U.S. patent application number 11/864011 was filed with the patent office on 2008-04-03 for method of heating hydrocarbons.
This patent application is currently assigned to OSUM OIL SANDS CORP.. Invention is credited to Dana Brock, Frank Wegner Donnelly, Michael H. Kobler, Andrew Squires, John D. Watson.
Application Number | 20080078552 11/864011 |
Document ID | / |
Family ID | 39260000 |
Filed Date | 2008-04-03 |
United States Patent
Application |
20080078552 |
Kind Code |
A1 |
Donnelly; Frank Wegner ; et
al. |
April 3, 2008 |
METHOD OF HEATING HYDROCARBONS
Abstract
The present invention relates generally to a method and means of
injecting hot fluids into a hydrocarbon formation using a
combustion and steam generating device installed at or near the
well-head of an injector well. The various embodiments are directed
generally to substantially increasing energy efficiency of thermal
recovery operations by efficiently utilizing the energy of the
combustion products and waste heat from the generator. The
generator apparatuses can be installed at the well-head which, in
turn, can be located close to the producing formation. The
combustion products may be injected into a well along with steam or
sequestered at another location.
Inventors: |
Donnelly; Frank Wegner;
(North Vancouver, CA) ; Kobler; Michael H.;
(Sebastopol, CA) ; Watson; John D.; (Evergreen,
CO) ; Brock; Dana; (Sebastopol, CA) ; Squires;
Andrew; (Calgary, CA) |
Correspondence
Address: |
SHERIDAN ROSS PC
1560 BROADWAY
SUITE 1200
DENVER
CO
80202
US
|
Assignee: |
OSUM OIL SANDS CORP.
Suite 300, 1204 Kensington Road NW
Calgary
CA
T2N 3P5
|
Family ID: |
39260000 |
Appl. No.: |
11/864011 |
Filed: |
September 28, 2007 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60827608 |
Sep 29, 2006 |
|
|
|
Current U.S.
Class: |
166/303 ;
166/57 |
Current CPC
Class: |
Y02C 20/40 20200801;
E21B 43/24 20130101; Y02C 10/14 20130101; E21B 41/0064
20130101 |
Class at
Publication: |
166/303 ;
166/057 |
International
Class: |
E21B 43/24 20060101
E21B043/24 |
Claims
1. A method for recovering a hydrocarbon from an underground
hydrocarbon-containing material, comprising: (a) in a manned
excavation positioned in proximity to the hydrocarbon-containing
material, generating a heated hydrocarbon production fluid; (b)
introducing, via a wellhead positioned in the manned excavation,
the heated hydrocarbon production fluid into the
hydrocarbon-containing material to mobilize at least part of the
hydrocarbons in the hydrocarbon-containing material; and (c)
thereafter recovering the mobilized hydrocarbon from the
hydrocarbon-containing material.
2. The method of claim 1, wherein the heated hydrocarbon production
fluid is steam, wherein the wellhead is positioned adjacent to a
liner of the manned excavation, wherein an injection well passes
from the wellhead, through the liner, and into the
hydrocarbon-containing material, and wherein the generating step
(a) is performed by a steam generating device positioned in the
manned excavation.
3. The method of claim 2, wherein waste heat from the steam
generating device is used to preheat at least a portion of input
water to the device.
4. The method of claim 2, wherein an exhaust gas of the steam
generating device is combined with the production fluid and
introduced into the hydrocarbon-containing material in step
(b).
5. The method of claim 2, wherein the steam generating device is
positioned at a distance of no more than about 20 meters from the
wellhead and a distance of no more than about 200 meters from the
hydrocarbon-containing material; wherein the manned excavation
comprises multiple wellheads and steam generating devices, wherein
each wellhead is in communication with a respective steam
generating device, and wherein the steam generating device performs
at least one of steam stimulation and flooding.
6. The method of claim 1, wherein the wellhead comprises a
controllable wellhead apparatus, the apparatus comprising a first
input for the heated hydrocarbon production fluid, a second input
for heated gaseous exhaust products, a third input for water, and a
manifold in communication with the first, second, and third inputs
to introduce, in step (b), a mixture of the heated hydrocarbon
production fluid, heated gaseous exhaust products, and water into
the hydrocarbon-containing material.
7. The method of claim 1, wherein the generating step is performed
by a generating device, wherein the generating device comprises a
diesel engine, a compressor, and a drive shaft extending
therebetween to enable the diesel engine to drive the compressor,
wherein an exhaust gas from the engine is routed to the compressor
to be incorporated into the heated hydrocarbon production fluid,
and wherein a heat exchanger is in thermal communication with the
engine to heat water, using waste heat from the engine, for
introduction into the hydrocarbon-containing material.
8. The method of claim 8, wherein the generating device comprises a
further heat exchanger in communication with the compressor and the
water to transfer heat from the compressor to the water.
9. The method of claim 1, wherein the generating step is performed
by a generating device is a liquid propellant motor having one or
more pistons being configured to compress water or steam for
introduction into the hydrocarbon-containing material.
10. A hydrocarbon production system, comprising: (a) a manned
excavation positioned in proximity to a hydrocarbon-containing
material; (b) a generating device, positioned in the manned
excavation, operable to generate a heated hydrocarbon production
fluid; (c) an injection well comprising a wellhead, the wellhead
being positioned in the manned excavation and the injection well
extending from the manned excavation, the injection well being
operable to introduce the heated hydrocarbon production fluid into
the hydrocarbon-containing material to mobilize at least part of
the hydrocarbons in the hydrocarbon-containing material; and (c) a
collector well operable to recover the mobilized hydrocarbon from
the hydrocarbon-containing material.
