U.S. patent application number 14/532544 was filed with the patent office on 2015-07-23 for carbon dioxide energy storage and enhanced oil recovery.
The applicant listed for this patent is GEOSIERRA, LLC. Invention is credited to Grant Hocking.
Application Number | 20150204171 14/532544 |
Document ID | / |
Family ID | 53544358 |
Filed Date | 2015-07-23 |
United States Patent
Application |
20150204171 |
Kind Code |
A1 |
Hocking; Grant |
July 23, 2015 |
CARBON DIOXIDE ENERGY STORAGE AND ENHANCED OIL RECOVERY
Abstract
The present invention is a method and apparatus for the
subsurface storage of carbon dioxide in reservoir formations, to
provide energy storage for electrical load balancing, and to enable
the enhanced recovery of hydrocarbon fluids from the subsurface
formations by gravity drainage. Multiple propped vertical
inclusions are propagated into hydrocarbon fluid bearing reservoir
formations at various vertical depths from well casings. Carbon
dioxide is injected and stored in the formations. At off-peak power
demand periods, carbon dioxide is pumped by a pump/turbine from the
low energy formation into a deeper high energy formation, and at
peak power demand periods the carbon dioxide is released from the
high energy formation and flows to the low energy formation,
driving the pump/turbine to generate electricity. Hydrocarbon
fluids are produced from the formations depending on the formation
conditions. Additional carbon dioxide is injected into the system
as hydrocarbon fluids are extracted.
Inventors: |
Hocking; Grant; (Alpharetta,
GA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
GEOSIERRA, LLC |
Alpharetta |
GA |
US |
|
|
Family ID: |
53544358 |
Appl. No.: |
14/532544 |
Filed: |
November 4, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61900612 |
Nov 6, 2013 |
|
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|
Current U.S.
Class: |
166/303 ;
166/307; 166/52 |
Current CPC
Class: |
Y02C 20/40 20200801;
Y02P 90/70 20151101; Y02C 10/14 20130101; E21B 43/006 20130101;
E21B 41/0085 20130101; E21B 41/0064 20130101; E21B 43/267 20130101;
E21B 43/164 20130101 |
International
Class: |
E21B 43/16 20060101
E21B043/16; E21B 43/267 20060101 E21B043/267; E21B 43/00 20060101
E21B043/00; E21B 41/00 20060101 E21B041/00 |
Claims
1. A carbon energy storage and oil recovery method comprising the
steps of: a. propagating an inclusion filled with a proppant into a
high energy formation from a well casing extending from a ground
surface into the high energy formation; b. propagating an inclusion
filled with a proppant into a low energy formation from the well
casing extending from the ground surface into the low energy
formation; c. injecting carbon dioxide into the high energy
formation and the low energy formation through a carbon dioxide
conduit disposed in the well casing; d. during off-peak energy
demand times, pressurizing the carbon dioxide in the high energy
formation by pumping carbon dioxide from the low energy formation
through the carbon dioxide conduit into the high energy formation
by means of a pump/turbine; e. during peak energy demand times,
releasing the carbon dioxide from high energy formation to the low
energy formation through the carbon dioxide conduit and through the
pump/turbine to generate electricity; and f. producing hydrocarbon
fluids in the high energy formation or the low energy formation up
an oil production tube in the well casing.
2. The method of claim 1, wherein the well casing comprises a high
energy well casing extending from the ground surface into the
high-energy formation and a low energy well casing extending from
the ground surface into the low energy formation.
3. The method of claim 1, wherein the method further includes a
plurality of inclusions at varying azimuths in the high energy
formation and the low energy formation.
4. The method of claim 3, wherein the plurality of inclusions are
initiated from the well casing by injecting an injection fluid,
including the proppant, from the well casing into the high energy
formation and into the low energy formation, wherein the inclusions
are positioned at progressively shallower depths after the
viscosity of the injection fluid in the immediate lower inclusions
has reduced so that the plurality of inclusions at the shallower
depths intersect and coalesce with the inclusions immediately
beneath on their respective azimuths.
5. The method of claim 4, wherein the method further includes
providing a plurality of well casings with associated inclusions at
varying azimuth in the high energy formation and in the low energy
formation.
6. The method of claim 1, wherein the proppant has particles of
size ranging from #4 to #100 U.S. mesh and is selected from the
group including sand, ceramic beads, resin coated sand, resin
coated ceramic beads, fibers, or a mixture thereof.
7. The method of claim 1, wherein the carbon dioxide is injected
into the high energy formation and the low energy formation at a
supercritical state and above the miscible pressure of hydrocarbon
fluids in the high energy formation and the low energy
formation.
8. The method of claim 1, wherein the carbon dioxide injection is a
continuous injection, and the production of hydrocarbon fluids is
continuous.
9. The method of claim 1, wherein the carbon dioxide injection is a
pressure pulsed cyclic injection or intermittent injection.
10. The method of claim 1, wherein the high energy formation and
the low energy formation form a closed carbon energy storage system
for cyclic energy states of the carbon dioxide between the high
energy formation and the low energy formation.
11. The method of claim 10, wherein cyclic energy states of the
carbon dioxide are cycled by the pump/turbine.
12. The method of claim 11, wherein the pump/turbine is driven by a
variable speed generator.
13. The method of claim 11, wherein the pump/turbine is located
above the ground surface.
14. The method of claim 11, wherein the pump/turbine is located
below the ground surface.
15. The method of claim 1, wherein the injection of the carbon
dioxide into the low energy formation is at an injection pressure
and temperature so that the carbon dioxide is in its supercritical
state and above the miscible pressure of the hydrocarbon
fluids.
16. The method of claim 1, wherein the injection of the carbon
dioxide injection into the low energy formation is at an injection
pressure and temperature that provide a maximum density difference
between the hydrocarbon fluids and the carbon dioxide to thereby
achieve efficient enhanced recovery of the hydrocarbon fluids by
gravity drainage.
17. The method of claim 1, wherein the high energy formation has a
Skempton B parameter greater than 0.95 exp(-0.04p')+0.008p', where
p' is the mean effective stress in MPa at the depth of the
propagating inclusion.
