral water flux
with
maximized mixing.
[0022] The process may comprise injecting a fluid consisting of a mixture
of water-soluble and insoluble gases. In this aspect, a withdrawal well is
provided, which is in fluid communication with the aquifer or in communication
with an insoluble gas pocket in the formation, for withdrawal of the
insoluble,
non-sequestered gas. The water-insoluble gas is withdrawn from the formation
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with the withdrawal well, thereby providing additional volume in the formation
for further sequestration of the water-soluble liquid or gas.
[0023] The process may further include providing one or more water
injection wells into the formation and injecting water into the formation,
thereby
producing a cross current of water within the formation originating from a
region
remote from the injection well. This water injection process further enhances
the
convective current/cell process and water flux in the formation.
[0024] According to another aspect, a plurality of fluid injection wells
may
be provided to generate a plurality of convection currents in the formation,
thereby providing enhanced mixing of the water-soluble liquid or gas in the
formation. The configuration of the wells can be designed to promote the
development of sustained convention currents in the formation. The injection
wells may be horizontal injection wells, vertical injection wells or deviated
wells.
In some embodiments, the injection well defines a path that substantially
intersects the formation vertically, horizontally or at a deviated angle from
the
vertical.
[0026] In some embodiments, the process further includes determining
appropriate placement of one or more openings in the injection well for
discharge of fluid, such that the openings are spaced sufficiently below the
upper
face of the formation to generate a convection current so as to promote
enhanced mixing of the water-soluble fluid with formation water.
[0026] In some embodiments, the injected fluid is flue gas. As used
herein,
the term "flue gas" refers to gas produced by an industrial combustion such as
a
fireplace, oven, furnace, boiler or steam generator, or a recovery process
(such
as recovery of natural gas from a well). Such gases typically exit to the
atmosphere via a flue. The term "flue gas" encompasses combustion exhaust
gas produced at fossil fuel or biomass-burning burning power plants. The
composition of flue gas depends on what is being burned, but it will usually
consist of mostly nitrogen derived from the combustion air, CO2 and water
vapor
as well as excess 02 (also derived from the combustion air). Flue gas may
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further contain methane (CH4), carbon monoxide, hydrogen sulfide, nitrous
oxides and sulfur oxides, as well as particulates.
[0027] In another aspect of the invention, there is provided a process for
determining conditions for sequestration of a water-soluble fluid. The process
employs computer modeling of structure and conditions of a known water-laden
formation. Computer modeling programs for simulating formations are known in
the art. The skilled person will have the knowledge to modify an existing
program or to develop a new program using routine methodology for simulating
water-laden formations as well as the components and conditions employed in
performing the processes described herein. In accordance with this aspect of
the
invention, a computer program stored on a computer readable medium is
provided which includes a representation of a known formation and a fluid
injection well. The computer program is provided with means to vary one or
more of the following parameters: placement of the fluid injection well(s) in
the
formation, partial pressure of gas in the formation, rate of injection of
fluid into
the formation, numbers of injection wells placed in the formation, pH of water
in
the formation, salinity of water in the formation, and density of water in the
formation. The computer program is configured to calculate properties of a
convection cell generated in the formation based on dispersion of fluids in
the
formation which is influenced by one or more of the parameters. A report is
then
produced which provides recommended well patterns and injection conditions
and, optionally, sequestration conditions within the formation. The
sequestration
conditions include the parameters used in determining the properties of the
convection cell which is generated when the recommended conditions are
adhered to.
[0028] In some embodiments, the computer program is further provided
with means to simulate the varying of placement of a plurality of fluid
injection
wells, gas withdrawal wells, and/or water injection wells in the formation.
[0029] The process for determining conditions for sequestration of a water-
soluble fluid described above may then be put into practice by configuring one
or
more injection wells and, optionally, one or more withdrawal wells and/or
water
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injection wells for appropriate placement within the formation according to
the
parameters used to produce the convection cell in the computer simulation.