11. The system of claim 10, wherein the heated hydrocarbon
production fluid is steam, wherein the wellhead is positioned
adjacent to a liner of the manned excavation, wherein the injection
well passes from the wellhead, through the liner, and into the
hydrocarbon-containing material, wherein the heated hydrocarbon
production fluid is primarily steam, and wherein the manned
excavation comprises multiple wellheads and steam generating
devices, wherein each wellhead is in communication with a
respective steam generating device, and wherein the steam
generating device performs at least one of steam stimulation and
flooding.
12. The system of claim 11, wherein waste heat from the steam
generating device is used to preheat at least a portion of input
water to the device, wherein an exhaust gas of the steam generating
device is combined with the production fluid and introduced into
the hydrocarbon-containing material, and wherein the steam
generating device is positioned at a distance of no more than about
20 meters from the wellhead and a distance of no more than about
200 meters from the hydrocarbon-containing material.
13. The system of claim 10, wherein the wellhead comprises a
controllable wellhead apparatus, the apparatus comprising a first
input for the heated hydrocarbon production fluid, a second input
for heated gaseous exhaust products, a third input for water, and a
manifold in communication with the first, second, and third inputs
to introduce, simultaneously, a mixture of the heated hydrocarbon
production fluid, heated gaseous exhaust products, and water into
the injection well.
14. The system of claim 10, wherein the generating device comprises
a diesel engine, a compressor, and a drive shaft extending
therebetween to enable the diesel engine to drive the compressor,
wherein an exhaust gas from the engine is routed to the compressor
to be incorporated into the heated hydrocarbon production fluid,
and wherein a heat exchanger is in thermal communication with the
engine to heat water, using waste heat from the engine, for
introduction into the hydrocarbon-containing material.
15. The system of claim 14, wherein the generating device comprises
a further heat exchanger in communication with the compressor and
the water to transfer heat from the compressor to the water.
16. The system of claim 10, wherein the generating device is a
liquid propellant motor having one or more pistons being configured
to compress water or steam for introduction into the
hydrocarbon-containing material.
17. A hydrocarbon production system, comprising: (a) a diesel
engine; (b) a compressor; (c) a drive shaft interconnecting the
diesel engine to the compressor; and (d) a conduit transporting an
exhaust gas of the diesel engine to the compressor for injection,
by an injection well, into a hydrocarbon-containing material to
mobilize the hydrocarbons.
18. The system of claim 17, further comprising a heat exchanger is
in thermal communication with the engine to heat water, using waste
heat from the engine, for introduction into the
hydrocarbon-containing material.
19. The system of claim 17, wherein the generating device comprises
a heat exchanger in communication with the compressor and the water
to transfer heat from the compressor to the water and wherein the
heated water is introduced into the hydrocarbon-containing
material.
20. A hydrocarbon production method, comprising: (a) operating a
diesel engine to produce an exhaust gas comprising carbon oxides
and a rotating drive shaft; (b) operating a compressor, by the
rotating drive shaft, to form a compressed gas, the compressed gas
comprising at least part of the exhaust gas from the diesel engine;
and (c) introducing the compressed gas into a
hydrocarbon-containing material to mobilize the hydrocarbons for
production.
21. The method of claim 20, wherein a heat exchanger is in thermal
communication with the engine to transfer heat from the engine to
the water for introduction of the heated water into the
hydrocarbon-containing material.
22. The method of claim 20, wherein a heat exchanger is in thermal
communication with the compressor and the water to transfer heat
from the compressor to the water for introduction of the heated
water into the hydrocarbon-containing material.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] The present application claims the benefits, under 35 U.S.C.
.sctn.119(e), of U.S. Provisional Application Ser. No. 60/827,608
filed Sep. 29, 2006, entitled "Method of Heating Hydrocarbons" to
Brock, Donnelly, Kobler, Squires and Watson which is incorporated
herein by these references.
[0002] Cross reference is made to U.S. patent application Ser. No.
11/737,578 filed Apr. 19, 2006 entitled "Method of Drilling from a
Shaft" and U.S. patent application Ser. No. 11/441,929 filed May
25, 2006, entitled "Method for Underground Recovery of
Hydrocarbons", both of which are also incorporated herein by this
reference.
FIELD
[0003] The present invention relates generally to a method and
means of injecting hot fluids into a hydrocarbon formation using a
combustion and steam generating device installed at or near the
well-head of an injector well.
BACKGROUND
[0004] Oil is a nonrenewable natural resource having great
importance to the industrialized world. The increased demand for
and decreasing supplies of conventional oil has led to the
development of alternate sources of oil such as deposits of heavy
crude and bitumen and to a search for more efficient methods for
recovery from such hydrocarbon deposits.
[0005] Examples of efficient method for recovery methods of
unconventional oil deposits are the Steam Assisted Gravity Drain
("SAGD") process which uses steam as the fluid injected into the
hydrocarbon formation and the VAPEX process which uses a diluent as
the fluid injected into the hydrocarbon formation. In both methods,
horizontal well pairs are typically installed at the bottom of a
heavy oil or bitumen reservoir. A well pair is typically comprised
of a first well which may be a steam or diluent injector well and a
second well which may be a fluid collector well. The horizontal
portion of the injector well is commonly installed above the
producer well, separated by about 1 to about 5 meters. A mobilizing
fluid is introduced into the injector well and injected into the
heavy oil or bitumen formation where it is used to heat or dilute
the heavy oil or bitumen in order to mobilize (reduce its
viscosity) and allow the hydrocarbon to flow more readily (such as
the case for heavy crude) or flow at all (the case for bitumen
which is normally an in-situ solid).