18. The method of claim 1, wherein the low energy formation has a
Skempton B parameter greater than 0.95 exp(-0.04p')+0.008p', where
p' is the mean effective stress in MPa at the depth of the
propagating inclusion.
19. The method of claim 1, wherein methane is produced from the
high energy formation and the low energy formation from a first
portion of the well casing located at the highest elevation in the
high energy formation and from a second portion of the well casing
located at the highest elevation in the low energy formation.
20. A carbon energy storage and oil recovery system for recovery
hydrocarbon fluids from a formation having a high energy formation
and a low energy formation, the system comprising: a. high energy
well system located in the high energy formation comprising: i) a
well casing extending from a ground surface into the high energy
formation; ii) a high energy expansion device in the well casing
for propagating an inclusion filled with a proppant into the high
energy formation from the well casing; iii) a high energy carbon
dioxide conduit with a first end and a second end wherein the first
end communicates with the inclusions in the high energy formation;
and iv) an oil production tube with a first end communicating with
the formation and a second end extending to the ground surface for
delivery of hydrocarbons from the formation to the ground surface
for recovery; b. low energy well system located in a low energy
formation comprising: i) the well casing further extending into the
low energy formation; ii) a low energy expansion device in the well
casing for propagating an inclusion filled with a proppant into the
low energy formation from the well casing; iii) a low energy carbon
dioxide conduit with a first end and a second end wherein the first
end communicates with the inclusions in the low energy formation;
and c. a carbon dioxide source for injecting the carbon dioxide
into the high energy formation and the low energy formation by
means of the high energy carbon dioxide conduit and the low energy
carbon dioxide conduit; d. a pump/turbine connected between the
second end of the high energy carbon dioxide conduit and the second
end of the low energy carbon dioxide conduit for pressurizing the
carbon dioxide in the high energy formation by pumping carbon
dioxide from the low energy formation during off-peak energy demand
times and for generating electricity by the release of the carbon
dioxide from the high energy formation to the low energy formation
during peak energy demand times; and e. a hydrocarbon production
pump for pumping hydrocarbons in the formation up the oil
production tube.
21. The system of claim 20, wherein the well casing comprises a
high energy well casing extending from the ground surface into the
high-energy formation and a low energy well casing extending from
the ground surface into the low energy formation.
22. The system of claim 20, wherein the system further includes a
plurality of inclusions at varying azimuths in the high energy
formation and the low energy formation.
23. The system of claim 22, wherein the plurality of inclusions are
initiated from the high energy expansion device of the well casing
by injecting an injection fluid, including a proppant, from the
well casing into the high energy formation and are initiated from
the low energy expansion device of the well casing by injecting the
injection fluid, including the proppant, from the well casing into
the low energy formation, wherein the inclusions are positioned at
progressively shallower depths after the viscosity of the injection
fluid in the immediate lower inclusions has reduced so that the
plurality of inclusions at the shallower depths intersect and
coalesce with the inclusions immediately beneath on their
respective azimuths.
24. The system of claim 23, wherein the system further includes
providing a plurality of well casings with associated inclusions at
varying azimuth in the high energy formation and in the low energy
formation.
25. The system of claim 20, wherein the proppant has particles of
size ranging from #4 to #100 U.S. mesh and is selected from the
group including sand, ceramic beads, resin coated sand, resin
coated ceramic beads, fibers, or a mixture thereof.
26. The system of claim 20, wherein the carbon dioxide source
injects the carbon dioxide through the high energy carbon dioxide
conduit into the high energy formation and through the low energy
carbon dioxide conduit into the low energy formation at a
supercritical state and above the miscible pressure of hydrocarbon
fluids in the high energy formation and the low energy
formation.
27. The system of claim 20, wherein the carbon dioxide source
injects the carbon dioxide in a continuous injection, and the
production of hydrocarbon fluids is continuous.
28. The system of claim 20, wherein carbon dioxide source injects
the carbon dioxide in a pressure pulsed cyclic injection or
intermittent injection.
29. The system of claim 20, wherein the high energy carbon dioxide
conduit and the low energy carbon dioxide conduit form a closed
carbon energy storage system with the pump/turbine for cyclic
energy states of the carbon dioxide between the high energy
formation and the low energy formation.
30. The system of claim 29, wherein cyclic energy states of the
carbon dioxide are cycled by the pump/turbine system.
31. The system of claim 30, wherein the pump/turbine is driven by a
variable speed generator.
32. The system of claim 30, wherein the pump/turbine is located
above the ground surface.
33. The system of claim 30, wherein the pump/turbine is located
below the ground surface.
34. The system of claim 20, wherein carbon dioxide source injects
the carbon dioxide into the low energy formation at an injection
pressure and temperature so that the carbon dioxide is in its
supercritical state and above the miscible pressure of the
hydrocarbon fluids.
35. The system of claim 20, wherein the carbon dioxide source
injects the carbon dioxide into the low energy formation at an
injection pressure and temperature that provide a maximum density
difference between the hydrocarbons and the carbon dioxide to
thereby achieve efficient enhanced recovery of the hydrocarbon
fluids by gravity drainage.
36. The system of claim 20, wherein the high energy formation has a
Skempton B parameter greater than 0.95 exp(-0.04p')+0.008p', where
p' is the mean effective stress in MPa at the depth of the
propagating inclusion.
37. The system of claim 20, wherein the low energy formation has a
Skempton B parameter greater than 0.95 exp(-0.04p')+0.008p', where
p' is the mean effective stress in MPa at the depth of the
propagating inclusion.
38. The system of claim 20, wherein methane is produced from the
high energy formation and the low energy formation from a first
portion of the well casing located at the highest elevation in the
high energy formation and from a second portion of the well casing
located at the highest elevation in the low energy formation.
Description
CLAIM OF PRIORITY
[0001] This application claims priority from U.S. Provisional
Patent Application No. 61/900,612 filed on Nov. 6, 2013, which is
relied upon and incorporated herein in its entirety by
reference.
