U.S. patent application number 14/495245 was filed with the patent office on 2015-01-15 for method of using carbon dioxide in recovery of formation deposits.
This patent application is currently assigned to Palmer Labs, LLC. The applicant listed for this patent is 8 Rivers Capital, LLC, Palmer Labs, LLC. Invention is credited to Rodney John Allam, Glenn William Brown, JR., Jeremy Eron Fetvedt, David Arthur Freed, Miles R. Palmer.
Application Number | 20150013977 14/495245 |
Document ID | / |
Family ID | 45816683 |
Filed Date | 2015-01-15 |
United States Patent
Application |
20150013977 |
Kind Code |
A1 |
Palmer; Miles R. ; et
al. |
January 15, 2015 |
METHOD OF USING CARBON DIOXIDE IN RECOVERY OF FORMATION
DEPOSITS
Abstract
The present invention relates to systems, apparatuses, and
methods for providing a reliable, high purity source of CO.sub.2
that is used in the recovery of formation deposits, such as fossil
fuels. At least a portion of the fossil fuels recovered may be
directly combusted or extracted using the same process used to
provide the pure source of CO.sub.2 without the need to first
remove CO.sub.2, sulfur, other fossil fuels, or other
impurities.
Inventors: |
Palmer; Miles R.; (Chapel
Hill, NC) ; Allam; Rodney John; (Wiltshire, GB)
; Fetvedt; Jeremy Eron; (Raleigh, NC) ; Freed;
David Arthur; (New York, NY) ; Brown, JR.; Glenn
William; (Durham, NC) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Palmer Labs, LLC
8 Rivers Capital, LLC |
Durham
Durham |
NC
NC |
US
US |
|
|
Assignee: |
Palmer Labs, LLC
8 Rivers Capital, LLC
|
Family ID: |
45816683 |
Appl. No.: |
14/495245 |
Filed: |
September 24, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
13236095 |
Sep 19, 2011 |
8869889 |
|
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14495245 |
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61506429 |
Jul 11, 2011 |
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61385069 |
Sep 21, 2010 |
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Current U.S.
Class: |
166/266 ;
166/268; 166/52; 166/63 |
Current CPC
Class: |
E21B 43/168 20130101;
E21B 43/164 20130101; F23J 15/00 20130101; E21B 43/34 20130101;
E21B 43/40 20130101; Y02P 90/70 20151101; E21B 36/02 20130101 |
Class at
Publication: |
166/266 ;
166/268; 166/63; 166/52 |
International
Class: |
E21B 43/16 20060101
E21B043/16; F23J 15/00 20060101 F23J015/00; E21B 43/34 20060101
E21B043/34 |
Claims
1. A method for recovering a fuel material deposit from a
formation, the method comprising: providing a combustion fuel and
an oxidant into a combustor; combusting the combustion fuel to
provide a CO.sub.2 containing stream comprising supercritical
CO.sub.2; and injecting at least a portion of the CO.sub.2
containing stream into the formation including the fuel material
deposit for recovery such that at least a portion of the fuel
material in the formation and at least a portion of the CO.sub.2
stream flow from the formation and into a recovery well.
2. The method of claim 1, wherein the combustion fuel and oxidant
are provided into a combustor positioned above ground.
3. The method of claim 2, further comprising, after said combusting
step and prior to said injecting step, expanding the CO.sub.2
containing stream across a turbine for power generation to form an
expanded CO.sub.2 containing stream.
4. The method of claim 3, further comprising, prior to said
injecting step, passing the expanded CO.sub.2 containing stream
sequentially through a heat exchanger that cools the CO.sub.2
containing stream and through one or more separators that removes
one or more secondary components present in the CO.sub.2 containing
stream.
5-17. (canceled)
18. The method of claim 1, further comprising receiving from the
recovery well a recovery stream comprising the fuel material and
the CO.sub.2.
19. The method of claim 18, further comprising separating the
recovery stream into a recovered gas stream and a recovered liquid
stream.
20. The method of claim 19, wherein the recovered gas stream
comprises methane and CO.sub.2.
21. The method of claim 20, wherein the recovered gas stream
further comprises one or more of C.sub.2 hydrocarbons, C.sub.3
hydrocarbons, and C.sub.4 hydrocarbons.
22. The method of claim 19, wherein the recovered liquid stream
comprises petroleum.
23. The method of claim 22, wherein the petroleum comprises crude
oil.
24. The method of claim 19, wherein the recovered liquid stream
comprises a fluidized solid fuel material.
25. The method of claim 19, comprising directing at least a portion
of the recovered gas stream to the combustor as at least a portion
of the combustion fuel.
26. The method of claim 19, wherein said separating comprises
directing the recovery stream through at least one pressure letdown
stage at a defined pressure whereby one or more fuel material gas
fractions are withdrawn and the remaining fraction of the recovery
stream at the defined pressure comprises liquid fuel material.
27. The method of claim 26, wherein one or more of the fuel
material gas fractions comprises the CO.sub.2.
28. The method of claim 27, further comprising directing a fuel
material gas fraction comprising the CO.sub.2 to the combustor as
at least a portion of the combustion fuel.
29-50. (canceled)
51. An apparatus for producing a CO.sub.2 containing stream
down-hole in a well, the apparatus comprising: a combustor; a
combustion fuel supply in fluid connection with the combustor; an
oxidant supply in fluid connection with the combustor; a chamber
within the combustor wherein combustion of the fuel occurs at a
temperature of at least about 600.degree. C. to produce the
CO.sub.2 containing stream; and an outlet on the combustor that
delivers the CO.sub.2 containing stream from the combustor and into
the well.
52. The apparatus of claim 51, wherein the outlet comprises a
conically shaped nozzle that concentrates the CO.sub.2 containing
stream delivered therefrom.
53. A system for generating CO.sub.2 and recovering a fuel material
deposit from a formation, the system comprising: a combustor; a
combustion fuel supply in fluid connection with the combustor; an
oxidant supply in fluid connection with the combustor; a chamber
within the combustor configured for receiving and combusting the
combustion fuel to provide a CO.sub.2 containing stream comprising
supercritical CO.sub.2; an injection component that delivers the
CO.sub.2 containing stream into the formation including the fuel
material deposit such that at least a portion of the fuel material
in the formation and at least a portion of the CO.sub.2 stream flow
from the formation and into a recovery well as a recovery stream;
and one or more processing components for processing the recovered
fuel material and CO.sub.2 in the recovery stream
54-61. (canceled)
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present application claims priority to U.S. Provisional
Patent Application No. 61/506,429, filed Jul. 11, 2011, and U.S.
Provisional Patent Application No. 61/385,069, filed Sep. 21, 2010,
the disclosures of which are both incorporated herein by reference
in their entireties.
FIELD OF THE INVENTION
[0002] The present invention is directed to systems and methods for
use of CO.sub.2 in the recovery of formation deposits. In
particular, the invention provides systems and methods for
directing CO.sub.2 from a combustion process into a geologic
formation to facilitate recovery of one or more formation deposits
from the geologic formation, such as fuel material deposits.
BACKGROUND OF THE INVENTION
[0003] Numerous useful materials for energy production are found
naturally in the earth. For example, fossil fuels (e.g., crude oil,
natural gas, and coal) are located as deposits in various rock
formations throughout the world, and man has been recovering such
materials for many years through mining, drilling, and the like. As
more readily obtainable deposits are exhausted, advanced techniques
to facilitate the recovery of the useful materials are continually
being sought.
[0004] As an example, the use of fluids and fluidized mixtures for
enhancing the recovery of various fossil fuels has been under
development for several years. The mechanisms for enhanced recovery
generally are based on enhancing the flow of the fossil fuel
through its surrounding geologic formation toward an extraction
well. Three predominant mechanisms for enhancing fossil fuel
recovery in this manner include the following: 1) using fluids for
creating and sustaining fractures in rocky formations to promote
more free flow passages; 2) relying on the injection of fluids for
volumetric or pressurized displacement of the fossil fuel; and 3)
commingling the fluid with the fossil fuel such that one or both of
the density and viscosity of the fossil fuel is reduced. Viscosity
also may be reduced by mixing other materials into the fossil fuel,
by heating the fossil fuel, or both. All of these mechanisms
involve injecting material into a well or wells, and then obtaining
increased fossil fuel output from the injection well or wells (or
from one or more other wells in the vicinity).
[0005] Fracturing as a method to enhance fossil fuel recovery
typically is done from a wellbore drilled into a reservoir rock
formation. A hydraulic fracture can be formed by pumping the
fracturing fluid into the wellbore at a rate sufficient to increase
the pressure down-hole to a value in excess of the fracture
gradient of the formation rock. The pressure causes the formation
to crack, allowing the fracturing fluid to enter and extend the
crack further into the formation. To keep this fracture open after
the injection stops, a solid proppant usually is added to the
fracture fluid. The proppant, which is commonly a sieved round
sand, is carried into the fracture. This sand is chosen to be
higher in permeability than the surrounding formation, and the
propped hydraulic fracture then becomes a high permeability conduit
through which the formation fluids can flow to the well. A variety
of fluids have been proposed and used as fracture fluids,
displacement fluids, and viscosity reduction fluids to enhance
recovery for fossil fuel reservoirs. Existing methods, however,
employ fluids with highly controversial environmental impacts, less
than desired effectiveness, or high cost, or a combination of these
factors. Some environmental and human health concerns that have
been suggested to be associated with fluids typically used in prior
art hydraulic fracturing include the potential mishandling of solid
toxic waste, potential risks to air quality, potential
contamination of ground water, and the unintended migration of
gases and hydraulic fracturing chemicals to the surface within a
given radius of drilling operations.
[0006] Fluids, such as water and steam, with or without surfactants
and with or without high heat values, have often shown less than
desired performance for enhancing fossil fuel recovery. Key reasons
are that water can be much denser than certain fossil fuels, and
water is a liquid under equilibrium conditions. Such chemical
factors limit or largely eliminate miscibility and mixing between
the water/steam and the hydrophobic fossil fuel, thus limiting or
largely eliminating any reduction in viscosity of the fossil fuel.
The higher density of water can lead to initial physical
displacement of the fossil fuel, but this effect is often limited
in time and efficiency to an undesirable extent. The denser water
may flow downward and away from the fossil fuel reservoir, quickly
decreasing or eliminating any displacement effect.
[0007] Supercritical carbon dioxide can be highly useful for
enhancing oil recovery. Specifically, the supercritical fluid
nature and chemical nature of the material causes it to be miscible
with oil to lower the viscosity and density of the oil, and/or to
improve the oil flow through the formation. Also, the density of
supercritical carbon dioxide is substantially lower than the
density of water, and it therefore tends to rise into the fossil
fuel reservoir rather than to flow downward as does denser water.
Furthermore, the material properties of the supercritical CO.sub.2
allow it to function as a better solvent for other materials as
well. Specifically, as compared to gaseous or liquid CO.sub.2,
supercritical CO.sub.2 exhibit material properties that can
substantially increase its dissolution properties. Presently, in
order to use supercritical carbon dioxide in recovery methods, the
CO.sub.2 must be transported from its source (either natural or
anthropogenic) to a site of use.
[0008] As much as 70% of oil presently in formations is
unrecoverable without the use of enhanced oil recovery methods,
particularly CO.sub.2 led EOR. Despite its potential, there are
several limiting factors with EOR in the current art. Primarily,
the industrial creation of purified CO.sub.2 is overly expensive to
separate, purify, and compress in use for EOR as it normally
requires large capital and operating investments in the form of
system additions, such as amine and/or other solvent scrubbers.
Even thereafter, the CO.sub.2 must be compressed to a sufficient
pressure to inject into the well. These systems are not only
expensive and potentially hazardous to the environment, but also
require energy, thus limiting the efficiency of the overall system.
Secondly, pipeline networks are needed and are not sufficient in
the majority of locations where EOR is a possibility, thus limiting
its exposure to a significant number of formations. In current
instances, pipeline networks have been fed from geologic CO.sub.2
sources. However, these are extremely limited in location and
amounts of CO.sub.2 available.
[0009] Moreover, in an economic and political backdrop where
CO.sub.2 emissions are tightly monitored and always discouraged, it
is generally undesirable to open CO.sub.2 deposits that already are
geologically sequestered.
[0010] When fossil fuels are removed from underground deposits
using enhanced recovery methods, they often contain dissolved
CO.sub.2 and other impurities which must be separated using
processes such as absorption processes. These can include the
following: chemical, physical, and/or solid surface processes;
physical separation through membrane or cryogenic means; or hybrid
solutions that offer mixed physical and chemical solvents. Such
processes may include, but are not limited to, the expensive and
inefficient Ryan/Holmes process, the Low-Temperature Separator
(LTX) process, the FLUOR amine process, the Selexol process, the
Rectisol process, and others. These processes are used to remove
the CO.sub.2 content of the natural gas separated from liquid oil
so that the useful gas fraction (e.g., CH.sub.4 fraction) can be
produced at a sufficient purity for sale in pipeline systems and so
that C.sub.2 and greater hydrocarbon fractions can be separated for
sale. Moreover, the processes can be used to process flue gas
and/or sour gas before it can be transported or re-used. In some
instances where the CO.sub.2 content is of sufficient quantity
(e.g., greater than 30% by weight or partial pressure), the
separated CO.sub.2 can be recycled for further EOR duty.
Specifically, regarding other impurities, natural gas that contains
high amounts of hydrogen sulfides (typically an H.sub.2S content
exceeds 5.7 mg per cubic meter) is known as sour gas, and the
H.sub.2S must be removed (i.e., so that the natural gas is
"sweetened") using processes such as the amine process or Claus
process before injection into pipelines. These impurity removal
processes can have detrimental effects on the environment, system
efficiency, and overall recovery costs.
[0011] Even when CO.sub.2 is used for enhanced recovery, the
recoverable fossil fuels present in a formation are eventually
depleted. The CO.sub.2 injection system must then be disassembled
and either moved to a new location, which may be very distant, or
discontinued and scrapped. This requires the installation of
CO.sub.2 transmission pipelines with significant permitting, time,
and expense requirements. Alternately, the disadvantages of moving
CO.sub.2 to an injection site still can hinder economical and even
successful use of CO.sub.2 in an enhanced recovery method for
fossil fuel.
[0012] There particularly is a need for methods of EOR to be
applied to the recovery of very heavy oils, such as oil below about
15 API gravity, bitumen, and tar sands. Heavy oil deposits are
often recovered by injection of steam produced from surface steam
generators or as pass-out steam from a steam based power generation
system. These systems are often old, inefficient and highly
polluting, particularly with high CO.sub.2 emissions. Accordingly
there have been efforts to design a heat generation device which is
compact enough to be contained within the well bore and which can
combust a fossil fuel within the reservoir producing not only heat
but also CO.sub.2 and steam which act to displace the heated lower
viscosity oil. U.S. Pat. No. 4,397,356 describes a down-hole
combustor in which a fuel and an oxidant are burned within a burner
which includes a catalytic section to ensure complete combustion
with no soot formation, which would block the face of the oil
reservoir.
[0013] Such efforts, however, still fall short of providing
sufficient means for enhancing recovery of a wide variety of
formation deposits in a wide variety of settings in a manner that
is efficient, economical, environmentally friendly, and easily
mobilized for transport to different job sites as needed.
Accordingly, there remains a need in the field for further systems
and methods for enhancing recovery of formation deposits that not
only lessen the impact on the environment but also possibly provide
solutions to other existing energy generation issues.
SUMMARY OF THE INVENTION
[0014] The present invention provides systems and methods for
enhancing the recovery of a variety of formation deposits
including, but not limited to, fossil fuels and other commodities.
Beneficially, enhanced recovery can be achieved using CO.sub.2 that
can be directed from a combustion process that optionally can
provide power while also providing the CO.sub.2 used in the
enhanced recovery methods.
[0015] In various embodiments related to recovery of fossil fuels,
the CO.sub.2 can be used for creating and sustaining fractures in
rocky formations to promote more free flow passages for the fossil
fuels contained in the formations; for displacing hydrocarbons
(e.g., methane) from formation surfaces, such as in coal bed
methane formations; for providing volumetric or pressurized
displacement of the fossil fuels within a formation; and for
commingling with the fossil fuel such that one or both of the
density and viscosity of the fossil fuel is reduced. Still further,
the CO.sub.2 (alone or with water, preferably in the form of steam,
or other materials) can be used to reduce the viscosity of the
fossil fuel (e.g., heavy oils) directly by admixing with the fossil
fuel or indirectly by heating the fossil fuel, or both.
[0016] The inventive methods and systems utilizing CO.sub.2 for
enhancing recovery of fuel material deposits can exhibit a variety
of useful characteristics. For example, is some embodiments, the
CO.sub.2 used can be obtained as a byproduct (e.g., as a combustion
product) from a power generation process (e.g., that combusts a
fossil fuel). In certain embodiments, the CO.sub.2 can be supplied
from a power generation process at a pressure that is suitable for
direct injection into a deposit formation, specifically a
geological structure or rock formation. In other embodiments, the
CO.sub.2 can be supplied from a power generation process at a
location that is suitable for direct injection into the deposit
formation. More specifically, such direct deposit can mean that any
CO.sub.2 transmission pipeline associated with transmission of the
CO.sub.2 for injection would have a minimum to near zero
length--e.g., less than about 10 miles, less than about 5 miles,
less than about 1 mile, less than about 1,000 feet, or less than
about 100 feet. In further embodiments, the invention can provide a
transportable CO.sub.2 generating system than can be installed at
or near the point of use of the CO.sub.2--e.g., in the same field
with one or more wells or even directly within a well bore. In
additional embodiments, the invention can provide a transportable
CO.sub.2 generating system than can be easily disassembled,
relocated, and reassembled at one or more subsequent points of use
of the CO.sub.2 after use of the system at a first point. In still
other embodiments, the invention can provide a transportable
CO.sub.2 generating system than can be connected to the point of
use of the CO.sub.2 without a pipeline or with a pipeline of
minimum length, as otherwise described herein.