[0006] When steam is used as the injected fluid, it is typically
generated in a large boiler on the surface and is typically
transmitted by an insulated piping system to a manifold feeding six
or eight near-by wells for injection into the formation. The
injected steam must travel from the surface down to a horizontal
section of the well in the hydrocarbon deposit where it is forced
by pressure into the formation through many narrow slits in the
horizontal portion of the well pipe.
[0007] The SAGD method has been applied to heavy oil and bitumen
recovery with varying degrees of success, both in terms of total
recovery factor and economics. A SAGD operation may be
characterized by its Steam-Oil-Ratio ("SOR") which is a measure of
how much steam is used to recover a barrel of heavy oil or bitumen
(the SOR is determined by the number of barrels of water required
to produce the steam divided by the number of barrels of oil or
bitumen recovered). Thus, an SOR of 3 means that 3 barrels of water
are required to be injected as steam to recover 1 barrel of oil or
bitumen). This ratio is often determined by geological factors
within the reservoir and therefore may be beyond the control of the
operator. Examples of these geological factors are clay, mudstone
or shale lenses that impede the migration of steam upwards and the
flow of mobilized oil downwards; or thief zones comprised of lenses
of formation waters. An acceptable SOR may be in the range of 2 to
3 whereas an uneconomical SOR is commonly 3 or higher. In addition
to good reservoir geology, a low SOR reflects good energy
efficiency in the use of steam. If steam could be generated and
delivered to the formation at significantly higher efficiencies
than is currently achieved, then SAGD operations characterized by
high average SOR would become more economically viable, even if the
geology of the reservoir remains non-optimal.
[0008] In current practice, steam is generated in a large boiler or
boilers located on the surface. Boilers powered by natural gas, for
example, have efficiencies in the range of about 75% to 90%. The
remainder of the energy consumed by the boiler is typically
scrubbed and released into the atmosphere as flue gases. These flue
gases not only add to local air pollution and greenhouse gases but
represent lost energy. The generated steam typically loses an
additional 10% to 20% of its energy as it is transmitted from the
boiler downhole to the horizontal section of the SAGD injectors.
For example, if a boiler is 80% efficient and there are an
additional 15% transmission losses, then only 68% of the fuel
energy consumed by the boiler is delivered into the formation in
the form of hot steam. Some of the remaining 32% of waste energy
may be used to generate electrical energy by any number of
co-generation methods.
[0009] Another technology proposed for recovery of hydrocarbons,
including heavy oil and bitumen, is based on mining for access to
the producing formation. For example, a system of underground
shafts and tunnels has been proposed to allow wells to be installed
from under or from within a reservoir. This approach overcomes a
number of problems such as surface access, product lifting
difficulties and reliability of downhole pumps. In these mining for
access technologies, the wellhead and its associated equipment is
readily accessible and is typically in close proximity to the
formation. Also, the wells are installed from the underground
workspace either horizontally or inclined upwards. A discussion of
these mining for access methods can be found in U.S. patent
application Ser. No. 11/737,578 filed Apr. 19, 2006 entitled
"Method of Drilling from a Shaft" and U.S. patent application Ser.
No. 11/441,929 filed May 25, 2006, entitled "Method for Underground
Recovery of Hydrocarbons".
[0010] Installing wells from an underground workspace opens up
possibilities for improving steam generation efficiencies. For
example, the steam boilers may be installed underground, shortening
the transmission distances and thereby reducing transmission
losses. The combustion products from these boilers may be captured
and injected into the producing formation or into an underground
sequestering repository if the geology is favorable.
[0011] Reference 1 ("Thermal Recovery of Oil and Bitumen" by Roger
M. Butler) describes several methods and devices for downhole
(located in the well itself) steam generation including devices
that inject their products of combustion into the formation along
with steam. If these devices are installed downhole near the
entrance to the horizontal injection section, then they are
difficult to service because they have to be withdrawn to the
surface or they can cause a production shut down if they fail while
in service. If these devices are installed on the surface at the
well-head, then they are subject to transmission losses in the
portion of the well connecting the surface to the underground
horizontal. Additionally, these devices are generally not be able
to generate sufficient power to produce the quantity and quality of
steam required for a stimulation of a SAGD well that may produce
several hundred barrels of oil per day.
[0012] There remains, therefore, a need for a method and system to:
(1) reduce or eliminate the energy losses from the process of
energizing and transmitting the injection fluids; (2) eliminating
greenhouse gas emissions; and (3) maintain the ability to rapidly
service or replace steam generation equipment without disrupting
well injection and production operations. There also remains a need
for large horsepower steam generators that can utilize untreated
water and utilize technology that can reduce capital costs of the
steam generating function.
SUMMARY
[0013] These and other needs are addressed by the present
inventions. The various inventions are directed generally to
substantially increasing energy efficiency of thermal recovery
operations by utilizing the energy of the combustion products while
simultaneously sequestering them underground.
[0014] In a first invention, a method for recovering a hydrocarbon
from an underground hydrocarbon-containing material is provided
that includes the steps:
[0015] (a) in a manned excavation positioned in proximity to the
hydrocarbon-containing material, generating a heated hydrocarbon
production fluid;
[0016] (b) introducing, via a wellhead positioned in the manned
excavation, the heated hydrocarbon production fluid into the
hydrocarbon-containing material to mobilize at least part of the
hydrocarbons in the hydrocarbon-containing material; and
[0017] (c) thereafter recovering the mobilized hydrocarbon from the
hydrocarbon-containing material.
[0018] In one configuration, each well-head has its own steam
generator, and the steam generator is capable of simulating a
substantial zone of the formation by steam stimulation and/or
flooding.
[0019] In one configuration, the heated hydrocarbon production
fluid is steam, the wellhead is positioned adjacent to a liner of
the manned excavation, an injection well passes from the wellhead,
through the liner, and into the hydrocarbon-containing material,
and the generating step (a) is performed by a steam generating
device positioned in the manned excavation.