[0030] The term "gas" as used herein, unless a different meaning is
expressed or implied, means either a gas or combination of gases. Similarly,
"liquid" means either a liquid or combination of liquids, unless a different
meaning is expressed or implied.
[0031] The term "fluid" as used herein, unless a different meaning is
expressed or implied, means: a) a water-soluble liquid; b) a water-soluble
gas;
c) a combination of water-soluble liquids; d) a combination of water-soluble
and
insoluble liquids; d) a combination of water-soluble gases; or e) a
combination of
water-soluble gas and water-insoluble gas. Said liquid or gas may comprise
multiple types of liquids or gases. The fluid has a lower density than the
water
present in the formation to facilitate the generation of a convection current
or
convection cell.
[0032] As used herein, the term "insoluble" is not meant as an absolute
term, but as a relative term which means "poorly soluble" or substantially
less
soluble than a substance recognized by one with skill in the art as "soluble."
[0033] As used herein, the terms "formation" or "water-laden formation"
refer to a subsurface layer of water-bearing permeable rock or unconsolidated
materials such as gravel, sand, silt, or clay, that contains sufficient water
within
its pores to permit generation of a convection current therein. A saline
aquifer
is a non-limiting example of a geological formation suitable for the processes
disclosed herein. The related term "target formation" refers to the formation
selected for injection of liquids or gases for sequestration.
[0034] As used herein, the term "formation water" or "water" refers to
water present within the formation. The formation water may be present in the
formation as a bulk water phase or may be segregated in pockets or droplets
within a geological matrix of gravel sand, silt, or clay. The water may be
saline
or laden with other dissolved substances.
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[0035] As used herein, the terms "low permeability" means less than about
100 millidarcy (mD) and the term "high permeability" means greater than about
300 rnD.
[0036] As used herein, references to CO2 and other liquids or gases refer
to
such fluids in purified, supercritical (in the case of gases) or impure forms.
[0037] These and other advantages of the invention will become apparent
upon reading the following detailed description and upon referring to the
drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0038] FIGURE 1 is a schematic cross-sectional view of a geological
formation with a single horizontal injection well and two horizontal
withdrawal
wells showing the directions of the convection currents produced by gas
injection, and also showing a source of flue gas and components for processing
the gas prior to injection. Cross currents are also shown.
[0039] FIGURE 2 is a schematic cross-sectional view of a geological
formation with three horizontal injection wells and four vertical withdrawal
wells
showing the directions of the convection currents produced by gas injection.
Cross currents are also shown.
(0040] FIGURE 3 is a schematic cross sectional view of an inclined
formation with a single horizontal injection well and a single withdrawal well
showing the direction of a convection current produced by gas injection. Cross
currents are also shown.
[0041] FIGURE 4 is a schematic representation of a gas sequestration
array showing a single injection well, two withdrawal wells and two water
injection wells. Gas pockets within the formation are also shown.
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DETAILED DESCRIPTION
[0042] In the following description of embodiments, similar features are
referred to with similar reference numerals.
[0043] Figure 1 shows one embodiment of the process for injection of flue
gas to sequester the greenhouse gas components thereof. It will be understood
that similar processes may be used to sequester other fluids. Figure 1
illustrates
a schematic cross-sectional view of a subsurface formation 10 located deep
beneath ground surface 5. The formation 10 consists of a deeply buried high
permeability saline aquifer. The formation is bounded at its upper margin and,
preferably, lower margin, by upper and lower layers 60 and 80 having low
permeability. Formation 10 may be disposed in various orientations and
configurations, such as a flattened generally horizontal orientation, or a
sloping
or other configuration (for example, see Figure 3). Formation 10 should have a
region with sufficient top to bottom spacing to permit the generation of
convection currents within the formation water, as will be described in more
detail herein. It is believed that formation 10 should have a region with a
minimum vertical spacing of about 25 to 30 meters. The term "spacing" refers
to the distance "y" shown in Figure 1, that is, the vertical distance between
upper and lower margins of the formation. This region with a vertical spacing
of
at least y should also extend horizontally for a distance of at least about
1000
meters. Injection well 12 has at least one discharge opening 13 within this
region. The range of vertical spacing y may depend upon other factors such as
the pressure and the temperature of the gases emanating from the discharge
opening 13 of injection well 12. However, the inventors do not wish to be
bound
by theory and it is contemplated that under suitable conditions an aquifer
with a
lesser vertical spacing, or wherein the region with this minimum vertical
spacing
extends horizontally to a lesser extent than the above, may be used for the
present invention.