TECHNICAL FIELD
[0002] The present invention generally relates to the geological
storage of carbon dioxide, the closed cycling of carbon dioxide
from one reservoir formation to another for energy storage to
balance electrical loads, and the subsequent enhanced recovery of
petroleum fluids (oil) from the subsurface formation by gravity
drainage.
BACKGROUND OF THE INVENTION
[0003] Carbon capture and storage in geological formations is a
much focused research area due to the greenhouse gas effects of
releasing carbon dioxide to the atmosphere. The carbon dioxide can
be stored in geological formations in the form of a trap, the trap
being a depleted oil and gas field or a saline aquifer. The cost of
such storage is high, but in the case of natural gas reservoirs
containing high levels of carbon dioxide, such storage may be
easily justified by the value of the natural gas extracted. In the
case of carbon capture from coal fire power plants, the cost of
such carbon dioxide storage could be excessive for the operation of
the power plant. A need therefore exists for a cheaper storage
scheme for the geological storage of carbon dioxide.
[0004] Energy storage schemes for balancing peak and off-peak
electrical demand are now in even greater demand due to the fact
that most renewable energy sources, such as wind, tidal and solar
provide only intermittent power. Geological energy storage schemes
may assist in balancing electrical loads on a power grid consisting
of pumped hydroelectric and compressed air energy storage schemes.
The pumped hydroelectric scheme requires surface reservoir storage
and either topographical relief to provide the differential head
between the two stored reservoir states or the injection of the
fluid into the subsurface into either an aquifer or constructed
subsurface caverns. Water is pumped by a pump/turbine to a higher
elevation during off-peak demand, and during peak demand the water
flows from the higher elevation reservoir to the lower reservoir,
and drives the pump/turbine to generate electricity. Using a
variable speed generator the electrical loads can be even better
balanced.
[0005] The compressed air energy storage scheme involves
compressing air and injecting it into either a subsurface aquifer
or underground constructed caverns. The caverns are solution mined
in salt formations or excavated in hard rock formations. Air is
compressed and injected into the subsurface during off-peak demand
and at peak demand air is released from storage to the atmosphere
and drives the pump/turbine for electrical generation.
[0006] In both schemes the cost of the demand electricity is high,
so there is a need for a cheaper geological energy storage system
for balancing electrical loads.
[0007] Most hydrocarbon fluids (oil) are produced by primary,
secondary, and tertiary recovery methods. In many cases, the
recovery of the hydrocarbon fluids is only a small percentage of
the original oil in place. The reasons for the low recovery can be
attributed to many factors. Gravity drainage of hydrocarbon fluids
as a recovery mechanism is well known to yield very high recovery
factors. Gravity drainage, however, is not applicable to many
reservoirs due to the reservoir's low vertical permeability and the
low mobility of the oil. Thus, a need exists for a method to
enhance the gravity drainage of such reservoirs and thus enable the
recovery of significant quantities of stranded hydrocarbon fluids.
Carbon dioxide at supercritical state and above the miscible
pressure of the hydrocarbons provides a number of mechanisms to
assist oil recovery, such as lower gas-oil capillary pressure and
hence more effective gravity drainage, higher oil relative
permeability, vaporizing of intermediate components, swelling of
the oil, oil viscosity reduction, and solution gas drive.
[0008] Gravity drainage can yield oil recoveries greater than 80%
in clean high permeable reservoirs. Reservoirs with moderate to low
vertical permeability are not suitable for gravity drainage because
the recovery mechanism is extremely slow in these types of
formations. If multiple vertical high permeable propped planar
inclusions are installed in such reservoirs, then oil recovery is
virtually independent of the reservoir vertical permeability,
Hocking et al., "Unimpaired Performance of Single-Well SAGD in
Variable Geology," Gas & Oil Expo & Conference North
America, 2011, and thus is a viable oil recovery method. Such
vertical propped planar inclusions combined with the availability
of large quantities of carbon dioxide for enhanced recovery, makes
many reservoirs that are considered depleted as candidates for
significant enhanced oil recovery of these stranded hydrocarbon
fluid reserves.
[0009] Techniques used in hard, brittle rock to form fractures
therein are typically not applicable to ductile formations
comprising unconsolidated, weakly cemented sediments. The method of
controlling the azimuth of a vertical hydraulic planar inclusion in
formations of unconsolidated or weakly cemented soils and sediments
by slotting the well casing or installing a pre-slotted or weakened
well casing at a predetermined azimuth has been previously
disclosed. A vertical hydraulic planar inclusion can be propagated
at a pre-determined azimuth in unconsolidated or weakly cemented
sediments and that multiple orientated vertical hydraulic planar
inclusions at differing azimuths from a single well casing can be
initiated and propagated for the enhancement of petroleum fluid
production from the formation. See U.S. Pat. No. 6,216,783 to
Hocking et al., U.S. Pat. No. 6,443,227 to Hocking et al., U.S.
Pat. No. 6,991,037 to Hocking, U.S. Pat. No. 7,404,441 to Hocking,
U.S. Pat. No. 7,640,975 to Cavender et al., U.S. Pat. No. 7,640,982
to Schultz et al., U.S. Pat. No. 7,748,458 to Hocking, U.S. Pat.
No. 7,814,978 to Steele et al., U.S. Pat. No. 7,832,477 to Cavender
et al., U.S. Pat. No. 7,866,395 to Hocking, U.S. Pat. No. 7,950,456
to Cavender et al., U.S. Pat. No. 8,151,874 to Schultz et al. A
vertical hydraulic planar inclusion can be propagated at a
pre-determined azimuth in unconsolidated or weakly cemented
sediments and that multiple orientated vertical hydraulic planar
inclusions at differing azimuths from a single well casing can be
initiated and propagated for the enhancement of petroleum fluid
production from the formation. Unconsolidated or weakly cemented
sediments behave substantially different from brittle rocks from
which most of the hydraulic fracturing experience is founded.