[0017] In various embodiments, the power generation process from
which the CO.sub.2 is derived can be at least partially fueled
using a stream separated from a fuel material fraction recovered
according a method of the invention. In certain embodiments, the
separated stream (which may be a gas stream) can contain at least
CO.sub.2, and the separated stream can be used with no further
process steps to remove hydrocarbon or contaminant components
present before being optionally compressed and becoming at least
part of the fuel feed to a power production process from which
CO.sub.2 is derived. In preferred embodiments, a power production
process useful according to the invention can use CO.sub.2 as a
working fluid.
[0018] The invention generally encompasses a process that produces
CO.sub.2, and such process can be used likewise to produce
electricity, which adds value. Optionally the process can be
simplified substantially to a combustor only. In this case, the
capital cost is extremely low. This case is optimum when the fuel
cost is very low, as in locations where natural gas (NG) is flared,
or when coal slurry is available as a low cost fuel.
[0019] In other embodiments, the combustor can be used for direct
injection of CO.sub.2 (and/or optionally water) into a reservoir
suitable for recovery of deposits, such as fossil fuels. Any
combination of fuel gas, oxygen, water, nitrogen, argon, air, and
other additives may be added into a high pressure and high
temperature combustor.
[0020] In one embodiment, the CO.sub.2 (and/or water) as a result
of combustion (above ground or down-hole) can be directed into a
reservoir suitable for fossil fuel recovery. In another embodiment,
the CO.sub.2 (and/or water) can be directed through any combination
of coolers, filters, and pumps before injection into a well for
fossil fuel recovery. This embodiment may particularly be used only
for the production of supercritical CO.sub.2 to enhance recovery of
fossil fuels from appropriate reservoirs. In these processes,
carbon dioxide can be compressed to significant pressure--often in
excess of 200 bar (20 MPa) to inject into underground formations
that have lost the necessary pressure to facilitate flow of the
fossil fuels, and other substances, to a well bore for removal.
Carbon dioxide can act to re-pressure the underground formation and
acts as a natural surfactant to swell and/or remove the oil and
other fossil fuels from rock surfaces and pores. In the case of
enhanced coal bed methane recovery (ECBMR) and other forms of
natural gas recovery, coal beds and other underground structures
are flooded or fractured with CO.sub.2, again acting to either
pressurize the well, break the rock to free the gas, or as a
natural surfactant to remove the natural gas. In the case of coal
bed methane, the CO.sub.2 displaces CH.sub.4 and various short
chain hydrocarbon gases associated with (e.g., adsorbed on) the
coal particle surfaces, and the CO.sub.2 itself then becomes
adsorbed on the coal, effectively sequestering the CO.sub.2 in the
formation.
[0021] In yet other embodiments, the combustor may be specifically
located down-hole to generate steam and/or heat in enhanced
recovery applications, such as EOR, particularly in formations
where the API of the fuel material is below about 20 such as in tar
sands. In a fuel material bearing formation, a water-quenched
down-hole combustor can generate steam and heat to remove the fuel
material. In one embodiment, as a pressurized stream containing the
fuel material leaves the reservoir, the stream goes through an
expander and into a reservoir where heavy oil is removed. The water
and/or CO.sub.2 is then directed through power production
components to generate electricity, and CO.sub.2 is produced to
dilute the fuels going into the down-hole combustor.
[0022] The present invention is particularly beneficial in that a
reliable, consistent, high purity source of CO.sub.2 can be
provided for use as a recovery fluid. Since the CO.sub.2 produced
from the power production process is directed to the recovery
method, this beneficially prevents immediate release of the
CO.sub.2 to the atmosphere as the CO.sub.2 rather can be
sequestered in the fossil fuel reservoir (at least in part) after
down-hole pumping for recovery purposes and/or will be recycled
through the process one or more times. Moreover, the availability
of a reliable, consistent, high purity source of CO.sub.2 can
replace the use of environmentally damaging materials as fracturing
fluids since the CO.sub.2 can be a readily available, cost-saving
alternative to more toxic options.
[0023] In another embodiment, the CO.sub.2 stream coming out of the
down-hole combustor or high efficiency cycle can also be cooled
with water to create a steam generator. The invention further
provides the option to use water steam as a transpiration
fluid.
[0024] More specifically, the present invention can be directed to
methods for recovering a fuel material deposit from a formation.
The method can comprise combusting a fuel to provide a CO.sub.2
containing stream wherein at least a portion of the CO.sub.2 is in
a supercritical state. In other words, at least a portion of the
stream can comprise supercritical CO.sub.2. The method further can
comprise injecting at least a portion of the CO.sub.2 containing
stream into the formation including the fuel material deposit for
recovery such that at least a portion of the fuel material in the
formation and at least a portion of the CO.sub.2 stream flow from
the formation and into a recovery well.
[0025] In more particular embodiments, noted method may take on a
variety of characteristics. Non-limiting examples of the further
embodiments are noted below.
[0026] The CO.sub.2 containing stream may exhibit a pressure of at
least 7.5 MPa when the CO.sub.2 containing stream is injected into
the formation.
[0027] The combusting step may be performed above-ground at a
location that is a short distance (e.g., less than about 5 km) from
the site where the CO.sub.2 containing stream is injected into the
formation.
[0028] Prior to being injected into the formation, the CO.sub.2
containing stream may be expanded across a turbine for power
generation.
[0029] The CO.sub.2 containing stream from the combusting may be
injected into the formation without any intervening compression,
collection, or transport to the site where the CO.sub.2 containing
stream is directed into the formation. Similarly, the CO.sub.2
containing stream may be directly injected into the formation
without undergoing any intervening processing.
[0030] The CO.sub.2 containing stream may be injected into the
formation through an injection well. Further, the combusting step
may be performed down-hole in the injection well.
[0031] The combusting step may particularly be carried out using a
transpiration cooled combustor. More particularly, the method can
comprise providing a fuel, an oxidant, and a transpiration fluid to
the transpiration cooled combustor. Even more particularly, the
method can comprise providing a working fluid to the combustor that
is different from the transpiration fluid.
[0032] In certain embodiments, a method for recovering a fuel
material deposit from a formation according to the invention may
comprise the following steps: providing a combustion fuel and an
oxidant into a transpiration cooled combustor; combusting the
combustion fuel to provide a CO.sub.2 containing stream comprising
supercritical CO.sub.2; and injecting at least a portion of the
CO.sub.2 containing stream into the formation including the fuel
material deposit for recovery such that at least a portion of the
fuel material in the formation and at least a portion of the
CO.sub.2 stream flow from the formation and into a recovery
well.
[0033] In particular, combustion may be carried out above ground.
Thus, the combustion fuel and oxidant can be provided into a
transpiration cooled combustor positioned above ground.
[0034] After combusting and prior to injecting, the method can
include expanding the CO.sub.2 containing stream across a turbine
for power generation to form an expanded CO.sub.2 containing
stream. The expanded CO.sub.2 containing stream can be passed
through a heat exchanger that cools the CO.sub.2 containing stream
and/or through one or more separators that removes one or more
secondary components present in the CO.sub.2 containing stream.
Preferably, the cooling is carried out first and the separation
follows sequentially thereafter.
[0035] Also prior to injecting, the CO.sub.2 containing stream can
be separated into an injection CO.sub.2 stream that is injected
into the formation and a recycle CO.sub.2 stream that is provided
into the transpiration cooled combustor as a working fluid. To this
end, the method further can comprise one or more of compressing the
recycle CO.sub.2 stream by passing the stream through a compressor
and heating the recycle CO.sub.2 stream by passing the stream
through the heat exchanger that cooled the expanded CO.sub.2
containing stream. Accordingly, the method can then encompass
providing the recycle CO.sub.2 stream into the combustor as the
working fluid. Preferably, the recycle CO.sub.2 stream may be
provided into the combustor at a pressure of at least about 2 MPa.
In some embodiments, at least a portion of the recycle CO.sub.2
stream is provided into the combustor as at least a portion of a
transpiration fluid used to cool the transpiration cooled
combustor. It also can be preferably for the recycle CO.sub.2
stream to be provided into the combustor at a specific purity
level--e.g., having a purity of at least 95% molar.
[0036] The pressure of the CO.sub.2 containing stream can vary
throughout the method. For example, the expanded CO.sub.2
containing stream may have a pressure of at least about 1.5 MPa.
Further, the CO.sub.2 containing stream injected into the formation
may have a pressure of at least about 7.5 MPa. Pressure may be
relevant to the state of the CO.sub.2. Specifically, it may be
preferable for the CO.sub.2 containing stream that is injected into
the formation to comprise supercritical CO.sub.2. Similarly,
combusting may be carried out at a specific temperature
range--e.g., at a temperature of at least about 400.degree. C.
[0037] In particular embodiments, the combustion fuel and the
oxidant may be provided into a transpiration cooled combustor that
is positioned down-hole in a well that opens into a formation. In
such embodiments, the invention also may comprise providing water
into the transpiration cooled combustor such that the CO.sub.2
containing stream further includes steam. Specifically, the water
may be provided into the transpiration cooled combustor as a
transpiration cooling fluid.
[0038] As noted previously, the inventive methods further can
comprise receiving from the recovery well a recovery stream
comprising the fuel material and the CO.sub.2. Accordingly, the
methods may comprise separating the recovery stream into a
recovered gas stream and a recovered liquid stream. Specifically,
the recovered gas stream may comprise methane and CO.sub.2 (as well
as, optionally, one or more of C.sub.2 hydrocarbons, C.sub.3
hydrocarbons, and C.sub.4 hydrocarbons). The recovered liquid
stream specifically may comprise petroleum (which particularly may
be crude oil, but does not exclude gaseous and/or solid forms of
petroleum). In some embodiments, the recovered liquid stream may
comprise a fluidized solid fuel material.
[0039] In certain embodiments, the inventive methods may comprise
directing at least a portion of the recovered gas stream to the
combustor as at least a portion of the combustion fuel. To this
end, separating can comprise directing the recovery stream through
at least one pressure letdown stage at a defined pressure whereby
one or more fuel material gas fractions are withdrawn and the
remaining fraction of the recovery stream at the defined pressure
comprises liquid fuel material. In particular embodiments, one or
more of the fuel material gas fractions can comprise the CO.sub.2.
Also, the methods further can comprise directing a fuel material
gas fraction comprising the CO.sub.2 to the combustor as at least a
portion of the combustion fuel. The methods also can comprise
passing the fuel material gas fraction through a compressor that
increases the pressure of the fuel material gas fraction prior to
being introduced into the combustor. In specific embodiments,
separating can result in a plurality of fuel material gas
fractions, and each of the fractions may comprise CO.sub.2. In such
embodiments, two or more of the plurality of fuel material gas
fractions comprising CO.sub.2 can be combined and directed to the
combustor as at least a portion of the combustion fuel. This
further may comprise passing the fuel material gas fractions
through a compressor that increases the pressure of the fuel
material gas fractions prior to being introduced into the
combustor. Such compressor specifically may be a multi-stage
compressor. Preferably, the separation steps will substantially
partition all of the CO.sub.2 from the recovery stream into the one
or more fuel material gas fractions. For example, the fuel material
gas fractions comprising the CO.sub.2 may include at least about
95% by mass of the total CO.sub.2 present in the recovery
stream.
[0040] If desired, the method further may comprise separating the
recovered gas stream into a recovered hydrocarbon gas stream and a
recovered non-hydrocarbon gas stream (e.g., separating at least a
portion of the CO.sub.2 from the fuel gas fractions). Although this
is not necessary according to the invention, it may be desirable in
specific embodiments and thus is encompassed by the inventive
methods.
[0041] In further embodiments, the invention may be characterized
as providing a method of producing a CO.sub.2 containing stream
down-hole in a well. In particular, the method may comprise the
following steps: providing a combustion fuel and an oxidant into a
transpiration cooled combustor positioned down-hole in a well that
is in or around a formation including a fuel material deposit;
providing a transpiration cooling fluid into the combustor; and
combusting the fuel within the transpiration cooled combustor in
the presence of the transpiration cooling fluid so as to provide a
CO.sub.2 containing stream from an outlet of the combustor at a
pressure of at least about 7.5 MPa and a temperature of at least
about 400.degree. C. Preferably, at least a portion of the CO.sub.2
containing stream comprises supercritical CO.sub.2.
[0042] In particular embodiments, the invention can encompass
utilizing a formed CO.sub.2 containing stream as a means for
expanding a previously formed well and/or forming a separate
pathway through a formation. Specifically, the methods can comprise
directing the CO.sub.2 containing stream toward the formation such
that the CO.sub.2 containing stream provided from the outlet of the
combustor bores into the formation and creates a pathway therein.
The method also can comprise advancing the combustor through the
formed pathway.
[0043] Preferably, at least a portion of any formed CO.sub.2
containing stream can be injected into the formation including the
fuel material deposit such that at least a portion of the fuel
material in the formation and at least a portion of the CO.sub.2
stream flow from the formation and into a recovery well.
Thereafter, recovery steps can be carried out as already discussed
above.
[0044] The invention also provides a variety of systems and
apparatuses that can be useful for recovering deposits from
formations. For example, in certain embodiments, the invention can
be characterized as providing an apparatus for producing a CO.sub.2
containing stream down-hole in a well. In particular, the apparatus
can comprise a transpiration cooled combustor, a fuel supply in
fluid connection with the combustor, an oxidant supply in fluid
connection with the combustor, a transpiration coolant supply in
fluid connection with the combustor, a chamber within the
transpiration cooled combustor wherein combustion of the fuel
occurs at a temperature of at least about 600.degree. C. to produce
the CO.sub.2 containing stream; and an outlet on the combustor that
delivers the CO.sub.2 containing stream from the combustor and into
the well. In particular embodiments, the outlet can comprise a
conically shaped nozzle that concentrates the. CO.sub.2 containing
stream delivered therefrom. In other words, the nozzle focuses the
CO.sub.2 containing stream into a narrowed stream in comparison to
the combustor end of the outlet, the narrowed stream exhibiting
increased energy.
[0045] In further embodiments, the invention can be characterized
as providing a CO.sub.2 generating system. Such system can be used
for recovering a fuel material deposit from a formation. For
example, such system can comprise the following components: a
transpiration cooled combustor; a combustion fuel supply in fluid
connection with the combustor; an oxidant supply in fluid
connection with the combustor; a transpiration coolant supply in
fluid connection with the combustor; a chamber within the
transpiration cooled combustor configured for receiving and
combusting the combustion fuel to provide a CO.sub.2 containing
stream comprising supercritical CO.sub.2; an injection component
that delivers the CO.sub.2 containing stream into the formation
including the fuel material deposit such that at least a portion of
the fuel material in the formation and at least a portion of the
CO.sub.2 stream flow from the formation and into a recovery well as
a recovery stream; and one or more processing components for
processing the recovered fuel material and CO.sub.2 in the recovery
stream.
[0046] In particular embodiments, the one or more processing
components can comprise an expander that reduces the pressure of
the recovery stream. More specifically, the expander can comprise a
power generation turbine. Further, the one or more processing
components can comprise one or more separation unit. More
specifically, the separation unit may be a unit that separates a
gas stream from a liquid stream. The injection component can
comprise a pipeline extending into a well formed in the
formation.
[0047] In specific embodiments, one or more of the combustion fuel
supply, the oxidant supply, and the transpiration coolant supply
can comprise piping of sufficient dimensions to deliver the
respective material down hole into a well formed in the formation.
In other embodiments, the transpiration cooled combustor can be
configured for use down hole in a well formed in the formation.
Preferably, the system can be sufficiently modular in construction
such that the system can be reconfigured between a transportation
state and a CO.sub.2 generating state. Such reconfiguration
particularly can be carried out within a matter of hours, days, or
weeks.
BRIEF DESCRIPTION OF THE DRAWINGS
[0048] In order to assist the understanding of embodiments of the
invention, reference will now be made to the appended drawings, in
which like reference numerals refer to like elements and which are
not necessarily drawn to scale. The drawings are exemplary only,
and should not be construed as limiting the invention.
[0049] FIG. 1 provides a cross-section of a typical geological
formation bearing oil as a deposit and illustrates a system and
method of enhancing recovery of the oil in the formation through
combustion of a fuel in a down-hole combustor located in an
injection well according to an embodiment of the invention to
produce CO.sub.2 that is directed into the formation from the
injection well to enhance recovery of the oil via a producing well
with optional processing of the produced oil;
[0050] FIG. 2 provides a cross-section of a typical geological
formation bearing natural gas as a deposit and illustrates a system
and method of enhancing recovery of the natural gas in the deposit
through combustion of a fuel in a surface combustor according to an
embodiment of the invention to produce CO.sub.2 that is directed
into the formation from an injection well to enhance recovery of
the natural gas via a producing well with optional processing of
the produced natural gas;
[0051] FIG. 3 provides a cross-section of a portion of a typical
geological formation bearing a fossil fuel and illustrates a system
and method of enhancing recovery of the fossil fuel through
combustion of a fuel to produce CO.sub.2 that is directed into the
formation from an injection well, wherein a dual combustor system
and method is provided to facilitate the use of combustion fuels
that may form ash or other particulate materials as a combustion
product; and
[0052] FIG. 4 provides a graph illustrating efficiency of a power
production method according to one embodiment of the invention
wherein sour gas (i.e., natural gas with an H.sub.2S content) is
used as a combustion fuel, the efficiency being shown as a function
of the content of the H.sub.2S in the crude oil recovery stream
from which the sour gas was separated.
DETAILED DESCRIPTION OF THE INVENTION
[0053] The invention now will be described more fully hereinafter
through reference to various embodiments. These embodiments are
provided so that this disclosure will be thorough and complete, and
will fully convey the scope of the invention to those skilled in
the art. Indeed, the invention may be embodied in many different
forms and should not be construed as limited to the embodiments set
forth herein; rather, these embodiments are provided so that this
disclosure will satisfy applicable legal requirements. As used in
the specification, and in the appended claims, the singular forms
"a", "an", "the", include plural referents unless the context
clearly dictates otherwise.
[0054] The present invention relates to systems and methods for
providing a reliable, high purity source of CO.sub.2 that can be
safely and effectively provided for use in enhancing the recovery
of a variety of formation deposits, particularly fuel material
deposits. In specific embodiments, the terms "deposit" and
"formation deposit" specifically can refer to fuel material
deposits. As used herein, the term "fuel material" specifically can
encompass any material that is recognized as providing energy, such
as through combustion of the material, heat transfer, or other
means whereby stored energy potential of the material is realized.