[0044] A source 25 of gas is provided, in which the gas normally consists
of a mixture of gases. In the case of flue gas (raw or CO2 enriched), the gas
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normally consists of a mixture of water-soluble and insoluble gases (such as
nitrogen). In the described example, source 25 comprises a source of flue gas,
such as a fossil-fuel burning power plant or other facility. It will be
apparent
that essentially any stationary source of gas may serve as the source. The gas
mixture includes a water-soluble gas 16 and a water-insoluble gas 18.
Preferably, the water-soluble gas is either a greenhouse gas or other
pollutant.
More preferably, the water-soluble gas is one or more of the following: CO2,
NON,
or hydrogen sulfide. Most preferably, the greenhouse gas is CO2. Preferably,
the water-insoluble gas is nitrogen or methane. Source 25 may be located close
to or above formation 10 or at some remove therefrom, such that the gas is
piped to an injection site 40. The raw gas may derive from multiple sources,
for
example several fuel-burning facilities, wherein raw gases are piped to a
common disposal facility,
[0045] According to another aspect, the soluble gas component may be
enriched by known means, so as to enhance the efficiency of the sequestration
process. Such enrichment may be done at source 25 of the gas or immediately
prior to sequestration.
[0046] One or more gas injection wells 12 extend into formation 10. In
Figure 1, only a single such well is shown. Well 12 is a generally
conventional
high pressure gas injection well, having at least one and preferably multiple
gas
discharge openings 13 within formation 10. Well 12 may comprise any suitable
orientation, but is preferably horizontal within formation 10, with multiple
openings 13 spaced along the horizontal portion.
[0047] In order to provide sufficient pressure, heating and other
conditions of the flue gas, the gas is piped from source 25 to a gas treatment
unit 40 prior to being fed into injection well 12. The gas treatment unit
pressurizes and heats the raw gas and may optionally enrich certain components
of the gas. The conditions of pressure and temperature depend in part on the
conditions within the aquifer including its permeability, formation pressure,
the
salinity of water within the aquifer, as well as the composition of the gas
being
injected.
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[0048] The pressurized and optionally heated gas is fed into injection
well
12 and introduced into the aquifer via openings 13. The gas is injected into
formation 10 with sufficient volume and driving pressure and optionally added
heat to generate one or more convection current cells within the formation
water. It is believed that a convection cell is generated according to the
following mechanism. Injection of the heated gas initially generates a current
within the immediately adjacent formation water. This current develops as a
result of the upward movement of bubbles of undissolved gas formed within the
formation water, and optionally the elevated temperature of the injected gas,
displacing natural formation water from the pore space of the formation. The
gas disperses initially as bubbles or pockets of undissolved gas. The
resulting
movement of the formation water initiates one or more convection currents or
cells 14 within the formation water. Over time, a relatively low density plume
of
formation water develops as the gas becomes dispersed in the formation water
because of horizontal dispersion during vertical flow and the heterogeneity of
the
formation. The gas plume therefore tends to spread laterally as well as moving
vertically. The corresponding movements of the formation water and gas plume
generate one or more convection currents or cells 14 within the formation. As
additional gas is fed into the formation, the resulting plume will continue to
generate convection currents or cells 14 within the formation water in the
region
of the injection well due to density differences between the ambient formation
water and the plume. This current includes a component that flows laterally
and
rises upwardly, as a result of the dispersive movement of the plume of
injected
gas. The dimensions of this current depend at least in part on the dimensions
of
the aquifer including its vertical spacing and the density, driving pressure,
volume or flow rate and temperature of the injected gas. The soluble gas 16
dissolves into the formation water, facilitated by the enhanced mixing action
caused by the said convection cells/currents. The water-insoluble gas 18
separates out due to its insolubility, and rises to accumulate in a gas cap or
pocket 20 which is usually located immediately beneath the upper low
permeability formation 60.