[0020] Waste heat from the steam generating device can be used to
preheat at least a portion of input water to the device. In one
configuration, a heat exchanger is used to transfer heat from the
engine to pre-heat water prior to converting it to steam and
injecting it into the hydrocarbon-containing material. In one
configuration, a heat exchanger is used to transfer waste heat
energy from the compressor to the water prior to converting it to
steam and injecting it into the hydrocarbon-containing
material.
[0021] An exhaust gas of the steam generating device can be
combined with the production fluid and introduced into the
hydrocarbon-containing material in step (b).
[0022] The steam generating device is commonly positioned at a
distance of no more than about 20 meters from the wellhead and a
distance of no more than about 200 meters from the
hydrocarbon-containing material. In some applications, the manned
excavation is at least about 150 meters from the heated formation
to comply with safety regulations.
[0023] The wellhead can include a controllable wellhead apparatus.
The apparatus includes a first input for the heated hydrocarbon
production fluid, a second input for a heated gaseous exhaust
products, a third input for water, and a manifold in communication
with the first, second, and third inputs to introduce, in step (b),
a mixture of the heated hydrocarbon production fluid, heated
gaseous exhaust products carbon oxide, and water into the
hydrocarbon-containing material. Separate provisions may be made
for adding other gaseous products such as carbon dioxide and
additional water into the wellhead apparatus, for example for well
servicing.
[0024] In a second invention, a hydrocarbon production system is
provided that includes:
[0025] (a) a manned excavation positioned in proximity to a
hydrocarbon-containing material;
[0026] (b) a generating device, positioned in the manned
excavation, operable to generate a heated hydrocarbon production
fluid;
[0027] (c) an injection well comprising a wellhead, the wellhead
being positioned in the manned excavation and the injection well
extending from the manned excavation, the injection well being
operable to introduce the heated hydrocarbon production fluid into
the hydrocarbon-containing material to mobilize at least part of
the hydrocarbons in the hydrocarbon-containing material; and
[0028] (c) a collector well operable to recover the mobilized
hydrocarbon from the hydrocarbon-containing material.
[0029] The generating device can have many different
configurations. For example, the generator may be a robust burner
device, such as known in the art, that burns any of a number of
gaseous, liquid or solid fuels propellants and can work at
reasonably high injection pressures. In yet another configuration,
the generator may be a robust device that burns any of a number of
liquid propellants and can work at much higher injection pressures
than, for example a diesel engine, and therefore be applied to
formations at pressures as high as about 50,000 psi.
[0030] These gas and/or steam generators can be installed in or
near the wellhead. Their combustion products can be directed into
the injection well along with steam. The generators can utilize
essentially all the energy of combustion to heat the heavy oil or
bitumen deposit, thus converting almost all of the generated energy
into energy delivered into the formation. Further, the generators
can dispose of the combustion products by sequestering most or all
of them in the reservoir pore space from which heavy oil or bitumen
has been displaced and recovered by the collector wells. Even
further, the generators can eliminate a significant SAGD steam
generation problem. The generators can be substantially unaffected
by precipitation and scaling problems common to steam boilers and
steam transmission piping and thus can minimize or eliminate the
need for water treatment. The generators can be located very near
the horizontal section of injector well and readily serviced or
replaced while maintaining the well at pressure and temperature.
Servicing or replacing well-head components can be accomplished in
a very short time so that production is not interrupted and the
temperature in the injector well can be maintained at a level at
which the bitumen remains fluid in the injector well. The
generators can allow full control over injection fluid pressure and
temperatures, which is not possible with injection wells operated
from the surface. Finally, when the gas and/or steam generators is
located underground approximately at the level of the reservoir, it
can utilize a substantial pressure head for injection fluids stored
on the surface.
[0031] In a third invention, a hydrocarbon production system is
provided that includes:
[0032] (a) a diesel engine;
[0033] (b) a compressor;
[0034] (c) a drive shaft interconnecting the diesel engine to the
compressor; and
[0035] (d) a conduit transporting an exhaust gas of the diesel
engine to the compressor for injection, by an injection well, into
a hydrocarbon-containing material to mobilize the hydrocarbons.
[0036] A heat exchanger can be used to transfer heat from the
engine to pre-heat water prior to converting it to steam and
injecting it into the hydrocarbon-containing material.
[0037] In a fourth invention, a hydrocarbon production method
includes the steps:
[0038] (a) operating a diesel engine to produce an exhaust gas
comprising carbon oxides and a rotating drive shaft;
[0039] (b) operating a compressor, by the rotating drive shaft, to
form a compressed gas, the compressed gas comprising at least part
of the exhaust gas from the diesel engine; and
[0040] (c) introducing the compressed gas into a
hydrocarbon-containing material to mobilize the hydrocarbons for
production.
[0041] In one configuration, the generator is based on a diesel
engine where the load on the diesel engine is provided by the work
to maintain or compress its own exhaust combustion products to the
desired injection well pressure. In this configuration, heat
accumulated in the engine's cooling system is used, via a heat
exchanger apparatus, to transfer energy otherwise lost to heat
inlet water before injection into a well. A heat exchanger can also
be used to transfer waste heat energy from the compressor to the
water prior to converting it to steam and injecting it into the
hydrocarbon-containing material.
[0042] As can be seen from the above inventions, the well-head gas
and steam generators may be operated on a variety of fuels and
oxidizers. For example, the generator may be operated on a natural
gas/air combustion system; a diesel/air combustion system; a
gasoline/air combustion system; a heavy oil/diluent/air combustion
system; or a bitumen/diluent/air combustion system. Further, the
air used in combustion can be oxygen-enriched or replaced entirely
by oxygen to reduce or eliminate unwanted flue gas components,
especially nitrogen. The combustion system may use a gaseous fuel
system but preferably uses a liquid or solid fuel system when
operated underground.