[0010] The methods disclosed above find especially beneficial
application in ductile rock formations made up of unconsolidated or
weakly cemented sediments, in which obtaining directional or
geometric control over inclusions as they are being formed is
typically very difficult. Weakly cemented sediments are primarily
frictional materials because they have minimal cohesive strength.
An uncemented sand, having no inherent cohesive strength (i.e., no
cement bonding holding the sand grains together), cannot contain a
stable crack within its structure and cannot undergo brittle
fracture. Such materials are categorized as frictional materials
which fail under shear stress, whereas brittle cohesive materials,
such as strong rocks, fail under normal stress.
[0011] The term "cohesion" is used in the art to describe the
strength of a material at zero effective mean stress. Weakly
cemented materials may appear to have some apparent cohesion due to
suction or negative pore pressures created by capillary attraction
in fine grained sediment, with the sediment being only partially
saturated. These suction pressures hold the grains together at low
effective stresses and, thus, are often called apparent
cohesion.
[0012] The suction pressures are not true bonding of the sediment's
grains, because the suction pressures would dissipate due to
complete saturation of the sediment. Apparent cohesion is generally
such a small component of strength that it cannot be effectively
measured for strong rocks, and only becomes apparent when testing
very weakly cemented sediments.
[0013] Geological strong materials, such as relatively strong rock,
behave as brittle materials at normal petroleum reservoir depths,
but at great depth (i.e. at very high confining stress) or at
highly elevated temperatures, these rocks can behave like ductile
frictional materials. Unconsolidated sands and weakly cemented
formations behave as ductile frictional materials from shallow to
deep depths, and the behavior of such materials are fundamentally
different from rocks that exhibit brittle fracture behavior.
Ductile frictional materials fail under shear stress and consume
energy due to frictional sliding, rotation, and displacement.
[0014] Conventional hydraulic dilation of weakly cemented sediments
is conducted extensively on petroleum reservoir formations as a
means of sand control. The procedure is commonly referred to as
"Frac-and-Pack." In a typical operation, the casing is perforated
over the formation interval intended to be fractured, and the
formation is injected with an injection fluid of low gel loading
without proppant, in order to form the desired two winged structure
of a fracture. Then, the proppant loading in the injection fluid is
increased substantially to yield tip screen-out of the fracture. In
this manner, the fracture tip does not extend further, and the
fracture and perforations are backfilled with proppant.
[0015] The process, producing a two winged fracture, is formed as
in conventional brittle hydraulic fracturing. Such a process,
however, has not been duplicated in the laboratory or in shallow
field trials. In laboratory experiments and shallow field trials
chaotic geometries of the injection fluid has been observed, with
many cases evidencing cavity expansion growth of the injection
fluid around the well and with deformation or compaction of the
host formation.
[0016] Weakly cemented sediments behave like a ductile frictional
material in yield due to the predominantly frictional behavior and
the low cohesion between the grains of the sediment. Such materials
do not "fracture" and, therefore, there is no inherent fracturing
process in these materials as compared to conventional hydraulic
fracturing of strong brittle rocks.
[0017] Linear elastic fracture mechanics is not generally
applicable to the behavior of weakly cemented sediments. The
knowledge base of propagating viscous planar inclusions in weakly
cemented sediments is primarily from recent experience over the
past ten years, and much is still not known regarding the process
of viscous fluid propagation in these sediments.
[0018] Accordingly, there is a need for a method and apparatus for
construction of vertical multiple azimuth vertical propped planar
inclusions to assist in the more efficient injection and withdrawal
of petroleum fluids from the subsurface, for the geological storage
of carbon dioxide, a subsurface energy storage scheme for balancing
electrical loads, and a more efficient and effective recovery
method of hydrocarbon fluids from the subsurface formations.
SUMMARY OF THE INVENTION
[0019] The present invention is a method and apparatus for
subsurface storage of carbon dioxide, for providing energy storage
for electrical load balancing, and for enabling more efficient,
more economical, and less environmental impact for the enhanced
recovery of petroleum fluids from the subsurface formation by
gravity drainage. In one embodiment of this invention, multiple
vertical propped planar inclusions are initiated from well casings
and propagate into a hydrocarbon fluid bearing high energy
reservoir formation. Further multiple vertical propped planar
inclusions are initiated from other well casings and propagated
into a shallower depleted hydrocarbon fluid bearing low energy
reservoir formation. Carbon dioxide is injected and stored in both
reservoir formations.
[0020] At off-peak energy periods, the carbon dioxide is pumped by
a pump/turbine into the deeper high energy reservoir formation at a
high energy state, and at peak energy periods the carbon dioxide is
released from the high energy reservoir formation to the low energy
reservoir formation through the pump/turbine to generate
electricity to balance electrical loads on a power grid. The energy
storage scheme is a closed cycle system with no atmospheric
emissions.
[0021] The carbon dioxide is injected into the subsurface formation
at supercritical conditions, and because of its miscibility with
the oil and its gas like properties, the injection of carbon
dioxide results in increased production of petroleum fluids by
gravity drainage from the subsurface formation. Hydrocarbon fluids
are produced from either one or both reservoir formations depending
on the reservoir conditions, oil quality, and quantity of stranded
oil reserves. Additional carbon dioxide is injected into the
formations as hydrocarbon fluids are extracted.
[0022] In one embodiment, the pump/turbine is located on the
surface. In another embodiment of the invention, the two reservoirs
are located above and below each other, one being shallow and the
other deep. The well casing intersects both reservoirs, and
pump/turbine is located in the well casing below the surface and
between high energy formation and the low energy formation.
[0023] Although the present invention contemplates the formation of
vertical propped planar inclusions which generally extend laterally
away from a vertical or near vertical well penetrating an earth
formation and in a generally vertical plane, those skilled in the
art will recognize that the invention may be carried out in earth
formations wherein the fractures and the well bores can extend in
directions other than vertical.
[0024] Other objects, features and advantages of the present
invention will become apparent upon reviewing the following
description of the preferred embodiments of the invention, when
taken in conjunction with the drawings and the claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0025] FIG. 1 is a schematic isometric view of a carbon energy
storage and oil recovery system having a first well casing with
associated planar inclusions within a high energy formation and a
second well casing with associated planar inclusions within a low
energy formation in accordance with the present invention.