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[0049] At least one and preferably a plurality of withdrawal wells 22 are
provided. The withdrawal well(s) 22 are employed to vent the water-insoluble
gas 18 out of the formation 10, thereby providing additional volume in the
formation 10 for further sequestration of the water-soluble gas 16. The
withdrawal wells 22 extend into the formation 10, at least into an upper
portion
thereof. These wells include inlet openings 23 located within the formation
10,
at locations where the gas caps or pockets are expected to accumulate. The
withdrawal well(s) 22 may provide a conduit to a surface installation SO where
the insoluble gas may be either vented to the atmosphere, if for example the
insoluble gas is nitrogen or into a gas treatment or capture facility, if for
example the insoluble gas represents a useful product such as methane.
[0050] The venting process may rely on the internal pressure within the
gas pocket to vent the gas, or alternatively the accumulated gas may be
pumped in order to more rapidly and thoroughly withdraw the insoluble gases
from the formation 10. Preferably, a portion of withdrawal well 22 is
horizontal
to permit it to extend through an extended region of a gas pocket 20.
[0051] The venting process may be designed to extract some of the energy
present in the compressed insoluble gases by passing high-pressure vented
gases through a gas turbine to generate electricity, after such gasses have
vented from the gas pocket.
[0052] Shown in Figure 2, in another embodiment of the process is a
schematic cross-sectional view of a geological formation 10 with multiple
horizontal injection well openings and multiple withdrawal wells 22 showing
the
directions of convection currents 14 produced by gas injection. Also shown are
cross currents 24 which are influenced by the development of the convection
currents 14. As described in the embodiment of Figure 1, water-soluble gas 16
becomes dispersed within formation 10 as a plume of lower density fluid and
generates a convection current 14 while water-insoluble gas 18 rises toward a
gas pocket 20. Cross currents 24 provide additional mixing between water-
soluble gas 16 and the formation water. Also as described above, four
withdrawal wells 22 are employed to draw the water-insoluble gases out of the
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formation 10, thereby providing additional volume in the formation 10 for
further sequestration of the water-soluble gas 16.
[0053] The large-scale convection cell acts to bring remote water to the
injection well bore region via a "cross-current" 24 increasing the effective
volume in formation 10 that can be accessed through one injection well by
"flushing" the lateral water into the well bore region.
[0054] Shown in Figure 3, in another embodiment of the process, is a
schematic cross sectional view of an inclined formation 10 indicating a
horizontal
injection well 12 and a withdrawal well 22 showing the direction of a
convection
current 14 produced by gas injection. As described above, water-soluble gas 16
becomes dispersed within the formation as a plume of lower density fluid and
generates a convection current 14 while water-insoluble gas 18 rises toward
gas
pocket 20. Cross currents 24 are shown moving through the formation 10
towards the gas pocket 20.
[0055] Shown in Figure 4, in another embodiment of the process, is a
schematic representation of a gas sequestration array disposed in a formation
showing a gas injection well 12 for injection of a gas mixture 35, withdrawal
wells 22 and water injection wells 26 for injection of water. The gas outlet
region of gas injection well 12 is placed near the lower boundary of the
formation 10. Each withdrawal well 22 extends into gas pockets 20 within the
formation 10 for withdrawal of insoluble gas 18 contained therein, which has
separated from the injected gas mixture 35 by differential solubility of the
respective components of the mixture 35. Additional water 28 can be injected
into the formation via one or more water injection wells 26. This added water
can then flow into the matrix of formation 10 as indicated by arrows 32 to
bring
additional water into the formation 10 and promote mixing of gas mixture 35 in
formation 10.