A fuel material can encompass carbonaceous materials (including
biomass, waste materials, and the like), which further can
encompass solid, liquid, and gaseous hydrocarbons (including in a
form consisting wholly of hydrogen and carbon and in a form that
further includes additional elements or compounds--e.g., sulfur and
oxygen--as part of the chemical structure of the hydrocarbon or as
a physical mixture with the hydrocarbon). More specifically, a fuel
material can be characterized as a fossil fuel, petroleum, crude
oil, natural gas, coal, coke, bitumen, oil shale, tar sands, and/or
combinations thereof, and/or derivatives thereof. Other aspects of
geological formations that meet the criteria described above as may
be recognizable to one of skill in the art with knowledge of the
present invention may also be encompassed by the present
invention.
[0055] In various embodiments, the present invention may be
characterized as comprising injecting CO.sub.2 or a CO.sub.2
containing stream into a formation. In this sense, injecting or
injection can include a passive transmission of the material into a
formation. Since the very action of transporting a liquid or
gaseous material into the face of a rock or otherwise porous
formation typically requires applied pressure to significantly
permeate the formation, injecting can be characterized as including
application of a force, such as applied pressure. Since the
combustor of the present invention can provide a combustion product
stream at high pressure, the inherent pressure of the produced
combustion product may be sufficient to achieve injection of the
combustion product stream (or a portion thereof) into a formation.
In other embodiments, however, additional pressurization may be
used, particularly if the combustion product stream has been
expanded in a power production method. Of course, additional
expansion also may be used.
[0056] In certain embodiments, the CO.sub.2 used in enhanced
recovery of formation deposits can be yielded from a combustion
method or cycle wherein a fuel is combusted to provide a combustion
product stream comprising CO.sub.2. The CO.sub.2 can be withdrawn
from a combustion product stream and thus may be obtained in
various states of purity. Advantageously, through carrying out
specific processing steps, the isolated CO.sub.2 can be
substantially completely pure. In some embodiments, however, the
CO.sub.2 can be used according to the invention as an integrated
component of a combustion product stream. In other words, as more
fully discussed below, although CO.sub.2 arising from a combustion
product stream can be purified to a defined degree prior to use, a
CO.sub.2 containing combustion product stream may be used in the
invention without substantial purification or without any
purification (i.e., direct injection of the combustion product
stream, which may be characterized as the CO.sub.2 containing
stream). The combustion may or may not be a component of a larger
system or method, such as a power production system or method.
Thus, the CO.sub.2 used according to the invention may be yielded
from a power production system or method. The CO.sub.2 (either as a
purified stream or as a component of a combustion product stream)
can be directed for use in a recovery method as discussed
herein.
[0057] A system for providing CO.sub.2 for use in an enhanced
recovery method can comprise a combustor that is configured for
CO.sub.2 production through combustion of a fuel. An aspect of the
combustion may be power production, and the provision of the
CO.sub.2 for enhanced recovery of deposits can occur after power
production, before power product, or both after and before power
production. In some embodiments, however, combustion may be carried
out solely for CO.sub.2 production for enhanced recovery of
deposits. Accordingly, any system that combusts a carbonaceous fuel
and produces CO.sub.2 in quantities and forms described herein
could be configured for use according to the present invention in
light of the present disclosure.
[0058] Combustion as a means for yielding CO.sub.2 can comprise the
use of a high efficiency fuel combustor (such as a transpiration
cooled combustor) and optionally a quenching fluid, which may
function also as the transpiration fluid, a mixing fluid, and/or a
circulating fluid. Specifically, the circulating fluid can be
provided in the combustor along with an appropriate fuel, any
necessary oxidant, and any associated materials that may be useful
for efficient combustion and/or for further enhancing recovery of
the deposits. In certain embodiments, the invention can comprise
the use of a combustor that operates at very high temperatures
(e.g., in the range of about 1,600.degree. C. to about
3,300.degree. C., or other temperature ranges as disclosed herein),
and the circulating fluid can be useful to moderate the temperature
of a combustion product stream exiting the combustor, if desired.
Exemplary combustors useful according to the invention are
disclosed in U.S. Publication No. 2011/0083435 and U.S. Publication
No. 2010/0300063, the disclosures of which are incorporated herein
by reference in their entireties.
[0059] In some embodiment, combustion may be carried out under
conditions such that the CO.sub.2 in the resultant combustion
product stream is in a supercritical state. High temperature
combustion can be particularly useful for providing a CO.sub.2
stream for use in enhanced recovery methods in light of the ability
to achieve substantially complete combustion of the fuel, maximize
efficiency, and prevent production of a substantial content of
particulate matter or matter in other solid forms. In various
embodiments, high temperature combustion can mean combustion at a
temperature of at least about 400.degree. C., at least about
600.degree. C., at least about 800.degree. C., at least about
1,000.degree. C., at least about 1,200.degree. C., at least about
1,300.degree. C., at least about 1,400.degree. C., at least about
1,500.degree. C., at least about 1,600.degree. C., at least about
1,750.degree. C., at least about 2,000.degree. C., at least about
2,500.degree. C., or at least about 3,000.degree. C. In further
embodiments, high temperature combustion can mean combustion at a
temperature of about 1,200.degree. C. to about 5,000.degree. C.,
about 1,500.degree. C. to about 4,000.degree. C., about
1,600.degree. C. to about 3,500.degree. C., about 1,700.degree. C.
to about 3,200.degree. C., about 1,800.degree. C. to about
3,100.degree. C., about 1,900.degree. C. to about 3,000.degree. C.,
or about 2,000.degree. C. to about 3,000.degree. C.
[0060] The use of transpiration cooling according to the present
invention can be particularly useful to prevent corrosion, fouling,
and erosion in the combustor. This further allows the combustor to
work in a sufficiently high temperature range to afford complete or
at least substantially complete combustion of the fuel that is
used.
[0061] By way of example, a transpiration cooled combustor useful
according to the invention can include a combustion chamber at
least partially defined by a transpiration member, wherein the
transpiration member is at least partially surrounded by a pressure
containment member. The combustion chamber can have an inlet
portion and an opposing outlet portion. The inlet portion of the
combustion chamber can be configured to receive the fuel to be
combusted within the combustion chamber at a combustion temperature
to form a combustion product. The combustion chamber can be further
configured to direct the combustion product toward the outlet
portion. The transpiration member can be configured to direct a
transpiration substance therethrough toward the combustion chamber
for buffering interaction between the combustion product and the
transpiration member. In addition, the transpiration substance may
be introduced into the combustion chamber to achieve a desired
outlet temperature of the combustion product. In particular
embodiments, the transpiration substance can at least partially
comprise the circulating fluid. The walls of the combustion chamber
may be lined with a layer of porous material through which is
directed and flows the transpiration substance, such as CO.sub.2
and/or H.sub.2O. The perforated/porous nature of the transpiration
cooled combustor may extend substantially completely (axially) from
the inlet to the outlet such that the transpiration fluid is
directed into substantially the entire length of the combustion
chamber. In other words, substantially the entire length of the
combustion chamber may be transpiration-cooled. In other
combustors, the perforations/pores may be spaced apart at an
appropriate density such that substantially uniform distribution of
the transpiration substance is achieved (i.e., no "dead spots"
where the flow or presence of the transpiration substance is
lacking). The ratio of pore area to total wall area (% porosity)
may be, for example, at least about 5%, at least about 10%, at
least about 15%, at least about 20%, at least about 30%, at least
about 40%, or at least about 50%. Array sizes of about 10.times.10
to about 10,000.times.10,000 per inch with porosity percentages of
about 10% to about 80% can be utilized in some examples.
[0062] An exemplary combustor can comprise a combustion chamber
defined by a transpiration member, which may be at least partially
surrounded by a pressure containment member. In some instances, the
pressure containment member may further be at least partially
surrounded by a heat transfer jacket, wherein the heat transfer
jacket can cooperate with the pressure containment member to define
one or more channels therebetween, through which a low pressure
water stream may be circulated. Through an evaporation mechanism,
the circulated water may thus be used to control and/or maintain a
selected temperature of the pressure containment member, for
example, in a range of about 100.degree. C. to about 250.degree. C.
In some aspects, an insulation layer may be disposed between the
transpiration member and the pressure containment member.
[0063] In some instances, the transpiration member may comprise,
for example, an outer transpiration member and an inner
transpiration member, the inner transpiration member being disposed
opposite the outer transpiration member from the pressure
containment member, and defining the combustion chamber. The outer
transpiration member may be comprised of any suitable high
temperature-resistant material such as, for example, steel and
steel alloys, including stainless steel and nickel alloys. In some
instances, the outer transpiration member may be configured to
define first transpiration fluid supply passages extending
therethrough from the surface thereof adjacent to the insulation
layer to the surface thereof adjacent to the inner transpiration
member. The first transpiration fluid supply passages may, in some
instances, correspond to second transpiration fluid supply passages
defined by the pressure containment member, the heat transfer
jacket and/or the insulation layer. The first and second
transpiration fluid supply passages may thus be configured to
cooperate to direct a transpiration fluid therethrough to the inner
transpiration member.
[0064] The inner transpiration member may be comprised of, for
example, a porous ceramic material, a perforated material, a
laminate material, a porous mat comprised of fibers randomly
orientated in two dimensions and ordered in the third dimension, or
any other suitable material or combinations thereof exhibiting the
characteristics required thereof as disclosed herein, namely
multiple flow passages or pores or other suitable openings for
receiving and directing the transpiration fluid through the inner
transpiration member. Non-limiting examples of porous ceramic and
other materials suitable for such transpiration-cooling systems
include aluminum oxide, zirconium oxide, transformation-toughened
zirconium, copper, molybdenum, tungsten, copper-infiltrated
tungsten, tungsten-coated molybdenum, tungsten-coated copper,
various high temperature nickel alloys, and rhenium-sheathed or
coated materials. Sources of suitable materials include, for
example CoorsTek, Inc., (Golden, Colo.) (zirconium); UltraMet
Advanced Materials Solutions (Pacoima, Calif.) (refractory metal
coatings); Orsam Sylvania (Danvers, Mass.) (tungsten/copper); and
MarkeTech International, Inc. (Port Townsend, Wash.) (tungsten).
Examples of perforated materials suitable for such
transpiration-cooling systems include all of the above materials
and suppliers (where the perforated end structures may be obtained,
for example, by perforating an initially nonporous structure using
methods known in the manufacturing art). Examples of suitable
laminate materials include all of the above materials and suppliers
(where the laminate end structures may be obtained, for example, by
laminating nonporous or partially porous structures in such a
manner as to achieve the desired end porosity using methods known
in the manufacturing art).
[0065] The transpiration substance may be directed through the
inner transpiration member such that the transpiration substance
forms a buffer layer (i.e., a "vapor wall") immediately adjacent to
the inner transpiration member within the combustion chamber. In
some instances, the transpiration fluid can be delivered at least
at the pressure within the combustion chamber such that the flow
rate of the transpiration fluid into the combustion chamber is
sufficient for the transpiration fluid to mix with and cool the
combustion products to form an exit fluid mixture at a desired
temperature (e.g., as low as about 100.degree. C. in some
embodiments to as great as about 2,000.degree. C. in other
embodiments).
[0066] A combustor apparatus useful according to the invention may
comprise various ancillary components, such as components useful
for providing various materials used in the combustion process. For
example, the combustor may include an integrated mixing chamber
wherein fuel, circulating fluid (e.g., CO.sub.2 and/or water),
oxidant, and any further materials necessary to carry out
combustion may be combined in any combination. Alternately, such
materials may be mixed external to the combustor and input to the
combustor in a substantially mixed state. In various embodiments,
the combustor may include inputs for fuel, oxidant (e.g., O.sub.2
or air), circulating fluid, and transpiration fluid. In specific
embodiments, the circulating fluid and the transpiration fluid may
be the same material or mixtures of materials. An air separation or
compression unit may be used to provide the oxidant (e.g., in a
substantially purified state), and a fuel injector device may be
provided for receiving the oxidant and combining it with a CO.sub.2
circulating fluid and a fuel stream, which can comprise a gas, a
liquid, a supercritical fluid, or a solid particulate fuel slurried
in a high density CO.sub.2 fluid.
[0067] In another aspect, a transpiration-cooled combustor
apparatus may include a fuel injector for injecting a pressurized
fuel stream into the combustion chamber of the combustor apparatus,
optionally in combination with the circulating fluid and/or the
oxidant. The oxidant (optionally enriched oxygen) and the CO.sub.2
circulating fluid can be combined as a homogeneous supercritical
mixture.
[0068] In particular embodiments, a combustor according to the
invention can take on a particular configuration that can
facilitate specific uses, such as down-hole combustion. For
example, in some embodiments, it may be useful for the combustor to
provide a focused product stream that is effective for partially or
completely dissolving at least the portion of the formation that is
incident to the portion of the combustor from which the combustion
product stream flows. Specifically, the combustor may include a
nozzle or similarly conically shaped segment that concentrates the
combustion products into a high pressure, high temperature stream
upon exiting the combustor. In such configurations, a down-hole
combustor according to the present invention may at least partially
create a bore hole in the formation through which the combustor may
proceed to inject supercritical CO.sub.2 into the surrounding
formation.
[0069] Additionally, the combustor may include an outer shell
(e.g., a metal or ceramic material) in addition to the
transpiration cooled configurations already described above. Such
external shell may provide structural protection against physical
damage to the combustor (e.g., from unintentional contact with rock
formations) and can further protect against growth of organic
materials or deposition of other contaminants from rock, soot, and
other materials that may be dislodged by the down-hole combustion
stream. In particular embodiments, the outer shell may also be
transpiration protected (which may be at a lower temperature than
transpiration of the main combustor wall). Such additional
transpiration protection may be useful to protect and/or lubricate
the down-bore device to facilitate passage through the
formations.
[0070] A wide variety of materials may be used as a fuel in the
combustor. For example, combustion to produce CO.sub.2 for enhanced
recovery of formation deposits may be carried out using any of the
following: various grades, types, and derivatives of coal, wood,
oil, fuel oil, natural gas, coal-based fuel gas, tar from tar
sands, bitumen, and the like. Even further materials that may used
as the fuel can include biomass, algae, graded combustible solid
waste refuse, asphalt, used tires, diesel, gasoline, jet fuel
(JP-5, JP-4), gases derived from the gasification or pyrolysis of
hydro-carbonaceous material, ethanol, solid and liquid biofuels,
and the like. In embodiments wherein the formation deposits for
recovery include a fossil fuel, it can be particularly beneficial
for the fuel used in the combustor to be a component of the
recovery stream returned from the formation deposit (e.g., natural
gas, oil, or an oil fraction recovered from a formation). Any of
the above combustion fuels may be characterized as a carbonaceous
fuel to the extent that the material includes a carbon
component.
[0071] The fuels can be processed in various manners prior to
injection into the combustion apparatus and can be injected at
desired rates and pressures useful to achieve a desired combustion
product stream. Such fuels may be in liquid, slurry, gel, or paste
form with appropriate fluidity and viscosity at ambient
temperatures or at elevated temperatures. For example, the fuel may
be provided at a temperature of about 30.degree. C. to about
500.degree. C., about 40.degree. C. to about 450.degree. C., about
50.degree. C. to about 425.degree. C., or about 75.degree. C. to
about 400.degree. C. Any solid fuel materials may be ground or
shredded or otherwise processed to reduce particles sizes, as
appropriate. A fluidization or slurrying medium can be added, as
necessary, to achieve a suitable form (e.g., a coal slurry) and to
meet flow requirements for high pressure pumping. Of course, a
fluidization medium may not be needed depending upon the form of
the fuel (i.e., liquid or gas). Likewise, the circulated
circulating fluid may be used as the fluidization medium, in some
embodiments.
[0072] Combustion as a means for production of CO.sub.2 for
enhanced recovery of formation deposits can be carried out making
use of specific process parameters and components. Examples of high
efficiency combustion systems and methods that may be used
according to the present invention to yield CO.sub.2 are described
in U.S. Patent Publication No. 2011/0179799, the disclosure of
which is incorporated herein by reference in its entirety.
Preferably, the combustion system requires no additional
compression or removal of impurities before injection into
pipelines or formations for enhancing recovery of deposits, such as
fossil fuels. The present invention can also be applied to other
combustion processes that can accept a feed fuel stream containing
a substantial quantity of CO.sub.2.
[0073] In various embodiments of the invention, the combustor
apparatus used in the enhanced recovery methods can be at a surface
location that is in proximity to the site for injection of the
produced CO.sub.2. A surface-located combustor can be in a
permanent, semi-permanent, or transportable state. For example, the
combustor can be a component of a power production system wherein a
fuel is combusted (preferably at high temperature) in the presence
of a circulating fluid (particularly CO.sub.2) or other quenching
fluid that can moderate the temperature of the combustion product
stream exiting the combustor so that the combustion product stream
can be utilized in energy transfer for power production.
Specifically, the combustion product stream can be expanded across
at least one turbine to generate power. The expanded gas stream can
be subjected to processing, as further described below, or can be
injected directly into the formation.
[0074] In various embodiments, it can be desirable for the CO.sub.2
to be introduced into the combustor at a defined pressure and/or
temperature. Specifically, it can be beneficial for the CO.sub.2
introduced into the combustor to have a pressure of at least about
2 MPa, at least about 5 MPa, at least about 8 MPa, at least about
10 MPa, at least about 12 MPa, at least about 15 MPa, at least
about 18 MPa, or at least about 20 MPa. In other embodiments, the
pressure can be about 2 MPa to about 50 MPa, about 5 MPa to about
40 MPa, or about 10 MPa to about 30 MPa. Further, it can be
beneficial for the CO.sub.2 introduced into the combustor to have a
temperature of at least about 200.degree. C., at least about
250.degree. C., at least about 300.degree. C., at least about
400.degree. C., at least about 500.degree. C., at least about
600.degree. C., at least about 700.degree. C., at least about
800.degree. C., or at least about 900.degree. C.