[0043] Although the various inventions may be applied to surface
wellheads, in this configuration transmission energy losses remain,
and there remains the possibility of precipitation and scaling
problems in the non-horizontal portions of the well. In addition,
it can be more difficult to service the well casing in the event of
corrosion, precipitation, scaling and the like.
[0044] It is therefore preferable, though not necessary, to apply
the present invention to wellheads installed from an underground
workspace where the wellhead is typically within a few to several
meters of the reservoir.
[0045] Finally, the present invention allows the use of large
horsepower, high-efficiency boilers and engines to produce the
quantities and qualities of steam necessary to operate SAGD wells
capable of producing several hundred barrels of oil per day.
[0046] The following definitions are used herein:
[0047] It is to be noted that the term "a" or "an" entity refers to
one or more of that entity. As such, the terms "a" (or "an"), "one
or more" and "at least one" can be used interchangeably herein. It
is also to be noted that the terms "comprising", "including", and
"having" can be used interchangeably.
[0048] A blow out preventer or BOP is a large valve at the top of a
well that may be closed if the drilling crew loses control of
formation fluids. By closing this valve (usually operated remotely
via hydraulic actuators), the drilling crew usually regains control
of the reservoir, and procedures can then be initiated to increase
the mud density until it is possible to open the BOP and retain
pressure control of the formation. Some can effectively close over
an open wellbore, some are designed to seal around tubular
components in the well (drillpipe, casing or tubing) and others are
fitted with hardened steel shearing surfaces that can actually cut
through drillpipe.
[0049] A Christmas tree (also Subsea Tree or Surface Tree) in
petroleum and natural gas extraction, a christmas tree is an
assembly of valves, spools and fittings for an oil well, named for
its resemblance to a decorated tree. The function of a Christmas
tree is to both prevent the release of oil or gas from an oil well
into the environment and also to direct and control the flow of
formation fluids from the well. When the well is ready to produce
oil or gas, valves are opened and the release of the formation
fluids is allowed through a pipeline leading to a refinery, or to a
platform or to a storage vessel. It may also be used to control the
injection of gas or water injection application on a none-producing
well in order to sustain producer volumes. On producing wells
injection of chemicals or alcohols or oil distillates to solve
production problems (such as blockages) may be used.
[0050] A downhole steam generator as used herein is a steam
generator that is installed in the bore of a well.
[0051] A drilling room as used herein is any self-supporting space
that can be used to drill one or more wells through its floor,
walls or ceiling. The drilling room is typically sealed from
formation pressures and fluids.
[0052] A hydrocarbon is an organic compound that includes
primarily, if not exclusively, of the elements hydrogen and carbon.
Hydrocarbons generally fall into two classes, namely aliphatic, or
straight chain, hydrocarbons, cyclic, or closed ring, hydrocarbons,
and cyclic terpenes. Examples of hydrocarbon-containing materials
include any form of natural gas, oil, coal, and bitumen that can be
used as a fuel or upgraded into a fuel. Hydrocarbons are
principally derived from petroleum, coal, tar, and plant
sources.
[0053] Hydrocarbon production or extraction refers to any activity
associated with extracting hydrocarbons from a well or other
opening. Hydrocarbon production normally refers to any activity
conducted in or on the well after the well is completed.
Accordingly, hydrocarbon production or extraction includes not only
primary hydrocarbon extraction but also secondary and tertiary
production techniques, such as injection of gas or liquid for
increasing drive pressure, mobilizing the hydrocarbon or treating
by, for example chemicals or hydraulic fracturing the well bore to
promote increased flow, well servicing, well logging, and other
well and wellbore treatments.
[0054] A liner as defined for the present invention is any
artificial layer, membrane, or other type of structure installed
inside or applied to the inside of an excavation to provide at
least one of ground support, isolation from ground fluids (any
liquid or gas in the ground), and thermal protection. As used in
the present invention, a liner is typically installed to line a
shaft or a tunnel, either having a circular or elliptical
cross-section. Liners are commonly formed by pre-cast concrete
segments and less commonly by pouring or extruding concrete into a
form in which the concrete can solidify and attain the desired
mechanical strength.
[0055] A liner tool is generally any feature in a tunnel or shaft
liner that self-performs or facilitates the performance of work.
Examples of such tools include access ports, injection ports,
collection ports, attachment points (such as attachment flanges and
attachment rings), and the like.
[0056] A manned excavation refers to an excavation that is
accessible directly by personnel. The manned excavation can have
any orientation or set of orientations. For example, the manned
excavation can be an incline, decline, shaft, tunnel, stope, and
the like. A typical manned excavation has at least one dimension
normal to the excavation heading that is at least about 1.5
meters.
[0057] A mobilized hydrocarbon is a hydrocarbon that has been made
flowable by some means. For example, some heavy oils and bitumen
may be mobilized by heating them or mixing them with a diluent to
reduce their viscosities and allow them to flow under the
prevailing drive pressure. Most liquid hydrocarbons may be
mobilized by increasing the drive pressure on them, for example by
water or gas floods, so that they can overcome interfacial and/or
surface tensions and begin to flow. Bitumen particles may be
mobilized by some hydraulic mining techniques using cold water.