[0026] FIG. 2 is a section view of the well casings along section
line 2-2 of FIG. 1 in accordance with the present invention.
[0027] FIG. 3 is a schematic isometric view of a carbon energy
storage and oil recovery system having multiple well casings with
associated planar inclusions within the high energy formation in
accordance with the present invention.
[0028] FIG. 4 is a plot of the physical states of carbon dioxide
for various temperatures and pressures.
[0029] FIG. 5 is a plot of the density of carbon dioxide for
various temperatures and pressures.
[0030] FIG. 6 is a schematic isometric view of a carbon energy
storage and oil recovery system having a single well casing with
associated planar inclusions within a high energy formation and
with associated planar inclusions within a low energy formation in
accordance with the present invention.
DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT
[0031] Several embodiments of the present invention are described
below and illustrated in the accompanying drawings. The present
invention is a method and apparatus for the storage of carbon
dioxide in subsurface formations, for providing a closed cycle
energy storage method for balancing electrical loads on a power
grid by transferring carbon dioxide between subsurface hydrocarbon
bearing reservoir formations, and for enabling more efficient and
economical recovery of petroleum fluids from the subsurface
formations by gravity drainage with less environmental impact.
Multiple vertical propped planar inclusions at various azimuths are
constructed from multiple well casings into oil bearing formations
and are filled with a proppant that yields highly permeable planar
inclusions that greatly assist gravity drainage as an effective
recovery method of hydrocarbon fluids. The installation of the
multiple vertical propped planar inclusions enables both the carbon
dioxide injection and withdrawal to be very efficient. The propped
planar inclusions also enable gravity drainage as an effective
recovery method in reservoir formations of low vertical
permeability, in which oil reserves would otherwise be left
stranded and unexploited. Several embodiments of the present
invention are described below and illustrated in the accompanying
drawings.
[0032] As is well known, extensive oil reservoirs are found in
formations comprising unconsolidated, weakly cemented sediments
with moderate to low vertical permeability due to silt and/or clay
content. Unfortunately, the methods currently used for extracting
the oil from these formations have yielded low recovery factors.
Gravity drainage in these formations is limited due to the
formation's low vertical permeability. Oil is not very mobile in
these formations. Therefore, oil recovery can be enhanced by
forming highly permeable planar inclusions in the formations and by
injecting carbon dioxide into the permeable planar inclusions. The
injected carbon dioxide mixes with the oil reducing its viscosity
and thus increases the mobility of the oil. The oil can then flow
under gravity into the permeable planar inclusions and into the
well casing for production up oil production tubing in the well
casing at flow rates that are virtually independent of the
formation vertical permeability. See Hocking et al., "Unimpaired
Performance of Single-Well SAGD in Variable Geology," Gas & Oil
Expo & Conference North America, 2011. Oil recovery by
effective gravity drainage can yield recovery factors greater than
80%, whereas without the propped verticals planar inclusions
recovery by primary and secondary recovery could be less than 30%.
At 30% recovery, gravity drainage is not an effective recovery
method. Thus the combination of carbon storage and closed cycle
energy storage with enhanced gravity drainage oil recovery provides
a most cost effective, efficient, and environmentally proactive
system.
[0033] As is well known, the performance of the gravity drainage
process is mainly controlled by the competition between capillary
and gravity forces. The Bond number, Bo, is a dimensionless number
that quantifies the importance of gravitational forces compared to
interfacial forces as given by Bo=K.DELTA..rho.g/.sigma., with K
being the formation permeability, .DELTA..rho. the difference in
density of the oil and the carbon dioxide, g the gravitational
acceleration constant and .sigma. the interfacial tension. A high
Bo means that gravitational force is dominating and interfacial
does not influence the gravity induced oil flow. Therefore,
maximizing .DELTA..rho. and minimizing .sigma., by appropriate
selection of the supercritical carbon dioxide injection pressure
and temperature is important.
[0034] FIG. 1 represents a carbon energy storage and oil recovery
system 9 and serves to illustrate the associated method in
accordance with the principles of the present invention. Two
reservoir formations, a high energy reservoir formation 24 and a
low energy reservoir formation 14, with respective cap rocks 26 and
16, are hydrocarbon fluid bearing formations that are considered
depleted or legacy fields. The high energy formation 24 and the low
energy formation 14 may be moderately permeable. The vertical
permeabilities, however, are too low for gravity drainage to be an
effective recovery method. Therefore, considerable reserves of oil
remain in the high energy formation 24 and possibly in the low
energy formation 14. The formations 24 and 14 are shown at
differing elevations in FIG. 1, however they could be at similar
elevations, or the high energy formation 24 may be deeper or
shallower than the low energy formation 14. Which formation is held
at the high energy state depends on reservoir conditions, oil
quality, stranded reserves, etc. In general, the high energy
formation 24 will be substantially deeper than the low energy
formation 14. The terms "hydrocarbon fluids" and "oil" are used
herein to indicate relatively low viscosity and low density
hydrocarbons that have a moderate miscible pressure when exposed to
supercritical carbon dioxide. The cap rocks 26 and 16 are
geological traps for the hydrocarbons fluids and have stored the
hydrocarbon fluids over geological time under considerable
pressure. These cap rocks 26 and 16 are also suitable for the long
term storage and containment of carbon dioxide.
[0035] The carbon energy storage and oil recovery system 9 of FIG.
1 includes two interconnected well systems 20 and 10, one for the
high energy formation 24 and one for the low energy formation 14,
respectively. The well system 20 is positioned within the high
energy formation 24 and is used to inject carbon dioxide into the
high energy formation 24, to withdraw carbon dioxide from the high
energy formation 24, to inject fracture fluid into the high energy
formation 24, and to withdraw oil by means of an oil production
pump 28 from the high energy formation 24 via a sump 23. The other
well system 10 is positioned within the low energy formation 14 and
is used to inject carbon dioxide into the low energy formation 14,
to withdraw carbon dioxide from the low energy formation 14, to
inject fracture fluid into the low energy formation 14, and to
withdraw oil by means of an oil production pump 18 from the low
energy formation 14 via sump 13.