[0075] In some embodiments, it can be useful for the O.sub.2
supplied to the combustor to be substantially purified (i.e.,
upgraded in terms of the molar content of O.sub.2 in relation to
other components naturally present in air). In certain embodiments,
the O.sub.2 can have a purity of greater than about 50% molar,
greater than about 75% molar, greater than about 85% molar, greater
than about 90% molar, greater than about 95% molar, greater than
about 98% molar, or greater than about 99% molar. In other
embodiments, the O.sub.2 can have a molar purity of about 85% to
about 99.6% molar, about 85% to about 99% molar, or about 90% to
about 98% molar. Overall CO.sub.2 recovery from the carbon in the
fuel favors the use of higher purities in the range of at least
about 99.5% molar.
[0076] In certain embodiments, the amount of O.sub.2 provided can
be in excess of the noted stoichiometric amount by at least about
0.1% molar, at least about 0.25% molar, at least about 0.5% molar,
at least about 1% molar, at least about 2% molar, at least about 3%
molar, at least about 4% molar, or at least about 5% molar. In
other embodiments, the amount of O.sub.2 provided can be in excess
of the noted stoichiometric amount by about 0.1% to about 5% molar,
about 0.25% to about 4% molar, or about 0.5% to about 3% molar.
[0077] The introduction of the circulating fluid and/or the
transpiration fluid into the combustor can be useful to control
combustion temperature such that the combustion product stream
leaving the combustor has a desired temperature. For example, it
can be useful for the combustion product stream exiting the
combustor to have a temperature of at least about 500.degree. C.,
at least about 750.degree. C., at least about 900.degree. C., at
least about 1,000.degree. C., at least about 1,200.degree. C., or
at least about 1,500.degree. C. In some embodiments, the combustion
product stream may have a temperature of about 100.degree. C. to
about 2,000.degree. C., about 150.degree. C. to about 1,800.degree.
C., about 200.degree. C. to about 1,600.degree. C., about
200.degree. C. to about 1,400.degree. C., about 200.degree. C. to
about 1,200.degree. C., or about 200.degree. C. to about
1,000.degree. C.
[0078] The combustion product stream can be directed to a turbine
wherein the combustion product stream is expanded to generate power
(e.g., via a generator to produce electricity). The turbine can
have an inlet for receiving the combustion product stream and an
outlet for release of a turbine discharge stream comprising
CO.sub.2. A single turbine may be used in some embodiments, or more
than one turbine may be used, the multiple turbines being connected
in series or optionally separated by one or more further
components, such as a further combustion component, a compressing
component, a separator component, or the like. A stream originating
from a combustion process as discussed herein and entering and/or
exiting any of these components may be described as being a
CO.sub.2 containing stream and may arise from one or more
combustors.
[0079] The temperature of the stream at the turbine inlet can vary,
such as to as high as about 1,350.degree. C. In other embodiments,
the present systems and methods can use a turbine inlet temperature
in a much lower range, as described above. Moreover, the combustion
product stream leaving the combustor can have a pressure that is
closely aligned to the pressure of the CO.sub.2 circulating fluid
entering the combustor. In specific embodiments, the combustion
product stream can be at a temperature and pressure such that the
CO.sub.2 present in the stream is in a supercritical fluid state.
When the combustion product stream is expanded across the turbine,
the pressure of the stream can be reduced. Such pressure drop can
be controlled such that the pressure of the combustion product
stream is in a defined ratio with the pressure of the turbine
discharge stream e.g., a ratio of less than about 12, less than
about 10, less than about 8, or less than about 7. In other
embodiments, the inlet pressure to outlet pressure ratio a the
turbine can be about 1.5 to about 12, about 2 to about 10, about 3
to about 9, or about 4 to about 8.
[0080] In specific embodiments, it can be desirable for the turbine
discharge stream to be under conditions such that the CO.sub.2 in
the stream is no longer in a supercritical fluid state but is
rather in a gaseous state. For example, providing the CO.sub.2 in a
gaseous state can facilitate further processing of the stream prior
to injection in to the formation. Thus, the turbine discharge
stream may have a pressure that is below the pressure where the
CO.sub.2 would be in a supercritical state--i.e., less than about
7.3 MPa, is less than about 7 MPa, less than about 6 MPa, less than
about 5 MPa, less than about 4 MPa, less than about 3 MPa, less
than about 2 MPa, or less than about 1.5 MPa. In other embodiments,
the pressure of the turbine discharge stream can be about 1.5 MPa
to about 7 MPa, about 3 MPa to about 7 MPa, or about 4 MPa to about
7 MPa. In specific embodiments, the pressure of the turbine
discharge stream can be less than the CO.sub.2 condensing pressure
at the cooling temperatures to be encountered by the stream (e.g.,
ambient cooling). In other embodiments, however, where cooling
and/or separation may not be required or desired, it can be useful
for the pressure of the turbine discharge stream to be greater. For
example, the pressure may be at least about 7.5 MPa, at least about
8 MPa, at least about 8.5 MPa, at least about 9 MPa, or at least
about 10 MPa. In still other embodiments, the pressure of the
turbine discharge stream can be at least about 1.5 MPa, at least
about 2 MPa, at least about 3 MPa, at least about 4 MPa, or at
least about 5 MPa.
[0081] Although passage of the combustion product stream through
the turbine may lead to some amount of temperature decrease, the
turbine discharge stream may be significantly similar to the
temperature of the combustion product stream. For example, the
turbine discharge stream may have a temperature of about
500.degree. C. to about 1,000.degree. C., about 600.degree. C. to
about 1,000.degree. C., about 700.degree. C. to about 1,000.degree.
C., or about 800.degree. C. to about 1,000.degree. C. Because of
the relatively high temperature of the combustion product stream,
it can be beneficial for the turbine to be formed of materials
capable of withstanding such temperatures. It also may be useful
for the turbine to comprise a material that provides good chemical
resistance to the type of secondary materials that may be present
in the combustion product stream.
[0082] The combustion product stream (or the turbine discharge
stream in energy production embodiments) may be in a condition for
direct injection into the formation where enhanced recovery of a
deposit is desired (meaning without the necessity for further
processing of the stream, such as to remove impurities, etc.). In
some embodiments, it may be desirable, however, to further process
the stream prior to injection. For example, where the CO.sub.2
stream is being injected into a well, a pipeline, or a formation
generally that may be damaged by sufficiently high pressure
injection, the CO.sub.2 from the combustion process may be pressure
modified. As noted above, expansion in power production may reduce
the CO.sub.2 stream pressure; however, even further pressure
reduction may be desired, and such pressure reduction can be
provided by passage through one or more further power production
turbines. Other means for pressure reduction also may be used as
would be recognized by one of skill in the art with the advantage
of the present disclosure. Preferably, compression of the CO.sub.2
stream will not be required in light of the possible energy input
required. Nevertheless, if useful, such as because of the specific
geology of the formation structure or pipeline specifications,
compression of the CO.sub.2 may be carried out.
[0083] In some embodiments, it may be useful to adjust the
temperature of the CO.sub.2 stream prior to injection into the
formation. As further discussed below, use of a stream of
relatively high temperature may be useful, such as in enhanced
recovery of heavy oil. Since the present invention encompasses high
temperature combustion systems and methods, however, it may be
useful in some embodiments to cool the CO.sub.2 stream prior to
injection.
[0084] In particular, it can be useful to pass the CO.sub.2 stream
through at least one heat exchanger that cools the stream and
provides a CO.sub.2 stream having a temperature in a defined range.
In specific embodiments, the cooled CO.sub.2 can have a temperature
of less than about 1,000.degree. C., less than about 750.degree.
C., less than about 500.degree. C., less than about 250.degree. C.,
less than about 100.degree. C., less than about 80.degree. C., less
than about 60.degree. C., or less than about 40.degree. C. In
certain embodiments, it can be particularly useful for the heat
exchanger to comprise at least two heat exchangers in series for
receiving the CO.sub.2 stream and cool it to a desired temperature.
The type of heat exchanger used can vary depending upon the
conditions of the stream entering the heat exchanger. For example,
since the CO.sub.2 stream may be at a relatively high temperature,
it may thus be useful for the heat exchanger directly receiving the
CO.sub.2 stream to be formed from high performance materials
designed to withstand extreme conditions (e.g., an INCONEL.RTM.
alloy or similar material). The first heat exchanger in a series
can comprise a material capable of withstanding a consistent
working temperature of at least about 400.degree. C., at least
about 600.degree. C., at least about 800.degree. C., or at least
about 1,000.degree. C. It also may be useful for one or more of the
heat exchangers to comprise a material that provides good chemical
resistance to the type of secondary materials that may be present
in the combustion product stream. Suitable heat exchangers can
include those available under the tradename HEATRIC.RTM. (available
from Meggitt USA, Houston, Tex.). In embodiments where the first
heat exchanger in a series can transfer a sufficient content of
heat from the CO.sub.2 stream, one or more further heat exchangers
present in the series can be formed of more conventional
materials--e.g., stainless steel. In specific embodiments, at least
two heat exchangers or at least three heat exchangers are used in a
series to cool the turbine discharge stream to the desired
temperature.
[0085] In some embodiments, it may be desirable for the CO.sub.2
stream from the combustion method to undergo further processing to
separate out any secondary components remaining in the CO.sub.2
stream. Such secondary components may or may not be present,
particularly depending upon the nature of the fuel used in the
combustion method. Likewise, it may or may not be desirable to
separate any secondary components present in the CO.sub.2 stream
depending upon the formation into which it is being injected.
Accordingly, the present methods and system may comprise the use of
one or more separation units.
[0086] In particular embodiments, it may be useful to remove some
or all of any water present in the CO.sub.2 stream. Although it may
be useful for a "wet" CO.sub.2 stream to be input directly into a
formation for enhanced recovery of certain deposits, including in
relation to certain fossil fuels, if otherwise necessary, water
present in the CO.sub.2 stream (e.g., water formed during
combustion of a carbonaceous fuel and persisting through any
further processing prior to injection) can be removed mostly as a
liquid phase from a cooled CO.sub.2 stream. Such separation may be
achieved by providing the CO.sub.2 stream (e.g., in a gaseous
state) at a pressure that is less than the point at which CO.sub.2
present in the gas mixture is liquefied when the gas mixture is
cooled to the lowest temperature achieved with ambient temperature
cooling means. For example, the CO.sub.2 stream can be provided at
a pressure of less than 7.38 MPa during separation of secondary
components therefrom. An even lower pressure may be required if
cooling means at a temperature in the low ambient range or
substantially less than ambient are used. This allows for
separation of water as a liquid. In some embodiments, the pressure
may be substantially the same as the pressure at the turbine
outlet. A "dry" CO.sub.2 stream after water separation may comprise
water vapor in an amount of less than 1.5% on a molar basis, less
than 1% on a molar basis, or less than 0.5% on a molar basis. If
desired, further drying may be applied such that the CO.sub.2
stream is completely or substantially free of water. For example,
low concentrations of water may be removed by desiccant dryers or
other means that would suitable in light of the present
disclosure.
[0087] Further secondary components that may be removed from the
CO.sub.2 stream include, for example, SO.sub.2, SO.sub.3, HCl, NO,
NO.sub.2, Hg, O.sub.2, N.sub.2, and Ar. These secondary components
of the CO.sub.2 stream can all be removed from a cooled CO.sub.2
stream using appropriate methods, such as methods defined in U.S.
Patent Application Publication No. 2008/0226515 and European Patent
Application Nos. EP1952874 and EP1953486, all of which are
incorporated herein by reference in their entirety. In specific
embodiments, various secondary components may be removed via the
following methods: SO.sub.2 and SO.sub.3 can be converted 100% to
sulfuric acid; >95% of NO and NO.sub.2 can be converted to
nitric acid; excess O.sub.2 can be separated as an enriched stream
for optional recycle to the combustor; and inert gases (e.g.,
N.sub.2 and Ar) can be vented at low pressure to the
atmosphere.
[0088] In embodiments wherein the combustion product stream is
cooled to facilitate removal of one or more components thereof, it
may be useful to re-heat the stream prior to injection into the
formation. As described above, one or more heat exchangers may be
used to cool the combustion product stream. If desired, the
CO.sub.2 containing stream may be passed back through the same heat
exchanger(s) to capture the heat previously withdrawn from the
combustion product stream.
[0089] If desired, the CO.sub.2 stream may be provided for
injection or recycle back into the combustor as a circulating fluid
in a substantially purified form. Specifically, a purified CO.sub.2
stream for can have a CO.sub.2 concentration of at least about 95%
molar, at least about 97% molar, at least about 98.5% molar, at
least about 99% molar, at least about 99.5% molar, or at least
about 99.8% molar. Moreover, the CO.sub.2 containing stream can be
provided at a desired pressure for injection into a formation,
input into a pipeline, and/or input into the combustor. It can be
particularly useful for the CO.sub.2 containing stream to have an
injection pressure (i.e., the pressure of the CO.sub.2 containing
stream at the point of injection into the formation--such as
leaving the well bore and entering the formation) that is at a
minimum level. For example, the CO.sub.2 containing stream can have
an injection pressure of at least about 1.5 MPa, at least about 2
MPa, at least about 3 MPa, at least about 4 MPa, at least about 5
MPa, at least about 6 MPa, at least about 7 MPa, at least about 7.5
MPa, at least about 8 MPa, at least about 9 MPa, at least about 10
MPa, at least about 11 MPa, or at least about 12 MPa. In other
embodiments, the CO.sub.2 containing stream can have pressure from
ambient to about 30 MPa. Such pressures likewise can apply to any
portion of the CO.sub.2 stream that is recycled back into the
combustor and/or is input into a pipeline.
[0090] In certain embodiments, the CO.sub.2 containing stream may
be characterized in relation to its viscosity and/or density.
Preferably, the CO.sub.2 containing stream will have an injection
pressure that is near or above the minimum miscibility pressure
(MMP) of the formation (and its fuel material deposit).
Accordingly, the density and viscosity of a CO.sub.2 containing
stream according to the invention can be a function of the MMP of
the specific well, which can be a known value. For example, it has
been shown in North Sea reservoirs that CO.sub.2 used in EOR must
have a density of 570 kg/m.sup.3 to 800 kg/m.sup.3 and a viscosity
of 0.04 mPa s to 0.07 mPa s. If desired, the invention can
encompass the use of additives to alter the density and/or
viscosity of the CO.sub.2 containing stream.
[0091] In preferred embodiments, a CO.sub.2 stream yielded from a
combustion system or method can be injected into a deposit
formation without the necessity of separation of any non-CO.sub.2
components and/or compression of the CO.sub.2 stream. Accordingly,
in embodiments related to surface combustion, the CO.sub.2 stream
may be injected in a formation after combustion only, after
combustion and expansion for power generation, after combustion and
cooling, or after combustion, expansion, and cooling. Preferably,
in embodiments related to surface combustion, at least one
expansion step is included to as to provide for power production,
particularly in embodiments where some level of pressure reduction
is useful prior to injection into the formation.
[0092] In some embodiments, direct injection of the CO.sub.2 stream
into a formation may be particularly desirable. Direct injection
may be characterized as injection of the CO.sub.2 containing
combustion product stream into the formation without any further
intermediate steps as otherwise described herein (e.g., without
expansion, cooling, or separating components from the stream).
Direct injection can include transporting the CO.sub.2 stream from
the combustor to a separate pipeline that delivers the CO.sub.2
stream to an injection site or from the combustor through a
pipeline that is a dedicated component of the system and method.
Delivery to a wellhead component for injection through existing oil
well components, natural gas well components, or the like also can
be considered direct injection of the CO.sub.2 stream according to
the invention.
[0093] It can be particularly beneficial for a power production
facility as described above that produces CO.sub.2 for enhanced
formation deposit recovery to be located substantially near the
formation where the CO.sub.2 will be injected. Such proximity can
reduce or eliminate the need for excess transfer of the CO.sub.2.
For example, in embodiments wherein the formation deposit for
recovery is a fossil fuel, it can be beneficial for the power
production facility to be located in or near the field including
the well or wells from which the fossil fuel is being recovered.
Preferably, the power production facility can be located very near
the site where the CO.sub.2 will be injected to enhance recovery of
the fossil fuel. In this manner, use of pipelines, tanker trucks,
and the like may be reduced or completely eliminated. In
particular, the present CO.sub.2 production system may include
sections of pipeline that are in fluid connection with the
remaining components of the combustion system such that CO.sub.2
produced by combustion is directed specifically to the injection
well through the pipeline without connects that allow input of
CO.sub.2 from a source that is external to the inventive
system.
[0094] In some embodiments, the power production can be
sufficiently near the site where the produced CO.sub.2 is injected
such that any pipeline that was used to direct the produced
CO.sub.2 to the injection site has a total length of less than
about 50 km, less than about 40 km, less than about 30 km, less
than about 20 km, less than about 10 km, less than about 5 km, less
than about 2 km, less than about 1 km, less than about 0.5 km, less
than about 0.25 km, or less than about 0.1 km. In some embodiments,
any transmission pipeline associated with transmission of the
CO.sub.2 from the power production facility to the injection site
can be described as having a near zero length. This particularly
can mean pipelines having a total length of less than about 0.5 km,
less than about 0.25 km, or less than about 0.1 km. Such distances
can be considered a "near zero" distance according to the present
invention since CO.sub.2 transmission pipelines typically have a
length measured in the hundreds of kilometers. Thus, by comparison,
the values noted above can be considered to be relatively near
zero. Moreover, the ability to provide the CO.sub.2 production
facility in such proximity to the injection site is not a matter of
mere optimization that could be achieved without real effort.
Rather, known CO.sub.2 sources typically are not amenable to
construction at specific sites at specific distances from where an
injection site may be located. This limitation is why the art
typically has required great lengths of pipelines and/or other
means for transporting CO.sub.2 the great distances necessary to
reach a fossil fuel deposit where enhanced recovery methods are
needed.
[0095] This advantage of the present invention is particularly
realized by the ability to provide a CO.sub.2 production system
that is fully transportable due to, but not limited to, its small
size and modular design. A fully transportable system according to
the present invention can be a surface production facility or
down-hole combustion system that is formed of components that can
be assembled to form an operable facility in a relatively short
time and, whenever desired, can be disassembled in a relatively
short time such that the full complement of components can be
transported to a different location (e.g., by truck, rail, or other
suitable vehicle) and again assembled in a relatively short time.