[0058] Primary production or recovery is the first stage of
hydrocarbon production, in which natural reservoir energy, such as
gasdrive, waterdrive or gravity drainage, displaces hydrocarbons
from the reservoir, into the wellbore and up to surface. Production
using an artificial lift system, such as a rod pump, an electrical
submersible pump or a gas-lift installation is considered primary
recovery. Secondary production or recovery methods frequently
involve an artificial-lift system and/or reservoir injection for
pressure maintenance. The purpose of secondary recovery is to
maintain reservoir pressure and to displace hydrocarbons toward the
wellbore. Tertiary production or recovery is the third stage of
hydrocarbon production during which sophisticated techniques that
alter the original properties of the oil are used. Enhanced oil
recovery can begin after a secondary recovery process or at any
time during the productive life of an oil reservoir. Its purpose is
not only to restore formation pressure, but also to improve oil
displacement or fluid flow in the reservoir. The three major types
of enhanced oil recovery operations are chemical flooding, miscible
displacement and thermal recovery.
[0059] A seal is a device or substance used in a joint between two
apparatuses where the device or substance makes the joint
substantially impervious to or otherwise substantially inhibits,
over a selected time period, the passage through the joint of a
target material, e.g., a solid, liquid and/or gas. As used herein,
a seal may reduce the in-flow of a liquid or gas over a selected
period of time to an amount that can be readily controlled or is
otherwise deemed acceptable. For example, a seal between sections
of a tunnel may be sealed so as to (1) not allow large water
in-flows but may allow water seepage which can be controlled by
pumps and (2) not allow large gas in-flows but may allow small gas
leakages which can be controlled by a ventilation system.
[0060] A shaft is a long approximately vertical underground opening
commonly having a circular cross-section that is large enough for
personnel and/or large equipment. A shaft typically connects one
underground level with another underground level or the ground
surface.
[0061] Steam flooding as used herein means using steam to drive a
hydrocarbon through the producing formation to a production
well.
[0062] Steam stimulation as used herein means using steam to heat a
producing formation to mobilize the hydrocarbon in order to allow
the steam to drive a hydrocarbon through the producing formation to
a production well.
[0063] A tunnel is a long approximately horizontal underground
opening having a circular, elliptical or horseshoe-shaped
cross-section that is large enough for personnel and/or vehicles. A
tunnel typically connects one underground location with
another.
[0064] An underground workspace as used in the present invention is
any excavated opening that is effectively sealed from the formation
pressure and/or fluids and has a connection to at least one entry
point to the ground surface.
[0065] A well is a long underground opening commonly having a
circular cross-section that is typically not large enough for
personnel and/or vehicles and is commonly used to collect and
transport liquids, gases or slurries from a ground formation to an
accessible location and to inject liquids, gases or slurries into a
ground formation from an accessible location.
[0066] Well drilling is the activity of collaring and drilling a
well to a desired length or depth.
[0067] Well completion refers to any activity or operation that is
used to place the drilled well in condition for production. Well
completion, for example, includes the activities of open-hole well
logging, casing, cementing the casing, cased hole logging,
perforating the casing, measuring shut-in pressures and production
rates, gas or hydraulic fracturing and other well and well bore
treatments and any other commonly applied techniques to prepare a
well for production.
[0068] A wellhead consists of the pieces of equipment mounted at
the opening of the well to regulate and monitor the extraction of
hydrocarbons from the underground formation. It also prevents
leaking of oil or natural gas out of the well, and prevents
blowouts due to high pressure formations. Formations that are under
high pressure typically require wellheads that can withstand a
great deal of upward pressure from the escaping gases and liquids.
These wellheads must be able to withstand pressures of up to 20,000
psi (pounds per square inch). The wellhead consists of three
components: the casing head, the tubing head, and the `christmas
tree`. The casing head consists of heavy fittings that provide a
seal between the casing and the surface. The casing head also
serves to support the entire length of casing that is run all the
way down the well. This piece of equipment typically contains a
gripping mechanism that ensures a tight seal between the head and
the casing itself.
[0069] Wellhead control assembly as used in the present invention
joins the manned sections of the underground workspace with and
isolates the manned sections of the workspace from the well
installed in the formation. The wellhead control assembly can
perform functions including: allowing well drilling, and well
completion operations to be carried out under formation pressure;
controlling the flow of fluids into or out of the well, including
shutting off the flow; effecting a rapid shutdown of fluid flows
commonly known as blow out prevention; and controlling hydrocarbon
production operations.
[0070] It is to be understood that a reference to oil herein is
intended to include low API hydrocarbons such as bitumen (API less
than .about.10.degree.) and heavy crude oils (API from
.about.10.degree. to .about.20.degree.) as well as higher API
hydrocarbons such as medium crude oils (API from .about.20.degree.
to .about.35.degree.) and light crude oils (API higher than
.about.35.degree.).
[0071] As used herein, "at least one", "one or more", and "and/or"
are open-ended expressions that are both conjunctive and
disjunctive in operation. For example, each of the expressions "at
least one of A, B and C", "at least one of A, B, or C", "one or
more of A, B, and C", "one or more of A, B, or C" and "A, B, and/or
C" means A alone, B alone, C alone, A and B together, A and C
together, B and C together, or A, B and C together.
BRIEF DESCRIPTION OF THE DRAWINGS
[0072] FIGS. 1A and B are schematics of generic steam
generators.
[0073] FIG. 2 is a schematic of an underground placement of a steam
generator apparatus.
[0074] FIG. 3 is a schematic of an alternate underground placement
of a steam generator apparatus.
[0075] FIG. 4 is a schematic of a controllable injector well-head
apparatus.
[0076] FIG. 5 is a schematic of a steam generator based on a diesel
engine.
[0077] FIG. 6 is a schematic of an alternate configuration of a
steam generator based on a diesel engine.
[0078] FIG. 7 is a schematic of a steam generator based on a liquid
propellant injector system.