[0036] The high energy well system 20 includes a well casing 21, an
expansion device 22, an oil production tube 27, a carbon dioxide
conduit 25, and multiple vertical high permeability propped planar
inclusions 30 within the formation 24. As best seen in FIG. 2, the
carbon dioxide conduit 25 is the annular space between the oil
production tube 27 and the well casing 21. The high energy carbon
dioxide conduit 25 is connected to a pump/turbine 34 by means of a
high energy pump/turbine port 37. The low energy well system 10
includes a well casing 11, an expansion device 12, an oil
production tube 17, a carbon dioxide conduit 15 (the annular space
between the oil production tube 17 and the well casing 11), and
multiple vertical high permeability propped planar inclusions 30
within the formation 14. The low energy carbon dioxide conduit 17
is connected to the pump/turbine 34 by means of a low energy
pump/turbine port 39. A carbon dioxide source 7 pumps carbon
dioxide into the high energy formation 24 and the low energy
formation 14 via the high-energy carbon dioxide conduit 25 and the
low energy carbon dioxide conduit 15 to occupy the space created by
the removal of oil from the formations.
[0037] The propped planar inclusions 30 are formed by injecting a
suitable fracture fluid with proppant 51 into the expansion devices
22 and 12. The multiple vertical high permeable propped planar
inclusions 30 enhance the injection and withdrawal of hydrocarbon
fluids and carbon dioxide into and from the formations 24 and 14.
The well systems 20 and 10 in FIG. 1 enable the enhanced recovery
of hydrocarbon fluids by gravity drainage for producing oil from
the sumps 23 and 13, via oil production tubes 27 and 17 to the
ground surface 5 from formations 24 and 14. As hydrocarbons are
produced, additional carbon dioxide can be injected into the
formations 24 and 14 through carbon dioxide conduits 25 and 15.
[0038] During off-peak energy requirement periods, the carbon
dioxide in the low energy formation 14 is pumped into the high
energy formation 24, by the pump/turbine 34 driven by electrical
power 31. The electrical power 31 may be supplied by a variable
speed generator thus providing a refinement in balancing electrical
loads on a power grid. As a result of the operation of the
pump/turbine 34, the carbon dioxide in the high energy formation 24
is in a supercritical state and at a pressure greater than the
miscible pressure, thus greatly assisting gravity drainage of oil.
Hydrocarbon fluids (oil) are pumped to the surface 5 from the high
energy formation 24 by the high energy oil production pump 28 via
oil production tube 27. During peak energy requirement periods, the
carbon dioxide is released from high energy formation 24 and flows
via carbon dioxide conduit 25 through the pump/turbine 34 to low
energy formation 14 and drives the pump/turbine 34 to produced peak
demand electrical power 31. The cycle for the energy storage system
9 described above is a closed system with no atmospheric emissions.
The continuous operation of the energy storage system 9 enhances
the recovery of hydrocarbon fluids from the formations 24 and 14,
allowing for greater volumes of carbon dioxide to be stored in the
formations 24 and 14 of energy storage system 9.
[0039] Turning to FIG. 3, the high energy state reservoir formation
24 is shown to illustrate and describe in detail multiple well
systems 20. Multiple vertical wells have been drilled into the
formation 24, and the well casings 21 have been cemented in the
formation 24 and in the overlying cap rock 26. The term "casing" is
used herein to indicate a protective lining for a wellbore. Any
type of protective lining may be used, including those known to
persons skilled in the art as liner, casing, tubing, etc. Casing
may be segmented or continuous, jointed or unjointed, conductive or
non-conductive made of any material (such as steel, aluminum,
polymers, composite materials, etc.), and may be expanded or
unexpanded, etc.
[0040] With continuing reference to FIG. 3, the high energy well
casings 21 have expansion devices 22 and the sump sections 23. The
carbon dioxide conduits 25 are interconnected via pump/turbines
(not shown). The formation 24 may comprise unconsolidated and/or
weakly cemented sediments for which conventional fracturing
operations are not well suited. The expansion devices 22 operate to
expand the well casings 21 radially outward and thereby dilate the
formation 24 proximate the expansion devices 22, in order to
initiate the formation of the generally vertical and planar
inclusions 30 extending outwardly from the well casings 21 at
various azimuths. Suitable expansion devices for use in the well
system 20 are described in U.S. Pat. Nos. 6,216,783, 6,330,914,
6,443,227, 6,991,037, 7,404,441, 7,640,975, 7,640,982, 7,748,458,
7,814,978, 7,832,477, 7,866,395, 7,950,456 and 8,151,874. The
entire disclosures of these prior patents are incorporated herein
by this reference. Other expansion devices or modes of formation
deformation may be used in the well systems 20 in keeping with the
principles of the invention.
[0041] Once the expansion devices 22 have expanded the well casings
21 radially outward, the fracture fluid with a proppant 51 is
forced from the well casings 21 into the dilated formation 24 to
propagate the planar inclusions 30 into the formation 24. The
planar inclusions 30 are not necessarily formed simultaneously. As
shown in FIG. 3, the well systems 20 each include eight planar
inclusions 30. The well systems 20 do not necessarily need to have
eight inclusions at the same depth orientated at various azimuths,
but could consist of one, two, three, four, five, six or even seven
vertical planar inclusions at various azimuths at the same depth,
with such choice of the number of inclusions constructed depending
on the application, formation type, and/or economic benefit. Also
there is only one inclusion at a particular azimuth, whereas there
could be other upper inclusions on the same azimuth, and in fact
there could be numerous of these upper inclusions at progressively
shallower depths.