Thus, the system or apparatus may be described as being modular in
nature so as to allow the system to be reconfigured from a
transportation mode to a operation mode. As used in relation to
these embodiments, a relatively short time can be defined to mean a
total assembly time from separate components to operable facility
(i.e., producing CO.sub.2) or a total time of reconfiguration of
less than 56 days, less than 49 days, less than 42 days, less than
35 days, less than 28 days, less than 21 days, less than 14 days,
less than 10 days, less than 7 days, less than 5 days, or less than
2 days. Like time periods can apply to the disassembly from an
operable facility to the separate components. Such transportable
system may include power production components as described herein
or may be limited substantially to the combustor and associated
components necessary for CO.sub.2 production. Moreover, such
transportable system may be sufficiently compact such as to be
skid-mounted. In this manner, the CO.sub.2 production system may be
transported to a specific injection well and attached substantially
directly to the well-head for direct injection of produced CO.sub.2
into the well. The CO.sub.2 producing process thus is compact and
can be constructed in a form for disassembly, transportation to a
new recovery site, and reassembly at the lowest possible cost. This
likewise can function to eliminate the cost of a CO.sub.2
pipeline.
[0096] In addition to surface combustion, such as described above,
the present invention also encompasses embodiments wherein
combustion is carried out at a sub-surface location. By the term
"sub-surface" is meant that the actual combustion of the fuel to
produce CO.sub.2 is carried out at a physical location that is
below ground level. In some embodiments, the combustor may be
located only a few meters below ground level. In other embodiments,
the combustor may be located up to about 10 m, up to about 100 m,
up to about 500 m, up to about 1,000 m, up to about 1,500 m, up to
about 2,000 m, up to about 5,000 m, or up to about 10,000 m below
ground level. In further embodiments, the combustor may be located
at least about 1 m, at least about 10 m, at least about 25 m, at
least about 50 m, at least about 100 m, at least about 250 m, at
least about 500 m, or at least about 1,000 m below ground level. In
even other embodiments, the combustor can be located about 1 m to
about 5,000 m, about 5 m to about 4,000 m, about 10 m to about
3,000 m, or about 25 m to about 2,000 m below ground level.
According to this aspect of the invention, the combustor may be
characterized as being located down-hole (particularly in relation
to fossil fuel formations or other formations where a well may be
bored to recover the deposit), as being located within the
formation from which enhanced recovery is desired, as being located
above the deposit for which enhanced recovery is desired, as being
located below the deposit for which enhanced recovery is desired,
or as being located aside the deposit for which enhanced recovery
is desired (i.e., in a common horizontal plane with the
deposit).
[0097] When down-hole combustion is used, it can be particularly
beneficial to completely eliminate the pre-injection power
production system wherein a working fluid is used, such as to
generate electricity. In this manner, the methods and systems of
the invention can be effectively condensed into as little as a
combustor and any piping necessary to deliver combustion materials
(and any additionally desired enhanced recovery component--e.g.,
water for steam generation) down-hole to the input end of the
combustor. Thus, combustion can be carried out to produce CO.sub.2
(and optionally steam or other products useful for enhancing
recovery of certain deposits), which directly passes from the
output end of the combustor into the formation to enhance recovery
of the particular deposits, such as further described herein. As
discussed in greater detail below, the produced CO.sub.2 may be
combined with the deposit that is recovered from the formation in
the recovery stream. If desired, the produced CO.sub.2
specifically, or part or all of the recovery stream, may be used to
generate power in much the same manner described above. In these
embodiments, the power production components of the systems and
methods may be physically separated from the combustor (i.e., the
combustor being located down-hole and the power production
turbine(s) and similar or additional components being located
above-ground). Even in such embodiments, however, the combustor and
the power production components can be described as being in fluid
communication. Specifically, the combustion product stream exiting
the output end of the combustor passes into the formation, mixes
with or otherwise facilitates recovery of the deposit, and is
included in the recovery stream from the formation that may be
passed directly through the power production components or
separated into one or more portions prior to being passed through
the power productions components.
[0098] Whether surface combustion or down-hole combustion is
employed, the present invention can relate to enhanced recovery of
a variety of materials. In specific embodiments, the inventive
methods and systems can be used to enhance recovery of fossil
fuels. In particularly preferred embodiments, the invention can
particularly relate to enhanced recovery of fossil fuels in a fluid
form. In specific embodiments, a fluid form may mean a form that is
flowable at standard temperature and pressure. The fossil fuel may
be substantially in a fluid form while maintained within its
formation (or reservoir), such as in the case of a crude oil of
sufficiently low viscosity or natural gas. The fossil fuel also may
be characterized as being in a fluid form after contact with the
CO.sub.2 and/or any steam or other heating and/or diluting material
that may be used, such as in the case of bitumen, tar sands, oil
shale, or the like.
[0099] The enhanced recovery methods of the invention can include
delivering a CO.sub.2 containing stream to a formation including a
deposit for recovery. Although the CO.sub.2 containing stream may
include one or more further components, it is desirable for the
CO.sub.2 containing stream to comprise at least about 10%, at least
about 20%, at least about 30%, at least about 40%, at least about
50%, at least about 60%, at least about 70%, at least about 80%, at
least about 90%, at least about 95%, at least about 98%, or at
least about 99% by weight CO.sub.2 based on the overall weight of
the stream. In further embodiments, the CO.sub.2 containing stream
may comprise about 50% to about 100%, about 60% to about 98%, about
70% to about 97%, or about 75% to about 95% by weight CO.sub.2. As
noted above, the CO.sub.2 in the CO.sub.2 containing stream may be
in the form of a supercritical fluid or a gas. In some embodiments,
the CO.sub.2 containing stream can be characterized as consisting
of CO.sub.2. In other embodiments, the CO.sub.2 containing stream
can be characterized as consisting essentially of CO.sub.2. In such
embodiments, "consisting essentially of" specifically can mean any
of the following: the CO.sub.2 containing stream comprises less
than 2% by weight of any non-CO.sub.2 components; the CO.sub.2
containing stream is expressly free of any further material that is
typically recognized as being a fracture fluid; the CO.sub.2
containing stream is expressly free of any proppants; or the
CO.sub.2 containing stream is expressly free of any
surfactants.
[0100] As can be seen from the foregoing, the present invention
specifically can provide methods for enhancing recovery of fossil
fuel reserves. In various embodiments, the methods can be applied
to any formation that may contain one or more of methane, other
light hydrocarbon gases (e.g., C.sub.2 to C.sub.4 gases), oil of
varying viscosities, bitumen, tar sands, and shale oil. For
example, a method according to the invention can comprise:
combusting a carbonaceous fuel to provide a combustion product
stream comprising CO.sub.2; and directing at least a portion of the
CO.sub.2 into a formation containing the fossil fuel for recovery.
Further, the method can comprise receiving a fluid stream from the
formation comprising a fraction of the fossil fuel from the
formation and a fraction of the CO.sub.2 injected into the
formation. In further embodiments, at least a portion of the fossil
fuel fraction recovered from the formation can be separated from
the fluid stream. The separated fossil fuel fraction may comprise
light oils, heavy oils, light gases, or high viscosity fuel
materials (e.g., bitumen, tar sands, and shale oil). A plurality of
separations may be applied to obtain from the fluid stream all of
the marketable products, and such separations may result in
isolation of non-hydrocarbon materials, including CO.sub.2. In
other embodiments, at least a portion of the recovered fluid stream
can be recycled back into the combustion method. Specifically, the
recycled stream may comprise CO.sub.2 and/or a content of a
recovered fossil fuel (e.g., a light gas fraction). Moreover, in
embodiments for recovering mixed hydrocarbon products (e.g.,
including a gas fraction and a liquid oil fraction), it may be
beneficial to separate the liquid fraction for market. The
remaining gas fraction (including any impurities and CO.sub.2) can
be input directly to the combustor as all or part of the combustion
fuel. Preferably, the content of the recovered fossil fuel can be
sufficient to completely fuel the combustion process without
requiring input of external fuel sources. In other embodiments, the
portion of the recovered fossil fuel recycled into the system can
be used to supplement an external fuel source. Such methods
similarly can be applied to recovery of other types of formation
deposits.
[0101] In further embodiments, the present invention can provide
systems for providing CO.sub.2 for recovery of a fossil fuel from a
formation. For example, a system according to the invention can
comprise the following: a combustor configured for receiving a
carbonaceous fuel and having at least one combustion stage that
combusts the fuel to provide a combustion product stream comprising
CO.sub.2; and one or more components for directing at least a
portion of the CO.sub.2 into the formation. The system also can
comprise one or more components for power production, such as
electricity generating turbine components, that may be in fluid
connection with the combustor and/or may be positioned for power
generation using a component of the recovered fuel material stream.
The system further can comprise one or more components for
receiving a fluid stream from the formation comprising a fraction
of the fossil fuel from the formation and a fraction of the
CO.sub.2 directed into the formation. The system further can
comprise one or more components for separating at least a portion
of the recovered fossil fuel fraction from the fluid stream and/or
one or more components for recycling at least a portion of the
fluid stream back into the combustor. Such systems similarly can be
adapted for recovery of other types of formation deposits.
[0102] In some embodiments, the invention can relate to the use of
CO.sub.2 in enhancing recovery of a fossil fuel via a fracturing
process. Fracturing can be particularly useful in enhancing
recovery of hydrocarbon gases, such as in coal beds and
hydrocarbon-bearing, shale-containing formations, which typically
contain methane (CH.sub.4) and small amounts of other light
hydrocarbon gases.
[0103] When a CO.sub.2 containing treatment fluid is injected into
an appropriate formation (such as described above, for example) at
a pressure above the fracture pressure of the formation, the
formations can be effectively fractured to stimulate production of
methane and other hydrocarbon gases. The fracturing relieves
stresses in the formation, decaps trapped gases, and creates pore
spaces and channels for the flow of gas from the formation into a
wellbore. Additionally, because of preferential displacement of
absorbed or latticed methane by CO.sub.2, further methane is
evolved from the treatment than would otherwise occur with other
fracturing treatments or with the use of other gases. The use of
CO.sub.2 also provides longer term enhancement of the overall gas
production due the ability of CO.sub.2 to displace methane. If
enough methane is displaced in the localized area of the fracture
face surrounding the wellbore, the pressure in the formation may
also drop sufficiently low so that it falls below the critical
desorption pressure of methane within the formation, which can
result in spontaneous desorption and significant production of
methane.
[0104] Fracturing according to the invention can be used with any
formation where hydrocarbon production, particularly gaseous
hydrocarbon production, is sufficiently impeded by low formation
pressures and/or low formation permeability (i.e., a "tight"
formation). Formations (e.g., shale formations, coal beds, and the
like) having sufficiently low permeabilities so as to make
fracturing a favorable method of enhancing recovery may include
those having a permeability of less than about 10 mD, less than
about 5 mD, less than about 1 mD, or less than about 0.5 mD.
[0105] A fracturing method according to the present invention may
comprise introducing a CO.sub.2 containing stream (such as through
a well bore or other injection well) into a formation at a pressure
that is above the fracture pressure of the formation. Fracturing
methods can particularly comprise the use of a surface combustor.
Accordingly, the CO.sub.2 containing stream may essentially be the
combustion product stream that exits the combustor. In other
embodiments, CO.sub.2 containing stream may be the stream that
exits the turbine or other power production components. In still
further embodiments, the CO.sub.2 containing stream may be the
stream that exits the components used in any separation process
steps that may be carried out. Moreover, additional fracture
materials may be added to the CO.sub.2 containing stream at any
point after combustion and immediately prior to introduction into
the fracture (which may include combinations taking place within
the well bore itself). Such additional components include, but are
not limited to proppants, surfactants (e.g., aliphatic or
oxygen-containing hydrocarbon polymers, hydrofluoropolymers, or
perfluoropolymers, partially or fully fluorinated small molecules
with molecular weights up to 400 grams per mole, perfluoroethers,
neutral surfactants, charged surfactants, zwitterionic surfactants,
fatty acid esters, and/or surfactants that give rise to
viscoelastic behavior), gelling agents, or water (including
brines). The CO.sub.2 containing stream also can be characterized
as being expressly free of any or all of the foregoing components
or any further components that may be typically recognized as being
useful in a fracture fluid. In addition, the CO.sub.2 containing
stream may be introduced into the formation simultaneously, before,
after, or sequentially with water and/or a further fracture fluid
or material.
[0106] Carbon dioxide can be particularly useful to displace
methane from lattice structures, such as methane hydrates and
methane clathrates, as well as to displace adsorbed methane from
the surfaces, pore spaces, interstices, and seams of a formation.
Other gases, such as nitrogen or air, typically do not exhibit a
similar preferential tendency to displace the absorbed or latticed
methane. Coal beds and gas hydrates, in particular, show
preferential adsorption of or replacement by CO.sub.2 compared to
methane.
[0107] Because of the tendency for CO.sub.2 to displace methane
from lattice structures and displace adsorbed methane from the
surfaces, pore spaces, interstices, and seams of a formation,
CO.sub.2 produced according to the present invention also can be
specifically used to achieve these functions in the absence of
fracturing. In other words, the CO.sub.2 containing stream can be
introduced into a formation, such as at a pressure below the
fracture pressure of the formation but at a pressure sufficient to
enter seams or cracks in the formation or at a pressure sufficient
to enter at least a portion of the pores of the formation so as to
displace adsorbed hydrocarbon gases or otherwise facilitate removal
of hydrocarbon gases from the formation. This particularly may be
beneficial for natural gas recovery from coal beds, sub-surface
coal seams (particularly those that are deep and/or have one or
both of economic and technical production problems), and shale gas
formations where natural gas or other short chain hydrocarbon gases
are associated with the solid materials and are preferentially
displaced by the CO.sub.2. While CO.sub.2 in a fracturing method
preferably is produced via surface combustion to allow for the
optional inclusion of further materials, CO.sub.2 for a pure gas
recovery method without fracturing may be produced via surface
combustion or in a down-hole combustor. The CO.sub.2 containing
stream that is injected into such formations through a first well
bore (i.e., an injection well) displaces the hydrocarbon gases
therefrom, at least partially combines with the displaced
hydrocarbon gases, and facilitates recovery of the hydrocarbon
gases from the formation, such as through the injection well or one
or more recovery wells. The recovered hydrocarbon gases optionally
can be treated, as further described below.
[0108] In addition to enhancing recovery of hydrocarbon gases, the
inventive methods also may be used to both form and recover a fuel
material. For example, CO.sub.2 will react chemically with coal,
particularly at elevated temperatures and pressures, to produce CO
and H.sub.2 (as well as water). Thus, CO.sub.2 produced according
to the present invention may be introduced to a coal formation so
as to chemically react with the coal and form CO and H.sub.2, which
can be recovered as otherwise discussed herein and used as fuel
materials--e.g., in the production of syngas. In certain
embodiments, a multiple functions could be performed wherein
injection of CO.sub.2 into the coal formation can displace for
recovery any hydrocarbon gases associated therewith, and/or react
with the coal to form CO and H.sub.2 for recovery, and/or sequester
at least a portion of the CO.sub.2 within the coal formation.
[0109] The CO.sub.2 produced according to the present invention
also can be useful for enhancing recovery of liquid fuel materials
(e.g., crude oil) and even highly viscous fuel materials (e.g.,
bitumen, tar sands, and oil shale). The use of a CO.sub.2
containing stream in relation to such liquid and/or highly viscous
fuel materials can be effective to enhance the recovery thereof
through a variety of methods, such as one or both of increasing
formation pressure and altering the physical nature of the fuel
material (e.g., reducing the viscosity thereof).
[0110] Oil displacement by CO.sub.2 injection can depend upon the
phase behavior of the mixtures of the CO.sub.2 and the crude, which
can depend upon a variety of factors, such as reservoir
temperature, reservoir pressure, and crude oil composition.
Although not wishing to be bound by theory, it is believed that the
mechanisms that facilitate crude oil displacement can include oil
swelling, viscosity reduction, and complete miscibility of the
CO.sub.2 and the crude oil. The methods of the present invention
can provide for one or any combination of such mechanisms for
enhancing recovery of oil and highly viscous hydrocarbons from a
formation. Although the discussion below generally discusses
removal of liquid hydrocarbons in relation to oil (or crude oil),
it is understood that such disclosure can relate to enhancing
recovery of oil of a wide range of viscosities and also can relate
to enhancing recovery of other, highly viscous hydrocarbons--e.g.,
bitumen, tar sands, oil shale, and the like.
[0111] When CO.sub.2 is injected into an oil reservoir, it can
become mutually soluble with the residual crude oil as light
hydrocarbons from the oil dissolve in the CO.sub.2 and the CO.sub.2
dissolves in the oil. The extent of such mutual dissolution can
increase as the density of the CO.sub.2 increases, which can
particularly favor providing the CO.sub.2 in a compressed (i.e.,
pressurized) form. Mutual dissolution also can be greater in
formations wherein the oil contains a significant volume of "light"
(i.e., lower carbon) hydrocarbons. When the injected CO.sub.2 and
residual oil are miscible, the physical forces holding the two
phases apart (interfacial tension) effectively disappear. This
enables the CO.sub.2 to displace the oil from the rock pores,
pushing it towards a producing well. As CO.sub.2 dissolves in the
oil it swells the oil and reduces the oil viscosity, which also
helps to improve the efficiency of the displacement process.
[0112] Since the minimum pressure needed to attain mutual
dissolution of the oil and the CO.sub.2 can be a factor of
reservoir temperature, reservoir pressure, CO.sub.2 stream
pressure, and oil density (i.e., the relative fraction of light
hydrocarbons), the minimum pressure needed to attain oil/CO.sub.2
miscibility can vary. Accordingly, in addition to controlling the
nature of the injected CO.sub.2 stream (i.e., temperature,
pressure, and optional additives, such as steam), the invention can
comprise additional treatments in addition to the CO.sub.2
injection. For example, prior to, after, or simultaneous with
CO.sub.2 injection, the invention also can comprise water injection
into the formation, which can be particularly beneficial to
increase the reservoir pressure. More specifically, the invention
may comprise alternating injection of the CO.sub.2 stream with
volumes of water. This technique may be referred to as water
alternating gas (or "WAG") floods. Such method may be useful to
mitigate any tendency for the lower viscosity CO.sub.2 to creep
ahead of the displaced oil. Other, similar techniques also can be
encompassed by the present invention.