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Example 1: Sequestration of Carbon Dioxide in a Saline Aquifer by
Density Driven Convection
[0056] In this example, the gas mixture being injected includes CO2,
which
is highly soluble in water, along with other gases which are less soluble in
water
under the conditions of temperature, pressure, pH, and salinity within the
formation. The gas mixture is injected at a high rate into a location close to
the
base of the formation. The formation has considerable vertical extent, or a
dip
which provides a vertical extent of about 20 m. For example, not excluding
other possible cases that may be acceptable, a desirable saline formation
would
be located over 1000 m deep within the strata and of great lateral extent. It
would have an intrinsic permeability of at least 1 Darcy in the vertical
direction.
The formation would have a porosity exceeding 15% with the pore fluid being
saline water. It is considered more desirable if the formation has a natural
dip
(inclination) of up to 20 . It is advantageous if the formation is bounded by
an
upper formation of rocks of low permeability to the mobile phases involved in
the sequestration process, including gases and water.
[0057] Preferably, the injection pressure is higher than the formation
pressure within the saline aquifer formation by an amount that is determined
by
the porosity and permeability of the host rock, along with other secondary
factors. For example, an injection well with a 1000 m long horizontal section
is
drilled into a 1500 m deep saline aquifer which has a natural formation
pressure
of 15 MPa. A mixture containing CO2 and other gases is injected uniformly
along
the length of the horizontal section at a pressure greater than 15 MPa. The
injection pressure is normally somewhat below the fracture pressure of the
formation. However, in some circumstances where it is deemed necessary to
encourage and promote vertical flow within the formation (for example where it
is desired to increase the fluid flow rate and enhance distribution of fluid
in the
formation), the injection pressure may be slightly higher than the natural
fracturing pressure of the formation, such that limited length vertical
fractures
are generated in order to increase the mixing length of the gas-water contact
zone. Those skilled in the art will be able to readily determine a suitable
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injection pressure or range of pressures to induce the formation of density-
driven convection currents within the target formation water. One of the
relevant considerations is the extent to which it is desired to increase the
sweep
efficiency, or the extent of distribution of gas in the formation laterally or
vertically, of the injected gas.
[0058] The gas may be optionally injected at an elevated temperature
above the ambient temperature of the formation water, in order to further
enhance the density contrast between the injected gas - and consequently the
formation water which is charged with the injected gas, and the surrounding
formation water.
[0059] Initially, under the high pressure gradients near the well bore,
the
injection may lead to a local displacement mechanism, with the liquid in the
pores being mostly physically displaced by the gas that is entering. In a
suitable
formation, as the size of the injected zone increases, the driving pressure
decreases (because of the greater radius, pressure drops off because of radial
spreading), and the height of the gas column increases, leading to a
gravitational segregation effect which arises from differences in phase
densities.
Once the effect is large enough, the gas will tend to rise towards the top of
the
formation, most likely through a tortuous path due to the presence of small
flow
impedance barriers such as shale streaks or small bodies of fine-grained sand.
[0060] Due to dispersion in vertical flow and the heterogeneity of the
formation, the gas will spread out in an upward-moving plume that spreads
laterally as well as moving vertically. This plume represents a region of
lower
pore fluid density than the adjacent parts of the saline formation that have
no
free gas, therefore a lateral contrast in the average fluid density is
generated
which creates a large density-difference-driven convective flow cell.
[0061] This density contrast will greatly increase the in situ forced
mixing
between the injected gas and the formation water. Water is brought from
remote locations in the formation to the injection site as the result of the
creation of the large convection cell, and this replenishes in part the local
water
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with CO2-free water, which can therefore strip the CO2 out of the injected gas
more efficiently. Therefore, the large-scale convection cell not only
increases the
diffusive mass transfer of CO2 into solution, it also acts to bring remote
water to
the injection well bore region, increasing the effective volume in the
formation
that can be accessed through one injection well by "flushing" the lateral
water
into the well bore region. The gases of lower solubility remain as non-
dissolved
gaseous phases and spread laterally and essentially upwardly, where they can
be removed by withdrawal wells such as passive drain wells. The density-driven
convection process provides more rapid mass transfer into solution.