[0042] With continuing reference to FIG. 3, the lower planar
inclusions 30 are constructed first, with each wing of the eight
planar inclusions 30 injected independently of the others. The well
systems 20 are shown with the planar inclusions 30 constructed at
only a single depth, these well systems 20 are shown as only one
example of the invention. Alternative forms of the invention could
contain numerous upper inclusions constructed at progressively
shallower depths, depending on the formation thickness, the
distribution of hydrocarbon fluids within the formation 24, and/or
economic benefit.
[0043] The injected fracture fluid carries the proppant 51 to the
extremes of the planar inclusions 30. Upon propagation of the
planar inclusions 30 to their required lateral and vertical extent,
the thickness of the planar inclusions 30 may need to be increased
by utilizing the process of tip screen out. The tip screen out
process involves modifying the proppant loading and/or modifying
the properties of the injected fracture fluid to achieve a proppant
bridge at the inclusion tips. The injected fracture fluid is
further injected after tip screen out, but rather than extending
the inclusion laterally or vertically, the injected fracture fluid
widens, i.e. thickens, and fills the inclusion 30 from the
inclusion tips back to the well casings 21 within the well
bore.
[0044] The behavioral characteristics of the viscous injected
fracture fluid are preferably controlled to ensure the propagating
viscous planar inclusions 30 maintain their azimuth directionality,
such that the viscosity of the injected fracture fluid and its
volumetric rate are controlled within certain limits depending on
the formation 24, the specific gravity of the proppant 51, and the
size distribution of the proppant 51. For example, the viscosity of
the injected fracture fluid is preferably greater than
approximately 100 centipoise. If, however, a foamed injected
fracture fluid is used, a greater range of viscosity and injection
rate may be permitted while still maintaining directional and
geometric control over the planar inclusions 30. The viscosity and
volumetric rate of the injected fracture fluid needs to be
sufficient to transport the proppant 51 to the extremities of the
planar inclusions 30. The size distribution of the proppant 51
needs to be matched with that of the formation 24, to ensure
formation fines do not migrate into the propped planar inclusion 30
during hydrocarbon fluid production. Typical size distribution of
the proppant 51 would range from #12 to #20 U.S. mesh for oil sand
formations, with an ideal proppant 51 being sand or ceramic beads
and could also contain a mixture of fibers. Resin coated sand or
ceramic beads are capable of mechanically binding the proppant 51
together without loss of permeability of the propped planar
inclusion 30.
[0045] With continuing reference to FIG. 3, the well systems 20,
have carbon dioxide injected into the formation 24 through the
carbon dioxide conduits 25, and the hydrocarbons are produced to
the surface 5 by the high energy oil production pump 28 through the
oil production tubes 27 placed inside of the well casings 21. The
oil is mobilized by the miscible carbon dioxide, flows under
gravity from the formation 24 through the planar inclusions 30
towards the well systems 20, enters the sumps 23, and is pumped to
surface 5 via the production tubes 27 by means of the production
pump 28 that may include a PCP (progressive cavity pump), ESP
(electrical submersible pump), gas lift, or natural lift, depending
on operating temperatures, pressures, and depth of the well systems
20. The level of hydrocarbon fluids (oil) in the well systems 20
will be maintained above the inlets (sump 23) to the production
tubes 27 to ensure carbon dioxide is not produced from the
formation 24 up the production tubes 27. The production of
hydrocarbon fluids includes the production of methane from the high
energy formation and the low energy formation from a first portion
of the well casing 21 located at the highest elevation in the high
energy formation 24 and from a second portion of the well casing 11
located at the highest elevation in the low energy formation
14.
[0046] The formation 24 could be comprised of relatively hard and
brittle rock, but the well systems 20 and the method find
especially beneficial application in ductile rock formations made
up of unconsolidated or weakly cemented sediments, in which it is
typically very difficult to obtain directional or geometric control
over inclusions as they are being formed.
[0047] The selected range of temperatures and pressures to operate
the process with the well systems 20 will depend on reservoir
depth, ambient conditions, the quality of the in place oil and the
presence of nearby water bodies. The process is operated at a
pressure and temperature range that is optimal for miscible
conditions of the carbon dioxide, plus maximizing the density
difference of the oil and supercritical carbon dioxide to provide
an efficient energy storage scheme. The operating pressure of the
process may be selected to closely match the ambient reservoir
conditions to minimize water inflow into the process zone and the
well bore by the injection of the supercritical carbon dioxide.
[0048] In FIG. 4, the physical states of the carbon dioxide are
shown at various temperatures and pressures, as a gas 40, as a
solid 41, as a liquid 42, and as a supercritical fluid 43. The
critical point 44 is at a temperature of 304.25.degree. K and at a
pressure of 72.9 bar.
[0049] In FIG. 5, the density of the carbon dioxide is shown at
various temperatures and pressures. The critical point 44 is shown
in FIG. 4. At a temperature 45 of 310.degree. K, the density of the
carbon dioxide changes significantly with pressure, while at a
higher temperature 46 of 330.degree. K, the change is less. While
at a still at higher temperature 47 of 400.degree. K, the density
change with pressure is much more like a gas. It is therefore
imperative to site the system 9 at pressure and temperature
conditions in formations 24 and 14 that yield the most optimal
energy storage scheme and the viable enhanced recovery of
hydrocarbon fluids. Thus the system 9 is better suited for
formations that are in areas of high geothermal heat flow to
achieve an optimal system 9.
[0050] In FIG. 6, a variation of the carbon energy storage and oil
recovery system 9 is shown, wherein the high energy formation 24 is
located below the low energy formation 14. In this case, the high
energy well system 20 and at the low energy well system 10 can be
constructed with a single well casing 11 that penetrates both
formations 24 and 14. In this system 9, the pump/turbine 34 is
located in the subsurface between the high energy well system 20
and the low energy well system 10 and is connected to the carbon
dioxide conduit 15. Such an arrangement can achieve a more optimum
efficient system 9 compared to the surface located pump/turbine 34
shown in the system 9 in FIG. 1.