[0113] By way of example only, a CO.sub.2 injection method for
enhanced oil recovery according to the invention may be carried out
as follows. First, combustion can be carried out as already
described herein to produce a CO.sub.2 containing stream
(preferably comprising supercritical CO.sub.2). The combustion may
be carried out above ground or down-hole, and any intervening steps
deemed appropriate under the specific circumstances of the
formation being stimulated may be carried out (e.g., expansion for
power production and/or separation of any stream components that
are not desired for injection). Preferably, if surface combustion
is used, the combustion system can be located significantly close
to the injection well and/or the oil field where the CO.sub.2
containing stream is to be used. The CO.sub.2 particularly can be
provided for injection at an injection pressure as otherwise
described herein.
[0114] Next, the CO.sub.2 containing stream exiting the combustor
(or further system components as desired) can be directed to one or
more injection wells strategically placed within a pattern to
optimize the areal sweep of the reservoir. This can be via a
relatively short transfer line as discussed above. When down-hole
combustion is used, directing of the CO.sub.2 containing stream can
comprise simply outputting the CO.sub.2 containing stream from the
combustor and directly into the formation, such as through
perforations in a well casing or through an open rock face. The
injected CO.sub.2 enters the reservoir and moves through the pore
spaces of the formation rock. As the CO.sub.2 moves through the
reservoir and encounters deposits of crude oil, it can become
miscible with the oil and form a concentrated oil bank that is
swept towards the separate producing well(s)--which may include the
injection well in some embodiments. In other words, the movement of
the CO.sub.2 containing stream through the reservoir enhances
movement of the oil out of the formation and into the producing
well(s). This may proceed because of the mutual solubility
phenomenon described above and because the formation still exhibits
a sufficient pressure to "push" the oil/CO.sub.2 combination (which
now has a reduced viscosity and/or density in relation the oil
alone) to the open producing wells (which have a much reduced
density in relation to the formation itself). Movement of the oil
to the producing well(s) also may arise from an increase in the
formation pressure arising from the injection of the CO.sub.2
therein (and/or any other re-pressurizing materials that may be
injected--e.g., water).
[0115] At the producing well(s), oil (typically as a mixture of
oil, CO.sub.2, water, and possibly hydrocarbon gases) is delivered
to the surface (which typically can include active pumping) for
processing, as described below. The CO.sub.2 containing stream may
be injected into a number of injection wells, and the pattern of
injector wells and producer wells can change over time. Desirable
patterns can be determined based on recognized engineering models,
such as computer simulations that model the reservoir's behavior
based on different design scenarios.
[0116] Although the use of CO.sub.2 in stimulating oil and gas
wells has previously been known, it is well recognized that
CO.sub.2 EOR is a capital-intensive undertaking with the single
largest project cost typically being the cost to purchase the
CO.sub.2 for injection, particularly at the necessary pressure and
purity. It has been estimated that in EOR procedures, the total
CO.sub.2 costs (both purchase price and recycle costs) can amount
to 25 to 50 percent of the cost per barrel of oil produced. The
present invention can overcome such limitations by providing a
continuous source of CO.sub.2 that is formed in close proximity to
the injection sites and can even be formed down-hole to even
further eliminate CO.sub.2 transportation costs. Moreover, CO.sub.2
production costs can be effectively offset through power production
via a pre-injection cycle as described above and even through power
production using the production stream in some embodiments.
Moreover, as additionally described herein, combustion fuel costs
can be significantly offset through use of a fraction of the fuel
materials recovered in the enhanced recovery process (including
liquid and gaseous fuel materials).
[0117] In addition to the high up-front capital costs of a CO.sub.2
supply/injection/recycling scheme, the initial CO.sub.2 injection
volume typically must be purchased well in advance of the onset of
incremental production. Accordingly, the return on investment for
CO.sub.2 EOR has tended to be low, with only a gradual, long-term
payout. Given the significant front-end investment in wells,
recycle equipment, and CO.sub.2, the time delay in achieving an
incremental oil production response, and the potential risk of
unexpected geologic heterogeneity significantly reducing the
expected response, CO.sub.2 EOR has heretofore been considered a
risky investment by many operators, particularly in areas and
reservoirs where it has not been implemented previously. Moreover,
it has previously been understood that oil reservoirs with higher
capital cost requirements and less favorable ratios of CO.sub.2
injected to incremental oil produced will not achieve an
economically justifiable return on investment without improved
technology and/or fiscal/tax incentives for storing CO.sub.2.
Again, the present invention overcomes these shortcomings and makes
CO.sub.2 based enhanced recovery methods economically justifiable
and even advantageous across a wide range of fuel material deposits
and even further types of deposits.
[0118] As already noted above, the methods and systems of the
present invention can be particularly beneficial in light of the
ability to position the combustor apparatus down-hole within the
reservoir or formation. Such embodiments can be particularly useful
in EOR methods. More specifically, down-hole combustor embodiments
can be highly advantageous for use with bitumen-containing
formations, for use in tar sands, for use in oil shale extraction,
and for use with heavy oil generally--i.e., oil having an American
Petroleum Institute (API) gravity of below about 20. In specific
embodiments, the inventive methods and systems particularly can be
used in formations containing oil with an API gravity that is less
than about 19, less than about 18, less than about 17, less than
about 16, less than about 15, less than about 14, less than about
13, less than about 12, less than about 11, less than about 10,
less than about 9, or less than about 8. API gravity can be
directly measured using a hydrometer graduated with API gravity
units as detailed in ASTM D287. Alternately, API gravity may be
calculated from the density of the oil, which can be measured using
either a hydrometer, as detailed in ASTM D1298, or with an
oscillating U-tube method, as detailed in ASTM D4052. Density
adjustments at different temperatures, corrections for soda-lime
glass expansion and contraction and meniscus corrections for opaque
oils are detailed in the Petroleum Measurement Tables details of
usage specified in ASTM D1250. The specific gravity is then
calculated from Formula 1 below, and the API gravity is calculated
from Formula 2 below.
SG oil = .rho. oil .rho. H 2 O Formula 1 API gravity = 141.5 SG -
131.5 Formula 2 ##EQU00001##
[0119] Use of a down-hole combustor in the enhanced recovery of
fuel material deposits from a formation according to certain
embodiments of the invention is illustrated in the flow diagram of
FIG. 1. Particularly, the figure illustrates a cross-section of a
typical geological formation consisting of (from top to bottom) a
top soil layer 2, a low porosity rock layer 3 (such as shale) that
does not permit significant oil infiltration, a medium porosity
rock layer 4 that may or may not allow for oil infiltration, an oil
containing layer 5 (such as sandstone or limestone) that has a
sufficient porosity to contain oil and possibly allow for free flow
therefrom to a lower pressure zone, and a further medium porosity
rock layer 6. It is understood that such geological formation is
only exemplary, and geological formations that may benefit from the
methods of the present invention may have more or fewer layers with
a variety of different configuration, including crossing of layers.
Moreover, the discussion in relation to an oil containing layer
should not be viewed as limiting down-hole combustion to only such
formations.
[0120] An injection well 100 is shown penetrating the various
geological formation layers including the oil containing layer 5.
Although a single injection well is shown, it is understood that a
plurality of injection wells could be utilized. Moreover, the
injection well may be a pre-existing well bore that is modified, if
necessary, to accommodate the down-hole combustor (or its products)
or may be a purposefully formed drill hole. The illustrated
injection well 100 includes a conductor casing 101, a surface
casing 102, and a production casing 103, each of which may be
cemented in position. Interior to the production casing is a
working pipeline 104 that is utilized for delivery of combustion
materials. In some embodiments, the working pipeline may be absent,
and delivery of combustion materials may proceed through the
production casing. In instances where a well is formed expressly
for the purpose of down-hole combustion, casing combinations may
vary or be essentially absent. For example, the injection well
could comprise simply a conductor, a surface casing, and an open
bore hole extending below the lower edge of the surface casing. In
the illustrated embodiment, an injection packing plug 110 for use
as a pressure seal is provided near the lower terminus of the
working pipeline 104 to isolate the upper portion of the well from
the combustion zone 112 below.
[0121] Within the combustion zone 112 is a combustor 300, such as a
transpiration cooled combustor as described otherwise herein. The
combustor is geographically aligned with the oil containing layer
(or formation) relatively low in the formation. The exact location
within the formation may vary--e.g., high in the formation to favor
downward movement of the injected materials or low in the formation
to favor upward permeation of the injected materials--and such
location can depend upon the exact nature of the injected materials
and the exact nature of the deposit to be recovered from the
formation). In particular embodiments, it may be desirable to use
one or more non-vertical wells as an injection well. For example,
the injection well may include one or more diagonal or horizontal
sections from which the CO.sub.2 containing stream may be injected
into the formation. The injection well likewise may include one or
a plurality of branches that may be any of vertical, horizontal, or
diagonal in relation to the surface at ground level. In further
embodiments, the combustor or components directing the CO.sub.2
containing stream may be situated on rails or pulleys or may
utilize other mechanisms to allow it to move in all potential
directions. Valves that control the flow to various portions of the
combustor can also be used to control the direction of CO.sub.2
flow.
[0122] A combustion fuel source 10 provides combustion fuel
down-hole to the combustor 300, such as via an associated pipeline
or otherwise suitable delivery means. As further described below,
the combustion fuel may be a fraction of the recovered fuel
material from the deposit formation. An oxidant source 20 (which is
an air separation unit providing O.sub.2 by way of example in this
embodiment) provides O.sub.2 (preferably in a substantially
purified form, as described above) down-hole to the combustor, such
as via an associated pipeline or otherwise suitable delivery means.
A CO.sub.2 stream 30 also is provided for passage through the
combustor. In the illustrated embodiment, the CO.sub.2 stream
converges with the O.sub.2 stream from the oxygen source at mixer
25. Alternately, the CO.sub.2 stream may go directly to the
combustor in a separate delivery line. Still further, an additional
or different mixer apparatus may be used to combine the fuel,
oxygen, and CO.sub.2 prior to passage into the combustor. In
embodiments where CO.sub.2 from combustion is significantly
sequestered within the injected formation or is not recycled to the
combustion method, the CO.sub.2 stream may be absent. In the
illustrated embodiment, the combustion system further includes a
quenching fluid source 40, which may specifically provide water, a
different quenching fluid (including CO.sub.2), or mixtures of
quenching fluids to the combustor via an associated pipeline or
otherwise suitable delivery means. The quenching fluid may
specifically be delivered to the combustor as a transpiration
cooling fluid. Additionally, the CO.sub.2 stream may be delivered
to the combustor through the quenching fluid source (particularly
when CO.sub.2 may be desired for use as a transpiration cooling
fluid).
[0123] When the combination of feeds (i.e., O.sub.2, water,
CO.sub.2, and fuel) are delivered to the combustor, combustion can
proceed, and the combustion products exiting the combustor can
include one or more of heat, steam, CO.sub.2, and reaction
by-products as otherwise discussed herein. The combustor can be
described as having an input zone wherein the fuel and further
materials are delivered and an output zone from which the
combustion product stream is produced. As seen in FIG. 1, the
production casing 103 can include one or more perforations 105,
which can be located significantly in the area of the combustor 300
or may be spaced at varying locations corresponding to the oil
producing formation. Such perforations can provide passage of the
combustion product stream out of the well and into the oil
containing formation. In other embodiments, the production casing
103 may be absent, at least within the oil producing formation, and
the combustion product stream can readily flow through the
formation pores.
[0124] Propagation of the combustion products through the producing
formation facilitates recovery of the formation deposits (e.g.,
oil) through one or more producing wells 200. Such propagation of
the combustion products and the formation deposits is illustrated
by the block arrows in FIG. 1. The unfilled arrows represent
combustion product entering the formation. The successively darker
arrows represent formation deposits (e.g., oil) that are miscible
with the CO.sub.2 and, having a now reduced viscosity (and
optionally increased temperature from steam treatment and/or
increased pressure), proceed into the producing well. In some
embodiments, the injection well 100 may be configured so as to
inject the combustion product stream at a first zone within a
producing formation and to receive produced formation deposits in a
second zone within the producing formation. For example, injection
of the combustion product stream could proceed from the production
casing below the packing plug 110, and deposits could enter the
production casing above the packing plug through one or more
additional perforations (not shown), and the recovered deposits
could flow through the annular space between the production casing
103 and the working pipeline 104.
[0125] The separate producing well 200 shown in FIG. 1 includes a
conductor casing 201, a surface casing 202, and a production casing
203, each of which may be cemented in position. In this embodiment,
the production casing only extends a short distance below the lower
terminus of the surface casing, and the remaining portion of the
well therebelow is illustrated as simply an open well bore 206. In
other embodiments, the production casing may extend further down
within the well, and the open well bore could in fact include a
liner or casing that could be perforated or otherwise porous to
allow passage of produced deposits into the well. Interior to the
production casing is a producing pipeline 204 that is utilized for
delivery of the recovered deposits to the surface, and the
producing pipeline is surrounded near the lower terminus thereof
with a production packing plug 210.
[0126] The recovered deposit stream 250 delivered to the surface of
the producing well 200 may undergo one or more processing steps.
For example, the recovered deposit stream may pass through an
expander 320 to reduce the pressure of the stream. The optionally
reduced pressure stream may pass through a separation unit 330,
such as to separate a heavy oil stream 332 from a light gas stream
334. The light gas stream may proceed through a gas separator 340
that can isolate a hydrocarbon gas stream 342 from any CO.sub.2
(and/or impurities--e.g., H.sub.2S) combined with recovered deposit
stream. The expanded CO.sub.2 stream 344 can optionally proceed
through a power generation turbine 350 to produce electricity (E),
and the expanded CO.sub.2 stream 30 can proceed to the mixer 25 for
combining with the O.sub.2 stream for re-injection into the
injection well 100. In alternate embodiments any of streams 250,
332, 334, 342, and 344 could be input directly to the combustion
system, particularly if any of the intervening pressure adjustment,
separation, or power production components are not needed or
desired.
[0127] In some embodiments, rather than separating out the light
gases, such component may remain in combination with the CO.sub.2
stream for input to the combustor. In this manner, the requirement
of a separate fuel source for the combustor can be partially or
completely eliminated. In effect, a method according to the
invention thus can produce a crude oil product for market, and any
produced light gases can be used as the fuel source for the
combustor to form further CO.sub.2 to continue the EOR operation.
Still further, the gas separation step may still occur, and any
separated hydrocarbon gases can be delivered to the combustor as
the fuel source. Further embodiments related to separation of
components of the product recovery stream are otherwise discussed
herein.
[0128] In some embodiments, it can be useful to specifically
proportion the ratio of oxidant to CO.sub.2 that is input to the
combustor. For example, the amount of oxidant introduced to the
combustor can be less than about 50% by weight of the amount of
CO.sub.2 introduced into the combustor. In further embodiments, the
amount of oxidant introduced to the combustor can be less than
about 45%, less than about 40%, less than about 35%, or less than
about 30% by weight of the amount of CO.sub.2 introduced into the
combustor. In specific embodiments, the amount of oxidant
introduced to the combustor can be about 10% to about 50%, about
10% to about 45%, about 12% to about 40%, about 12% to about 35%,
or about 15% to about 30% by weight of the amount of CO.sub.2
introduced into the combustor.
[0129] In certain embodiments, it can be particularly desirable to
produce a significant quantity of steam as part of the combustion
process. Specifically, water may be added to the combustion cycle
(e.g., as a quenching fluid in the combustor) and may particularly
be input to the combustor as a transpiration coolant. Thusly, in
addition to CO.sub.2, the combustion process also can provide a
relatively large volume of steam. In certain embodiments, the steam
fraction may be less than about 50%, less than about 40%, less than
about 30%, less than about 20%, less than about 10%, or less than
about 5% of the combustion stream on a mass to mass basis. If
desired, however (such as in a thermal EOR process), the steam
fraction may be greater than 50% by mass of the combustion product
stream.
[0130] In advantageous embodiments, the invention can be
characterized in relation to the down-hole use of the combustor
with an excess of oxidant (e.g., O.sub.2 or air). In specific
embodiments, the amount of O.sub.2 that is provided in excess of
the stoichiometrically necessary content for combustion of the fuel
is at least about 0.1%, at least about 0.2%, at least about 0.25%,
at least about 0.5%, or at least about 1.0% on a molar basis. In
other embodiments, the stoichiometric excess of O.sub.2 over the
amount necessary for combustion of the fuel is about 0.1% to about
5%, about 0.15% to about 4%, about 0.2% to about 3%, or about 0.25%
to about 2.5% on a molar basis. The amount of air that is provided
in excess of the stoichiometrically necessary content for
combustion of the fuel can be up to about a 40 fold excess.
Providing such stoichiometric excess can be useful to ensure
complete combustion of the carbonaceous fuel (which has the same
characteristics as described above with the ability to accept
directly the produced, enhanced recovery off-gas). This is
desirable because it can substantially or completely eliminate
production of carbon (i.e., soot), which could substantially plug
the formation. For example, the provision of a large excess of
oxidant can be effective to oxidize coal to produce carbon monoxide
(CO). In particular embodiments, carbon production can be limited
such that the combustion product stream comprises less than about
2%, less than about 1.5%, less than about 1%, less than about 0.5%,
less than about 0.25%, or less than about 0.1% by weight of
particulate carbon (or soot).
[0131] Providing an excess of oxidant (particularly O.sub.2) is
counterintuitive in relation to an oil or natural gas well since
such wells typically require that any O.sub.2 present be strictly
defined at a very low level to avoid problems of algae growth or
sulfur deposition. In the present combustion systems and methods,
however, the excess O.sub.2 is provided as part of a high
temperature gas stream. Under the conditions described herein, any
excess O.sub.2 remaining after combustion may be effectively
removed by side reactions with hydrocarbons in the reservoir. For
example, the following reactions may occur under such
conditions.