[0079] FIG. 8 illustrates a method of pressurizing injection fluids
when operating underground.
DETAILED DESCRIPTION
[0080] The well-head gas and steam generator apparatus of the
present invention may be operated on a variety of fuels and
oxidizers. For example, the generator may be operated on a natural
gas/air combustion system; a diesel/air combustion system; a
gasoline/air combustion system; a heavy oil/diluent/air combustion
system; or a bitumen/diluent/air combustion system. Further, the
air used in combustion can be oxygen enriched or replaced entirely
by oxygen to reduce or eliminate unwanted flue gas components,
especially nitrogen. The combustion system preferably uses a liquid
or solid fuel system when operated underground.
[0081] In one configuration, the generator is based on a diesel
engine where the load on the diesel engine is provided by the work
to maintain or compress its own exhaust combustion products to the
desired injection well pressure. In this configuration, heat
accumulated in the engine's cooling system is used, via a heat
exchanger apparatus, to transfer energy otherwise lost to heat
inlet water before injection into a well.
[0082] In another configuration, the generator may be a robust
burner device, such as known in the art, that burns any of a number
of gaseous, liquid or solid fuels propellants and can work at
reasonably high injection pressures.
[0083] In yet another configuration, the generator may be a robust
device that burns any of a number of liquid propellants and can
work at much higher injection pressures than, for example a diesel
engine, and therefore be applied to formations at pressures as high
as about 50,000 psi.
[0084] The present invention may be applied to surface wellheads
but in this configuration, transmission energy losses remain and
there remains the possibility of precipitation and scaling problems
in the non-horizontal portions of the well. In addition, it is more
difficult to service the well casing in the event of corrosion,
precipitation, scaling and the like.
[0085] It is therefore preferable to apply the present invention to
wellheads installed from an underground workspace where the
wellhead is typically within a few to several meters of the
reservoir.
[0086] Finally, the present invention allows the use of large
horsepower, high-efficiency engines to produce the quantities and
qualities of steam necessary to operate SAGD wells capable of
producing several hundred barrels of oil per day.
[0087] As described in "Thermal Recovery of Oil and Bitumen", Roger
M. Butler, ISBN 0-9682563-0-9, 2.sup.nd Printing by GravDrain, Inc.
Calgary, Alberta 1998, there has been a significant effort to
develop downhole steam generators for oil field steam generation.
One of the main advantages seen for this approach is the reduction
of well-bore heat losses and, because of this, improved economics
for production in very deep deposits.
[0088] There are two basic approaches: [0089] 1. Low-pressure
combustion, in which the downhole combustion is carried out at
relatively low pressure and in which the flue gas products are
vented up the injection well. This approach requires a heat
exchanger down the well to isolate the low-pressure combustion zone
from the high-pressure steam. [0090] 2. High-pressure combustion,
in which the products of combustion are mixed directly with the
steam and pass into the reservoir to be collected at the production
or collector wells.
[0091] An important possible variation of the second approach
involves the use of oxygen-enriched air or primarily oxygen rather
than air for the combustion. This also has the potential advantage
that the resulting high concentration of carbon dioxide may improve
the effect of the steam in recovering oil.
[0092] A major advantage seen for the use of downhole steam
generators with the direct injection of the flue gas into the
reservoir is that the sulphur and nitrogen oxides can be absorbed
in the reservoir, either as anions in the water or by the rocks
directly and flue gas scrubbing is avoided. An example is a
high-pressure downhole steam generator developed by Sandia National
Laboratories in the DOE "Deep Steam" project (1982). Another
example is a high-pressure downhole generator developed by the
Chemical Oil Recovery Co. (1982). The Zimpro-AEC steam generator is
yet another device in which steam mixed with flue gas is produced
for injection into a reservoir. Up until now, downhole steam
generation has not advanced to the point where it is accepted as a
commercial alternative. The equipment that has evolved is
complicated and not easily serviceable. Although the use of
downhole steam generators may become practical for steam flooding,
it is unlikely to be so for steam stimulation, where the
requirement for large quantities of steam cannot be met. Steam
stimulation typically requires steam generators of several hundreds
to several thousands of horsepower per producing well.
[0093] This prior art shows however, that the concept of a downhole
steam generator that also injects its combustion products can have
significant operational and environmental advantages. However, as
noted, they have proved impractical because they must be large to
provide the quantities of steam for a typical SAGD well and they
would most likely have to be installed on the surface near the
wellhead where they would be subject to energy transmission losses
before the steam is delivered to the horizontal portion of the well
where the steam is to be injected.
[0094] Consider an example of a SAGD operation where a typical
producer well yields 500 barrels of oil per day at Steam-Oil-Ratio
("SOR") of 3 and where the steam is injected at a temperature of
200 C. If the water must be heated from room temperature, a surface
boiler operating at 85% efficiency with energy transmission losses
of 15% to get to the horizontal portion of the injector well have
to generate 34.3 million BTUs per hour. If 500 barrels per day of
heavy crude are produced, then the energy content of the produced
oil is 135.1 million BTUs per hour. This means that 25% of the
recovered energy in the heavy crude (or its equivalent of another
boiler fuel) must be consumed to produce the next barrel of heavy
crude.
[0095] If a steam generator is located at the entrance to the
horizontal portion of the injector well and all the generator's
produced energy including its flue gases are injected into the
formation, then the generator, assuming 95% overall energy
efficiency, will have to generate 26.1 million BTUs per hour. This
means that 19% of the recovered energy in the heavy crude (or its
equivalent of another generator fuel) must be consumed to produce
the next barrel of heavy crude.
[0096] Thus a generator located near the horizontal portion of the
injector well and injecting all its flue gases into the reservoir
saves on the order of 25% of the energy required by a surface
boiler and does not release flue gases into the atmosphere.