[0051] However, the present disclosure provides information to
enable those skilled in the art of oil recovery, energy storage,
hydraulic fracturing, and soil and rock mechanics to practice the
method enabled by system 9 and for well systems 20 and 10 to
initiate and control the propagation of a viscous injected fracture
fluid in weakly cemented sediments, and importantly for the
propagating planar inclusions 30 to intersect and coalesce with
earlier placed permeable planar inclusions 30 and thus form a
continuous planar inclusion 30 on a particular azimuth from within
a single well system 20 or 10 or between multiple well systems.
[0052] The system 9 and associated method are applicable to
formations 24 and 14 of weakly cemented sediments with low cohesive
strength compared to the vertical overburden stress prevailing at
the depth of interest. Low cohesive strength is defined herein as
no greater than 3 MegaPasca (MPa) plus 0.4 times the mean effective
stress (p') in MPa at the depth of propagation.
c<3 MPa+0.4p' (1)
where c is cohesive strength in MPa and p' is mean effective stress
in the formation.
[0053] Examples of such weakly cemented sediments are sand and
sandstone formations, mudstones, shales, and siltstones, all of
which have inherent low cohesive strength. Critical state soil
mechanics assists in defining when a material is behaving as a
cohesive material capable of brittle fracture or when it behaves
predominantly as a ductile frictional material.
[0054] Weakly cemented sediments are also characterized as having a
soft skeleton structure at low effective mean stress due to the
lack of cohesive bonding between the grains. On the other hand,
hard strong stiff rocks will not substantially decrease in volume
under an increment of load due to an increase in mean stress.
[0055] In the art of poroelasticity, the Skempton B parameter is a
measure of a sediment's characteristic stiffness compared to the
fluid contained within the sediment's pores. The Skempton B
parameter is a measure of the rise in pore pressure in the material
for an incremental rise in mean stress under undrained
conditions.
[0056] In stiff rocks, the rock skeleton takes on the increment of
mean stress and thus the pore pressure does not rise, i.e.,
corresponding to a Skempton B parameter value of at or about 0. But
in a soft soil, the soil skeleton deforms easily under the
increment of mean stress and, thus, the increment of mean stress is
supported by the pore fluid under undrained conditions
(corresponding to a Skempton B parameter of at or about 1).
[0057] The following equations illustrate the relationships between
these parameters in equations denoted as (2) as follows:
.DELTA.u=B.DELTA.p
B=(K.sub.u-K)/(.alpha.K.sub.u)
.alpha.=1-(K|K.sub.s) (2)
where .DELTA.u is the increment of pore pressure, B the Skempton B
parameter, .DELTA.p the increment of mean stress, K.sub.u is the
undrained formation bulk modulus, K the drained formation bulk
modulus, .alpha. is the Biot-Willis poroelastic parameter, and
K.sub.s is the bulk modulus of the formation grains. In the system
9 and associated method, the bulk modulus K of the formation for
inclusion propagation is preferably less than approximately 5
GPa.
[0058] For use of the system 9 and method in weakly cemented
sediments, preferably the Skempton B parameter is as follows with
p' in MPa:
B>0.95exp(-0.04p')+0.008p' (3)
[0059] The system 9 and associated method are applicable to the
formations 24 and 14 of weakly cemented sediments (such as tight
gas sands, mudstones and shales) where large extensive propped
vertical permeable drainage planar inclusions 30 are desired to
intersect thin sand lenses and provide drainage paths for greater
gas production from the formations. In weakly cemented formations
containing heavy oil (viscosity>100 centipoise) or bitumen
(extremely high viscosity>100,000 centipoise), generally known
as oil sands, propped vertical permeable drainage planar inclusions
30 provide drainage paths for cold production from these
formations, and access for steam, solvents, oils, and heat to
increase the mobility of the petroleum hydrocarbons (oil) and thus
aid in the extraction of the hydrocarbon fluids from the formation.
In highly permeable weak sand formations, permeable drainage planar
inclusions 30 of large lateral length result in lower drawdown of
the pressure in the reservoir, such as formation 24, which reduces
the fluid gradients acting towards the well casing 21, resulting in
less drag on fines in the formation 24, and resulting in reduced
flow of formation fines into the well casing 21.
[0060] The 51 proppant is carried by the injected fracture fluid
resulting in a highly permeable planar inclusion 30. Such proppants
51 are typically clean sand or specialized manufactured particles
(generally ceramic in composition), and depending on the size
composition, closure stress and proppant type, the permeability of
the fracture can be controlled. Either type of proppant 51 could be
resin coating to provide for bounding between proppant particles.
The proppant 51 could contain fibers, composed of carbon,
polyethylene and/or rubber of diameter similar to the sand proppant
but with lengths greater than 10.times. the sand proppant diameter.
The permeability of the propped planar inclusions 30 will typically
be orders of magnitude greater than the formation 24 permeability,
generally at least by two orders of magnitude.
[0061] The injected fracture fluid varies depending on the
application and can be water, oil, or multi-phased based gels.
Aqueous based injected fracture fluids consist of a polymeric
gelling agent such as solvatable (or hydratable) polysaccharide,
e.g. galactomannan gums, glycomannan gums, and cellulose
derivatives. The purpose of the hydratable polysaccharides is to
thicken the aqueous solution and thus act as viscosifiers, i.e.
increase the viscosity by 100 times or more over the base aqueous
solution of the injected fracture fluid. A cross-linking agent can
be added which further increases the viscosity of the solution of
the injected fracture fluid. The borate ion has been used
extensively as a cross-linking agent for hydrated guar gums and
other galactomannans (see U.S. Pat. No. 3,059,909 to Wise). Other
suitable cross-linking agents are chromium, iron, aluminum,
zirconium (see U.S. Pat. No. 3,301,723 to Chrisp), and titanium
(see U.S. Pat. No. 3,888,312 to Tiner et al). A breaker is added to
the solution of the injected fracture fluid and to controllably
degrade the viscous fracturing injected fracture fluid. Common
breakers are enzymes and catalyzed oxidizer breaker systems, with
weak organic acids sometimes used.
[0062] Finally, it will be understood that the preferred embodiment
has been disclosed by way of example, and that other modifications
may occur to those skilled in the art without departing from the
scope and spirit of the appended claims.
* * * * *