Coal (CH.sub.x)+O.sub.2.dbd.CO+0.5XH2O Formula 3
2CO+O.sub.2=2CO.sub.2 Formula 4
CO.sub.2+C=2CO Formula 5
CO+H.sub.2O.dbd.CO.sub.2+H.sub.2 Formula 6
H.sub.2+O.sub.2.dbd.H.sub.2O Formula 7
Oil (CH.sub.2)x+O.sub.2.dbd.CO+XH.sub.2O Formula 8
[0132] It is expected that the reactions of Formulas 4-7 likewise
would follow the reaction of Formula 8.
[0133] In addition to the foregoing, the use of a down-hole
combustor with transpirationally injected water flow can be
particularly advantageous for controlling the temperature of the
enhanced recovery fluid stream. More specifically, the water
content (and optionally the CO.sub.2 stream) can be adjusted as
necessary to directly cool the combustion product stream to a
user-designed, controlled temperature that can be set for maximum
oil recovery in the particular reservoir. For example, combustion
product stream temperatures can be controlled in the range of about
100.degree. C. to about 1,800.degree. C. or any of the further
ranges otherwise disclosed herein.
[0134] Although down-hole combustion has been previously discussed
in the art, such methods differ from the present invention because
the combustion in the known systems does not include a where
sufficiently high temperatures and pressures can be achieved to
facilitate combustion of even contaminated fuels, as further
discussed below. Moreover, known down-hole combustion techniques
typically have required the use of a solid support catalyst to
prevent soot production and plugging of the face of the
oil-producing formation. As already noted above, the present
invention can eliminate the requirement of such catalyst systems.
If desired, however, in particular embodiments, combustion
according to the present invention (either surface combustion or
down-hole combustion) also may incorporate the use of a
catalyst.
[0135] Particular embodiments encompassing surface combustion are
illustrated in FIG. 2. As seen therein, the general nature of the
system and method is similar to down-hole combustion in that a fuel
source 10 provides combustion fuel to the combustor 300 positioned
at the surface, preferably substantially close to the injection
well 100. An oxygen source 20 (such as an air separation unit in
this exemplary embodiment) provides O.sub.2 (preferably in a
substantially purified form, as described above) to the combustor.
A working fluid source 31 also is included to provide the working
fluid, such as a CO.sub.2 stream, for passage through the
combustor. Optionally, a further quenching fluid, such as water,
could be provided to the combustor. The quenching fluid and/or the
working fluid may specifically be delivered to the combustor as a
transpiration cooling fluid per the discussion already provided
above. A mixer apparatus may be used to combine the fuel, oxygen,
and CO.sub.2 prior to passage into the combustor.
[0136] By way of example, FIG. 2 illustrates a cross-section of a
typical geological formation consisting of (from top to bottom) a
top soil layer 2, a low porosity rock layer 3 (such as shale), a
fossil fuel reservoir and/or coal bed layer 7 that includes methane
and possibly other light hydrocarbons therein, and further medium
porosity rock layer 6. Again, the actual layering of geological
strata may vary.
[0137] The injection well 100 is shown penetrating the various
geological formation layers including the coal bed layer 7.
Although a single injection well is shown, it is understood that a
plurality of injection wells could be utilized. Moreover, the
injection well may be a pre-existing well bore that is modified, if
necessary, to facilitate CO.sub.2 flow or may be a purposefully
formed drill hole. The illustrated injection well 100 includes a
conductor casing 101, a surface casing 102, and a production casing
103, each of which may be cemented in position. Interior to the
production casing is a working pipeline 104 that includes a central
pipe 115 for injection of the CO.sub.2 containing stream into the
well. In some embodiments, the working pipeline may be absent, and
delivery of the CO.sub.2 containing stream may proceed through the
central pipe alone. In the illustrated embodiment, an injection
packing plug 110 for use as a pressure seal is provided near the
lower terminus of the working pipeline 104 to isolate the upper
portion of the well from the injection zone 113 below.
[0138] As illustrated in FIG. 2, the production casing 103 can
include one or more perforations 105, which can be spaced at
varying locations within the coal bed formation. Such perforations
can provide passage of the combustion product stream out of the
well and into the coal bed. In other embodiments, the production
casing 103 may be absent, at least within the coal bed formation,
and the combustion product stream can readily flow through the
pores in the face of the coal bed and/or through seams in the coal
bed.
[0139] In particular embodiments, it may be desirable to use one or
more non-vertical wells as an injection well. For example, the
injection well may include one or more diagonal or horizontal
sections from which the CO.sub.2 containing stream may be injected
into the formation. The injection well likewise may include one or
a plurality of branches that may be any of vertical, horizontal, or
diagonal in relation to the surface at ground level. The injection
may again have the potential or translational, axial, and
rotational movement.
[0140] In operation, a fuel source 10 provides combustion to the
combustor 300, such as via an associated pipeline or otherwise
suitable delivery means, and such fuel may be a fraction of the
fuel material recovered from the deposit formation. An oxygen
source 20 (such as an air separation unit) provides O.sub.2
(preferably in a substantially purified form, as described above)
to the combustor, such as via an associated pipeline or otherwise
suitable delivery means. A CO.sub.2 stream 31 also is provided for
passage through the combustor. In the illustrated embodiment, the
CO.sub.2 stream preferably functions as a working fluid, and/or a
quenching fluid, and/or a transpiration fluid. If desired, a
different working fluid and/or quenching fluid and/or transpiration
fluid (which may be the same or different) may be used, and
separate sources for each stream may be provided. A mixer apparatus
may be used to combine the fuel, oxygen, and the working fluid
prior to passage into the combustor.
[0141] The combustor 300 includes an output from which flows a
combustion product stream, which can be described as a CO.sub.2
containing stream. The CO.sub.2 may be in any form as already
discussed above. The combustion product stream is input to a
turbine 350 to produce electricity (E), and the turbine output
stream is directed either to further processing or the injection
well. Processing components 375 may include one or more of a heat
exchanger, a separation unit (e.g., for removing water or trace
impurities), a compressor, an expander, and a cooling unit. The
CO.sub.2 containing stream--either exiting the turbine or a
processing component--is at least partially directed into the well
via the central pipe 115 and enters the coal bed formation 7
through the perforations 105 in the production casing 103.
[0142] Propagation of the CO.sub.2 containing stream through the
coal bed facilitates recovery of the formation deposits (e.g.,
methane) through one or more producing wells 200. Such propagation
of the combustion products and the formation deposits is
illustrated by the block arrows in FIG. 2. The unfilled arrows
represent the CO.sub.2 containing stream entering the formation.
The successively darker arrows represent formation deposits (e.g.,
methane) that commingle with the CO.sub.2 and/or are simply
displaced by the CO.sub.2 and proceed into the producing well. In
some embodiments, the injection well 100 may be configured so as to
inject the combustion product stream at a first zone within a
producing formation and to receive produced formation deposits in a
second zone within the producing formation. For example, injection
of the combustion product stream could proceed below the packing
plug 110, and deposits could enter the production casing above the
packing plug through one or more additional perforations (not
shown), and the recovered deposits could flow through the annular
space between the production casing 103 and the working pipeline
104.
[0143] The separate producing well 200 shown in FIG. 2 includes a
conductor casing 201, a surface casing 202, and a production casing
203, each of which may be cemented in position. In this embodiment,
the production casing only extends a short distance below the lower
terminus of the surface casing, and the remaining portion of the
well therebelow is illustrated as simply an open well bore 206. In
other embodiments, the production casing may extend further down
within the well, and the open well bore could in fact include a
liner or casing that could be perforated or otherwise porous to
allow passage of produced deposits into the well. Interior to the
production casing is a producing pipeline 204 that is utilized for
delivery of the recovered deposits to the surface, and the
producing pipeline is surrounded near the lower terminus thereof
with a production packing plug 210 that provides a seal.
[0144] The recovered methane stream 251 delivered to the surface of
the producing well 200 may undergo one or more processing steps,
and all or a portion of the methane stream may be directed back
into the combustor system. For example, the recovered deposit
stream may be processed through one or more of an expander to
reduce the stream pressure, one or more separation units to
separate a pure methane stream for market and/or separate a further
hydrocarbon gas stream from any CO.sub.2 (and/or impurities--e.g.,
H.sub.2S), and a further power generation turbine, all of which are
described above in relation to FIG. 1. As illustrated in FIG. 2, a
fraction of the methane stream 251 may be directed to the fuel
source. This fraction may be a combination of one or more
hydrocarbon gases and may include any impurities produced in the
methane stream. A further fraction of the methane stream may be
directed to the working fluid source. This fraction may be a
separated CO.sub.2 stream and may include any impurities produced
in the methane stream.
[0145] The choice of using surface combustion or down-hole
combustion can depend upon a variety of factors, including the type
of material to be recovered and the physical conditions of the
formation. Typically, either system may be employed for enhanced
recovery of any fossil fuel that is in a fluid form--e.g., gaseous
hydrocarbons, low viscosity oils, and even high viscosity oils. For
very high viscosity oils and other highly viscous hydrocarbons
(e.g., bitumen, tar sands, and shale oil), the down-hole combustion
systems can be advantageous because of the ability to easily
provide a high temperature combustion product stream that can
include a significant fraction of steam, which can be beneficial to
increase fluidity of such higher viscosity materials.
[0146] With either surface combustion or down-hole combustion, a
variety of combustion fuels may be used. Specifically, gaseous
hydrocarbons and liquid petroleum may be used, and the combustion
fuel thus may be formed at least in part from the fuel material
that is recovered by the methods. The combustion methods also can
encompass solid fuels as the combustion fuel. For example, coal
could be used, preferably in a particularized and fluidized state.
In such embodiments, it may be useful for the inventive systems to
include a plurality of combustors.
[0147] For example, FIG. 3 illustrates a partial view of the
surface combustion embodiment illustrated in FIG. 2 as modified to
incorporate a partial oxidation combustor 600. FIG. 3 illustrates a
cross-section of a typical geological formation consisting of (from
top to bottom) a top soil layer 2, a low porosity rock layer 3
(such as shale), and a fuel material reservoir 8. As in the
previous figures, the injection well 100 is shown penetrating the
various geological formation layers including the fuel material
layer 8. Although a single injection well is shown, it is
understood that a plurality of injection wells could be utilized.
Moreover, the injection well may be a pre-existing well bore that
is modified, if necessary, to facilitate CO.sub.2 flow or may be a
purposefully formed drill hole. The illustrated injection well 100
includes a conductor casing 101, a surface casing 102, and a
production casing 103, each of which may be cemented in position.
Interior to the production casing is a working pipeline 104 that
includes a central pipe 115 for injection of the CO.sub.2
containing stream into the well. In some embodiments, the working
pipeline may be absent, and delivery of the CO.sub.2 containing
stream may proceed through the central pipe alone. One or more
recovery wells as illustrated in FIG. 1 and FIG. 2 likewise could
be included in the present embodiments.
[0148] As shown in FIG. 3, a solid coal fuel 1010 is provided to
the partial oxidation combustor 600, which is the first combustor
in the series. Although the embodiment is discussed in relation to
coal, it is understood that any sold fuel material could be used as
described. Preferably, the solid fuel, such as coal, can be
particularized, such as by being passed through a mill apparatus.
This could be performed on-site, or the solid fuel could be
provided in a pre-particularized form. The particularized size
could be so as to provide an average particle size of about 10
.mu.M to about 500 .mu.m, about 25 .mu.m to about 400 .mu.m, or
about 50 .mu.m to about 200 .mu.m. The powdered coal can be mixed
with a fluidizing substance to provide the coal in the form of a
slurry (which may be a slurry with CO.sub.2).
[0149] In addition to the solid coal fuel 1010, O.sub.2 from the
oxygen source 20 and CO.sub.2 from the working fluid source 31 can
be provided to the partial oxidation combustor 600. The CO.sub.2
may be optional and may be the source of the fluidizing medium. The
CO.sub.2 also may be used for cooling the partial oxidation
combustor 600. Preferably, the amount of CO.sub.2 used is
sufficient to cool the temperature of the partial oxidation
combustion stream exiting the partial oxidation combustor such that
any ash that is present is in a solid form that can be safely
removed. Accordingly, the CO.sub.2, coal, and O.sub.2 can be
provided to the partial oxidation combustor in ratios such that the
coal is only partially oxidized to produce a partially oxidized
combustion product stream comprising CO.sub.2 along with one or
more of H.sub.2, CO, CH.sub.4, H.sub.2S, and NH.sub.3. The
CO.sub.2, coal, and O.sub.2 also preferably can introduced into the
partial oxidation combustor 600 in necessary ratios such that the
temperature of the partially oxidized combustion product stream is
sufficiently low that all of the ash present in the stream is in
the form of solid particles that can be easily removed by one or
more separators and/or filters--e.g., a cyclone filter. As shown in
FIG. 3, ash removal via filter 650 is shown. In specific
embodiments, the temperature of the partially oxidized combustion
stream can be less than about 1,100.degree. C., less than about
1,000.degree. C., less than about 900.degree. C., less than about
800.degree. C., or less than about 700.degree. C. In further
embodiments, the temperature of the partially oxidized combustion
stream can be about 300.degree. C. to about 1,000.degree. C., about
400.degree. C. to about 950.degree. C., or about 500.degree. C. to
about 900.degree. C. The filtered, partially oxidized combustion
stream leaving the filter 650 can be directly input into the
transpiration cooled combustor 300. This input is provided along
with the O.sub.2 stream from the oxygen source 20 and the recycled
CO.sub.2 working fluid from the working fluid source 31. Combustion
at this point can proceed similarly as otherwise described herein.
The combustible materials in the partially oxidized combustion
stream are combusted in combustor 300 in the presence of O.sub.2
and CO.sub.2 to provide the combustion stream comprising CO.sub.2.
This stream can be expanded across a turbine 350 to produce power
(e.g., via generator). The turbine discharge stream can be passed
through one or more processing components 375, and input to the
central pipe 115 for injection into the well. Of course, it is
understood that such partial oxidation embodiments could be adapted
to the down-hole combustor embodiments, as otherwise described
herein, particularly in relation to FIG. 1.
[0150] The present invention also provides general improvements
over CO.sub.2 flooding methods known in the art. Because the
CO.sub.2 containing stream formed and used in the present invention
is a combustion product stream, the CO.sub.2 containing stream also
can provide a significant amount of heat to the formation. The heat
of combustion thus may be transferred to a portion of the
formation, and such heating can function to facilitate enhanced
recovery of the deposits therein, particularly in relation to
fossil fuels. If desired, the CO.sub.2 containing stream can even
be provided at temperatures sufficient to facilitate cracking of
long chain hydrocarbons, such as in a crude oil formation. This can
be particularly useful for enhancing recovery of high viscosity
oils and even other highly viscous deposits.
[0151] In any of the systems and methods that may be utilized
according to the invention, the production stream removed from the
producing well or wells typically will comprise a mixture of
materials. For example, the recovered fossil fuels can include a
fraction (and even high amounts in certain cases) of hydrogen
sulfides, which may be removed, if desired, to provide an
essentially pure fossil fuel stream. Likewise, any CO.sub.2 passing
through the formation and into the recovery stream typically must
be removed to provide a saleable fossil fuel. The present invention
that utilizes a combustion process to provide the CO.sub.2
containing stream used for enhanced recovery can mitigate or
eliminate the adverse effects of the presence of impurities in a
recovered fossil fuel stream. For example, since the combustion
process can be integrated with a highly efficient and clean
supercritical power cycle using CO.sub.2 as the working fluid (such
as referenced above), such cycle can deal effectively with fuel
streams containing a large fraction of sulfur compounds (and other
impurities). Accordingly, mixtures of fossil fuels, CO.sub.2,
H.sub.2S, and further impurities can be used as the fuel in the
combustion process, even with high CO.sub.2, H.sub.2S, and/or other
impurity fractions. Therefore, by way of example, a variety of
combinations of oils, light gases, CO.sub.2, sulfur compounds, and
other impurities can be directly injected into the power production
cycle for use in combustion and power generation to produce
additional CO.sub.2 and electricity. Likewise, in high pressure,
high temperature, down-hole combustion embodiments, the input
combustion fuel can range from being an essentially pure
hydrocarbon to being a mixture of one or more hydrocarbon fuels
with a variety of impurities in a variety of combinations. In other
words, the combustion process according to the invention that
produces CO.sub.2 for injection in enhanced recovery techniques can
proceed essentially unimpeded including in the presence of even
significant amounts of impurities.
[0152] The fraction of a recovery stream that is utilized as a
combustion fuel in the combustor for production of further CO.sub.2
for enhanced recovery (and, optionally, power production) can vary
depending upon the nature of the formation and any saleable
materials that may be withdrawn from the stream. For example, in
enhanced oil recovery, the recovery stream will include crude oil
and possibly water, gaseous hydrocarbons, and/or H.sub.2S. In some
embodiments, it may be useful for a fraction of the crude oil to be
used as the combustion fuel. Typically, such use will occur after
the oil recovery stream has undergone separation steps useful for
withdrawing other components of the stream, such as natural gas
and/or water.