[0062] Implementation of this process increases the short-term storage
capacity of soluble gases in the formation as well as increasing the long-term
capacity by maximizing mixing and promoting lateral water flux. The overall
sequestration process may involve preliminary passage of a flue gas mixture
(for
example, containing about 13% CO2 and 87% N2) through a membrane or other
type of purification or gas enrichment system so that the injected gas is 25%-
80% CO2, with the remainder being essentially N2; such a gas/CO2 enrichment
process will also help with improved storage capacity in situ and particularly
with
the rate at which the soluble gases (CO2 in this realization) can be injected
and
subjected to contact with the formation waters. The specific content of the
injected gas can be varied in response to driving economic and environmental
factors, as the process does not depend upon having a specific composition of
the injected gas.
[0063] It is envisioned that the process may include one or more long
horizontally drilled well bores for injection completed with a slotted liner
with no
cement. Such wells may be placed in a parallel offset configuration, with the
distance between the wells dependent on analysis, such as computer modeling
that provides some insight as to the effective convection cell size. The
length of
the wells may be designed based on the rate at which gas can enter the
formation at an appropriate rate to maximize mass transfer and convection
mixing.
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[0064] Each well may be equipped with an interior tubing system that can
distribute the gas injection evenly along the length of the well so that equal
volumes of gas can enter the well bore at various locations over time, in a
manner known per se in the art.
[0065] The well may be operated to maximize the contact of CO2 with
saline formation water by controlling at the surface the volume, rate and
pressure of the gas stream being injected. It is considered to be advantageous
if the injection wells are placed near the bottom of the formation, whether
the
injection wells consist of horizontal or vertical wells.
[0066] In another embodiment, conditions for sequestration of a water-
soluble fluid within a water-laden formation are determined by a computer-
implemented simulation. The process consists of providing a computer which is
programmed by a computer program stored on a computer readable medium.
The program comprises a representation of a known geological formation in a
manner known to the art. The computer is programmed to represent at least
one injection well for injecting a mixture of soluble and insoluble fluid into
said
formation, and includes means know to the art to vary one or more parameters.
These parameters are selected from the group consisting of:
a) composition of said fluid to be injected into said formation;
b) placement of said fluid injection well in said formation;
c) temperature of said fluid to be injected into said formation
d) rate of injection of said fluid into said formation;
e) injection pressure of said fluid into said formation;
f) numbers of said injection wells placed in said formation;
g) locations and profiles of said injection wells in said formation;
h) pH of said water in said formation;
i) salinity of said water in said formation;
j) density of said water in said formation;
k) volume of said injected fluid;
I) partial pressure of said injected fluid in said formation water;
and
m) density of said fluid.
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[0067] The computer program is configured to calculate properties of a
convection cell generated in said formation arising from density-driven move-
ment of said fluid and formation water within said formation influenced by one
or
more of said parameters. The computer produces a report providing sequestra-
tion conditions and preferred injection conditions comprising said one or more
parameters.
[0068] The computer program is further provided with means to vary
placement of one or more fluid withdrawal or water injection wells in said
formation.
[0069] Preferably, the fluid comprises a greenhouse gas, as described
above.
[0070] According to another embodiment, the invention relates to a
process for sequestration of a water-soluble fluid within a water-laden
formation.
According to this embodiment, a computer modeling step as described above is
performed. The parameters determined in said model are then replicated on
site under real-world conditions with components of an injection well system
at
the site of said known formation, in order to generate at least one density-
driven
convection current within said formation to achieve sequestering of said water-
soluble fluid using said injection well system.
[0071] It will be seen that the present invention has been described by
way of preferred embodiments of various aspects of the invention. However, it
will be understood that one skilled in the art may depart from or vary the
embodiments described in detail herein, while still remaining within the scope
of
the invention as defined in this patent specification as a whole, including
the
claims.
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