[0153] When a recovery stream comprising crude oil also contains a
sufficient fraction of gaseous hydrocarbons, specific processing
steps can be applied to separate the gaseous hydrocarbons from the
crude oil. The gaseous hydrocarbons (inclusive of various
impurities included therein) can be used then as the combustion
fuel. In specific embodiments, the gaseous hydrocarbons (which may
mainly comprise methane as the gaseous hydrocarbon component) may
include a significant content of H.sub.2S. The present invention is
particularly useful in that the sour gas can be directly input into
the combustor without any sweetening requirement (i.e., no
significant content of H.sub.2S being removed), although sweetening
is not necessarily precluded. Beneficially, combustion can be
carried out using sour gas without actually lessening the
efficiency of the combustion cycle (efficiency being actual power
production versus the theoretical power production based on the
lower heating value of the natural gas fuel). This is illustrated
in FIG. 4 where efficiency of power production through combustion
of natural gas is shown as a function of sour gas content of the
original crude oil recovery stream. As seen therein, the input
based efficiency (i.e., the efficiency based on the total fuel
input including the natural gas and the H.sub.2S) remains
essentially constant as the H.sub.2S content increases, which
indicates that the presence of the H.sub.2S does not lessen process
efficiency. The use of the sour gas, however, can be characterized
as being beneficial in comparison to the use of pure natural gas
because the fuel based efficiency (i.e., the efficiency based only
on the potential power production of the natural gas) actually
shows a slight increase as H.sub.2S content increases. This is
because the actual amount of natural gas being combusted decreases
as H.sub.2S content increases with substantially no loss in actual
power production. Combustion of the H.sub.2S as a component of the
recovered natural gas stream thus can function as a simplified
means for removal of the H.sub.2S. For example, a natural gas
stream that includes H.sub.2S can be input to a combustor with an
oxidant and optionally CO.sub.2 (which may be at least partially
present in the natural gas stream in addition to the H.sub.2S). The
combustion stream (wherein the H.sub.2S has been converted to
SO.sub.3 via reaction with the oxygen in the combustor) can be
passed through a turbine for power production (e.g., via an
electric generator connected to the turbine) and then through a
heat exchanger to reduce the temperature of the stream. The cooled
stream (e.g., less than about 90.degree. C., less than about
50.degree. C., of less than about 30.degree. C.) can have a
pressure that is greater than about 8 MPa, greater than about 12
MPa, or greater than about 15 MPa. This stream then can be
processed through one or more separation units, such as a condenser
and an acid reactor, wherein the sulfur originally input as
H.sub.2S is removed as sulfuric acid in the acid reactor.
[0154] Although the recovered fossil fuel stream may contain one or
more impurities (including CO.sub.2), in various embodiments, the
inventive systems and methods can be characterized as venting to
the environment only one or more of separated fossil fuels (which
are collected for sale or direct use), electricity, and controlled,
safe waste streams that also are collected and safely removed from
the system. This may be achieved in light of specific processing
that can be applied to the recovered fossil fuel stream, which
processing can be customized based on the actual makeup of the
stream.
[0155] For example, a recovered stream may contain significantly
only fuel material and CO.sub.2. As described above, such mixture
of materials may undergo a separation process to withdraw fuel
materials that may be condensed at the give pressure or otherwise
are in a liquid state under ambient conditions. Thus, a saleable
product stream of liquid fuel material can be provided. The
remaining stream may consist essentially of fuel material
(particularly light hydrocarbons or gaseous hydrocarbons) and
CO.sub.2, and this stream may be used directly as combustion fuel
in the defined combustion process. In this manner, the defined
combustion process can have the characteristic of recovering
virtually 100% of the total CO.sub.2 in its fuel feed (including
any CO.sub.2 resent)--i.e., with virtually zero emission of
CO.sub.2 to the atmosphere. Moreover, since any recovered mixture
of CO.sub.2 and gaseous hydrocarbons can be delivered directly to
the combustion process, there is no need to separate CO.sub.2 from
the low molecular weight hydrocarbons, such as using the absorption
processes, physical separation, or hybrid solution required in the
known art.
[0156] In certain embodiments, an oil production process according
to the invention can involve the production from the well of a high
pressure fluid which must be reduced in pressure to separate a
liquid oil fraction and a gas stream. Such situation has been
described above in relation to a down-hole combustion embodiment,
but such disclosure likewise can apply to surface combustion
systems and methods.
[0157] The pressure reduction for separation of liquid oil
fractions and gaseous hydrocarbon fractions (which typically will
include any CO.sub.2 fraction) can be carried out in a number of
stages with gas separation at each stage to minimize gas
recompression power. The pressure letdown in stages also has the
benefit of fractionating the off-gases in a more controlled
fashion, thus allowing the separation of gas for commercial
dispersion. This may be particularly useful where one or more of
these fractioned gases has a commercial value. The gas stream which
degasses at a particular pressure level could be further processed
for collection as opposed to being returned to the process for
combustion. The residual gas stream can contain a very large
fraction of CO.sub.2. Again, the invention thus can overcome the
limitations in the known art--i.e., the requirement that recovered,
gaseous hydrocarbon streams be treated in process units, such as
the Ryan-Holmes and LTX, to produce pipeline grade natural gas,
liquid propane gas (LPG), and a CO.sub.2 fraction that is recycled
for further recovery methods.
[0158] In enhanced oil recovery methods, it is common for the
deposit recovery stream to comprise mixtures of crude oil, gaseous
hydrocarbons (e.g., methane), and water in a variety of
proportions, depending upon the exact nature of the formation. In
some embodiments, known techniques and processes for fractional
distillation may be utilized for separation of components of the
recovery stream. Desirable procedures for isolating desired
fractions thus may be identified in light of the totality of the
present disclosure in combination, as useful, with known art
procedures. As one example, to process the mixtures for component
separation, it can be desirable for the recovery stream to be in a
favorable temperature range--e.g., about 10.degree. C. to about
50.degree. C., about 15.degree. C. to about 40.degree. C., or
otherwise ambient surface temperatures at the formation site. Other
processing temperatures are not excluded and may in fact be desired
in some embodiments. It is understood, however, that the following
discussion in relation to process pressures may vary based upon the
exact temperature of the recovery stream. Accordingly, in some
embodiments, it may be desirable for the recovery stream to be
temperature adjusted prior to undergoing any pressure letdown
separation steps or even during the pressure letdown steps (e.g.,
raising or lowering temperature before transitioning the stream
from one process pressure to a further, different process
pressure.
[0159] As an example, a recovery stream comprising an oil/gas/water
mixture may be recovered at a pressure of greater than about 60 bar
(6 MPa), greater than about 75 bar (7.5 MPa), greater than about 90
bar (9 MPa), or greater than about 100 bar (10 MPa). When the
stream is processed at a temperature of about 15.degree. C. to
about 40.degree. C., the pressure of the stream may first be
reduced to about 50 bar (5 MPa). At this pressure, possible
components of the mixture that may be withdrawn in gaseous form
include CH.sub.4, C.sub.2H.sub.2, C.sub.2H.sub.4, H.sub.2, Ar,
N.sub.2, and He. Substantially all of the CO.sub.2 present in the
stream likewise would be withdrawn as a gas at this pressure. The
pressure of the stream may then be reduced to about 7 bar (0.7
MPa). At this pressure, possible components of the mixture that may
be withdrawn in gaseous form include C.sub.2H.sub.6, all C.sub.3
compounds (e.g., C.sub.3H.sub.8), and H.sub.2S. The pressure next
may be reduced to about 2 bar (0.1 MPa). At this pressure, possible
components of the mixture that may be withdrawn in gaseous form
include all C.sub.4 compounds (e.g., C.sub.4H.sub.10), and
additional H.sub.2S. The recovery stream thereafter consists mainly
of water, oil, and any residual H.sub.2S (although there may be up
to about 3 g/L of H.sub.2S dissolved in the water at this
temperature and pressure, and the oil fraction may also include
residual amounts of H.sub.2S dissolved therein). Such mixture may
be reduced to ambient pressure at this point and processed through
an oil/water separator. Recovered oil can be sent to tanks, a
pipeline, or other storage or transfer means as desired. Separated
water may be re-injected into the same formation or a different
formation, or the water may be stored or transferred off-site.
[0160] It is understood that further and/or different pressure
stages may be used to isolate specific components of a recovered
stream. Moreover, any combination of pressure letdown stages that
may be envisioned in light of the present disclosure is encompassed
herein. Once the chemical composition of a recovery stream is
identified, the foregoing scheme may be particularized to the
specific chemical composition to partition off specific components
of the recovery stream as desired.
[0161] In certain embodiments, it may be desirable to isolate a
methane gas stream (or streams comprising methane and/or other
gaseous hydrocarbons--include combinations of gaseous compounds
that may be commercially recognized as natural gas) from a recovery
product stream. Such recovery product stream could be a crude oil
stream, as discussed above, that includes a gas fraction. In such
embodiments, the high pressure fraction described above may be
withdrawn and further processed to isolate one or more desired
product streams. In other embodiments, the recovery product stream
may comprise mainly gaseous materials, such as in enhanced recovery
from a natural gas formation or in enhanced coal bed methane
production. In such embodiments, the recovery stream may comprise
methane, other gaseous fuels, and/or non-fuel gases, such as inert
gases or CO.sub.2. In some embodiments, separation of the gaseous
components may be achieved through known techniques in light of the
present disclosure.
[0162] As an exemplary embodiment, a recovery product stream
comprising materials, such as CH.sub.4, C.sub.2H.sub.2,
C.sub.2H.sub.4, H.sub.2, Ar, N.sub.2, He, and CO.sub.2, may be
separated into three streams. The first stream may include
components, such as Ar, N.sub.2, He, and H.sub.2. The second stream
may include CH.sub.4 predominately, and possibly small amounts of
C.sub.2H.sub.2, C.sub.2H.sub.4, C.sub.2H.sub.6, and C.sub.3
hydrocarbons (which mixture may be recognized as a natural gas
stream). The third stream may include predominately C.sub.2H.sub.2
and C.sub.2H.sub.4, and may include small amounts of
C.sub.2H.sub.6, and C.sub.3 hydrocarbons. The above distillation
procedure may be carried out at significantly low
temperatures--e.g., about -150.degree. C. to about -100.degree. C.
Under such conditions, the differential vapor pressures of the
gases can be used to effect the distillations. A variety of
temperatures and pressures can be used to effect the distillations
which depend on the composition of the crude gas stream and the
desired purities of the natural gas product stream (or other gas
product stream). Such conditions may be identified in light of the
present disclosure and distillation procedures recognized in the
art.
[0163] The incorporation of power production components can be
useful to provide electricity for grid distribution and/or internal
use. Associated power cycle components can essentially function as
scrubbers to capture all polluting byproducts (such as sulfur,
nitrogen, ash, heavy metals, and the like) and convert them to
their most benign and easily saleable or disposable forms. Sulfur
can be converted to sulfuric acid; nitrogen compounds can be
converted to nitric acid; metals can be converted to metal salts;
ash can be converted to non-leachable ash. In various embodiments,
the power output can be varied from a small percentage of the total
energy of mined fuel material to a large percentage. It could be
100% in the case of coal, where the electricity is more valuable
than the coal unless the coal is to be converted into liquid fuels
like gasoline, in which case, the electricity production can be
only be enough to power the process systems. This may be in the
range of about 10% to about 50%, about 15% to about 40%, or 20% to
35% of the total energy of the mined fuel material. In embodiments
wherein the product being mined is oil, the electrical generation
can be minimized to only what is necessary to run the associated
systems. For example, in enhanced oil recovery, about 1% to about
10%, about 1% to about 7%, or about 2% to about 5% of the total
energy of the mined oil may be converted into energy on-site.
[0164] In the various manners described above, the present
invention thus can provide a combustion process that produces a
pure CO.sub.2 stream at high pressure for injection into a
formation to enhance removal of a deposit therefrom, particularly a
fossil fuel deposit. Although the combustion process can require
input of a carbonaceous material (including oil, natural gas,
etc.), the produced CO.sub.2 stream can contain substantially all
of the CO.sub.2 that was present in the fossil fuel feed to the
combustor. Thus, the inventive methods may be characterized as
combusting a fossil fuel to enhance recovery of a further fossil
fuel. Preferably, the amount of fossil fuel recovered through the
inventive method can significantly exceed the amount of fossil fuel
input to the combustion system such that the methods and systems
are economically advantageous for enhancing recovery of the fossil
fuel. Moreover, significantly all of the CO.sub.2 produced by the
combustion process is recovered as a component of the recovery
stream exiting the one or more producing wells, becomes sequestered
within the formation in which it was injected, or a combination of
both. In any event, CO.sub.2 directly produced by the combustion
process is contained with the parameters of the method so as to be
sequestered, recycled into the combustion process, or otherwise
captured.
[0165] By way of example, a combustion system according to the
present invention may comprise a combustor in fluid communication
with a power production apparatus, such as a turbine. A fuel may be
combusted in the combustor, and the produced, CO.sub.2 containing
combustion product stream can pass to the turbine where the stream
is expanded to produce power. The expanded CO.sub.2 containing
stream then can be passed through piping or other suitable
apparatus in fluid connection with the turbine to an injection well
located in a fossil fuel containing formation, such piping
optionally extending a distance down into the injection well. The
injected CO.sub.2 containing stream can propagate through the
fossil fuel containing formation so as to enhance removal of the
fossil fuel therefrom, such as by the various methods described
herein. As the CO.sub.2 containing stream propagates further
through the formation, a combination of the fossil fuel and
CO.sub.2 from the stream may move to a low pressure zone, such as a
producing well, and the combined CO.sub.2/fossil fuel stream can be
withdrawn from the producing well. At production, the inventive
systems can comprise piping in fluid communication with the
recovery well, said piping delivering the recovered deposits to one
or more further components in fluid communication therewith. Such
further components are already described above.
[0166] As already noted, the methods and systems of the invention
can be customized to the specific requirements of the deposit to be
recovered from a formation. For example, in relation to recovery of
fossil fuels, the specifications of a system and method according
to the invention can be customized by working through a decision
tree that considers factors, such as the following:
[0167] whether the nature of the formation and the physical
parameters necessary to enhance recovery favors the use of surface
combustion or down-hole combustion;
[0168] whether it is desirable for the CO.sub.2 delivered to the
formation to be in a gaseous state or a supercritical state;
[0169] whether it is desirable for the CO.sub.2 containing stream
to further include steam or other material useful to further
enhance recovery of the fossil fuel;
[0170] whether it is desirable for the combustion product stream to
be used initially in a power production method prior to injection
into the formation;
[0171] whether it is desirable for the combustion product stream to
be otherwise pressure adjusted and/or temperature adjusted prior to
injection into the formation; and
[0172] whether it is necessary to filter or otherwise separate one
or more components from the combustion product stream prior to
injection into the formation.
[0173] A specific advantage of the present invention arises from
the ability to use all or a fraction of the fossil fuel that is
recovered as the fuel for the combustor. This can totally eliminate
the need to deliver fuel from an external source to a combustor
site. The type of fuel available for the combustor can vary
depending upon the fossil fuel(s) present in the formation and the
desired recoverable product that is the main economic driver of the
well or field.
[0174] For example, in an enhanced oil recovery embodiment, the
CO.sub.2/fossil fuel stream can be processed to separate any liquid
oil or other liquid hydrocarbons present. An initial decompression
step may be used, such as described above. The total gas stream
removed from the liquid separation may be optionally recompressed
and then may be directly input to the combustion process as all or
part of the required combustion fuel. If the residual, gaseous
hydrocarbon fraction exceeds the combustion fuel requirements,
further separation steps, as described above, may be applied to
isolate one or more hydrocarbon gas components for market.
[0175] As a further example, in an enhanced natural gas recovery
embodiment and/or an enhanced coal bed methane recovery embodiment,
the total hydrocarbon gas production (the major portion being
methane) preferably will significantly exceed the fuel requirements
for the combustion process. Accordingly, the total recovered
CO.sub.2/methane stream can be separated into two or more
fractions. One fraction (representing a portion of the total
produced gas stream) may be optionally recompressed and then be
input directly into the combustion process as the combustion fuel.
The remaining fraction(s) may undergo various separation processes
as required to isolate the methane (or other sellable gases, such
as propane and butane) for market. Preferably, substantially all of
the CO.sub.2 will be partitioned into the first fraction that is
used as the fuel component. In such embodiments, the produced
methane stream may be input directly to a natural gas pipeline
substantially without any need for purification except possible LPG
recovery. Likewise, when the total gas component in an enhanced oil
recovery method is used as the combustion fuel, the products from
the enhanced oil recovery system can be substantially only oil,
(optionally) LPG, and (optionally) electricity.
[0176] The systems and methods of the invention can be particularly
advantageous for even further reasons. For example, the inventive
systems and methods can reduce the operating costs and/or capital
costs required for extraction of fossil fuels. Additionally, the
systems and methods can create valuable by-products including, but
not limited to, electricity, ammonia, oil, syn-gas, hydrogen,
petroleum and petroleum products, natural gas, other fossil fuels,
thermal heat, steam, and other materials that would be evident to
the skilled person armed with the present disclosure. Further the
inventive methods can eliminate any requirement for external
natural gas, liquid fuel, or solid fuel that may be required in a
combustion process. Still further, the inventive methods can
eliminate any requirement for separation of CO.sub.2, sulfur, CO,
petroleum gases, or other impurities.
[0177] In additional embodiments, the combustion process used to
produce the CO.sub.2 according to the invention can burn all
impurities included in the recovered fossil fuel stream to a form
which provides easily treated waste streams. For example, all
sulfur compounds can be converted to sulfuric acid, which be easily
reacted at minimal capital and operating costs with limestone to
form saleable gypsum or can be produced as solid sulfur.
[0178] The present invention is further beneficial in that a
reliable, consistent, clean source of CO.sub.2 can be provided for
use as and enhanced recovery fluid. The direction of the CO.sub.2
produced as a by-product of power production to the recovery method
beneficially prevents immediate release of the CO.sub.2 to the
atmosphere since the CO.sub.2 rather will be sequestered in the
fossil fuel reservoir after down-hole pumping for recovery purposes
or will be recycled through the combustion system. The amount of
CO.sub.2 sequestered in the formation can depend upon the
miscibility of the oil and the geology of the reservoir. The
CO.sub.2 that is not deposited in the reservoir can be recompressed
and recycled for additional enhanced fossil fuel recovery. The
ratio of recycled/new CO.sub.2 for injection, and therefore the
amount of CO.sub.2 stored in the reservoir, can range from 0 to
abut 3 depending on the parameters specified above as well as the
life of the well. In certain embodiments, the average rate can be
such that approximately 50% by mass of the injected CO.sub.2 is
recycled and, therefore, approximately 50% by mass of the injected
CO.sub.2 can be sequestered in the reservoir, displacing the fossil
fuels coming up to the surface.
[0179] Many modifications and other embodiments of the invention
will come to mind to one skilled in the art to which this invention
pertains having the benefit of the teachings presented in the
foregoing descriptions and associated drawings. Therefore, it is to
be understood that the invention is not to be limited to the
specific embodiments disclosed and that modifications and other
embodiments are intended to be included within the scope of the
appended claims. Although specific terms are employed herein, they
are used in a generic and descriptive sense only and not for
purposes of limitation.
* * * * *