[0097] Although the present invention, which also seeks to increase
energy efficiency and sequester flue gases into the formation, can
be applied at the surface, it is preferable to apply it to wells
installed from a shaft or tunnel in or near the producing
formation. In this case, the underground workspace can be utilized
to accommodate generators large enough to sustain production rates
in the range of 100 to 1,000 barrels per producer well per day.
[0098] FIGS. 1A and B are schematics of two types of generic steam
generators such as might be located underground for producing steam
for injection into an injector well. FIG. 1A illustrates an
electrically-powered steam generator 101. Electrical energy 102 is
input as the energy source and water 104 is input as the mass
source. The generator outputs steam 107 and possibly some water
108. In addition, some waste heat energy is produced in the steam
generator much of which can be captured using a heat exchanger to
preheat all or a portion of the input water 104. Typically an
electrically powered steam generator is in the range of 80% to
about 90% efficient at converting electrical energy to energy of
steam for injection into an injector well. With a heat exchanger to
preheat the input water, it is possible to convert over about 95%
of the input electrical energy to energy of steam for injection
into an injector well. At such high energy conversion efficiencies
the amount of output water 108 is essentially zero. The input
electrical energy 102 may be obtained, for example, from an
external electric generating source such as an on-site surface
generator facility or distant power generating plant.
[0099] FIG. 1B illustrates a prime-power steam generator 111 which
uses a fuel 112 and oxidant 113 to generate power. Water 114 is
input separately from the fuel 112 and oxidant 113 so the mass
inputs are water, fuel and oxidant. The generator outputs exhaust
gases 116, steam 117 and possibly some water 118. In addition,
waste heat energy is generated in the steam generator much of which
can be captured using a heat exchanger to preheat all or a portion
of the input water 114. Typically a prime power steam generator can
convert about 25% to 45% of the total energy the energy of
combusted fuel into mechanical energy (typically rotating shaft
energy), approximately 25% to 30% to energy of exhaust gases and
the remainder to waste heat produced mainly in the generator
cooling system. If the exhaust gases 116 are combined with the
produced steam 117 and water 118, and if the waste heat energy
produced in the generator cooling system is captured using a heat
exchanger to preheat all or a portion of the input water 114, then
about 90% to about 95% of the energy of combusted fuel can be
captured and made available for injecting energized steam and other
gases into an injector well.
[0100] Examples of low cost fuel/oxidant combinations are: diesel
fuel/air; diesel fuel/oxygen; methane/air; methane/oxygen; various
emulsion fuels/air; various emulsion fuels/oxygen; JP4/red fuming
nitric acid; and the like.
[0101] A principal objective of the present invention is to locate
a steam generator in close proximity to an injector well-head and
to produce steam at high levels of conversion efficiency. If
exhaust gases, waste energy and some water are captured and
controlled, they can be injected along with the produced steam so
that the final injected mixture is an energetic gas in the desired
temperature and pressure range and with a mixture of gaseous
constituents compatible with the reservoir geology. Examples of
well-head generators will be provided (FIGS. 5, 6 and 7) for
controlling a high efficiency steam generator so that pressure,
temperature, mass and gas constituents can be tailored to
conditions required for thermal recovery in a heavy hydrocarbon
reservoir.
[0102] FIG. 2 is a plan view schematic of an example of a one of a
number of possible placements for the downhole combustion apparatus
of the present invention. The interior workspace of a tunnel or
shaft is shown enclosed, for example, by concrete walls 201 and an
alcove formed by walls 202. A wellhead apparatus 212, sometimes
known as a christmas tree, modified for the present invention, is
shown secured to the alcove wall 202 by a flange 211. The alcove
wall 202 is formed and sealed into the shaft or tunnel liner. A
method of installing such recesses under formation pressure is
fully described in U.S. patent application Ser. No. 11/737,578
filed Apr. 19, 2006 entitled "Method of Drilling from a Shaft". The
height and widths of the recesses 202 are in the range of about 2
meter to about 5 meters. The lengths of the recesses 202 are in the
range of about 4 meters to about 10 meters. Once installed, the
recesses 202 serve as the working space for installing, operating
and servicing the well-head equipment. In the present invention,
this wellhead apparatus 212 is adapted for use with an injector
well where water, flue gases and other gases may be injected into a
well. The equipment such as valves 213 can be utilized to help
control the injection process as well as shut down the well so that
the downhole steam and flue gas generator can be serviced or
replaced. This process of well-head control is described more fully
in FIG. 4. In the configuration shown in FIG. 2, a generator 221 is
shown positioned in the tunnel or shaft with its steam, flue gas
and water outlets (conduits 225, 227 and 227) connected to a
manifold 231 which is, in turn, attached to the well-head apparatus
212 and controlled by valves as described in FIG. 4. The generator
221 consumes fuel and all the mechanical and exhaust energy
produced by the generator 221 is injected through manifold 231. In
addition, supplementary water may be injected through conduit 234
and optional gases (CO.sub.2 for example) may be injected through
conduit 235. The steam, water and other gases from the generator
are mixed in a manifold 231 which is, in turn, attached to the
well-head apparatus 212 and controlled by valves. The steam, water
and other gases from the generator may be mixed in any combination
and then injected into the formation (reservoir rock) via injector
well 205. It is appreciated that the supplementary water in conduit
234 may routed to the generator 221 and used as coolant for the
generator 221 so that the injected water is at a higher temperature
when injected ultimately injected into well 205. If the water is
used as a coolant for the generator 221 then it is preferable that
the cooling system for generator 221 is operable with untreated
water. In the event that the generator has to be serviced or
replaced, then well 205 can be shut in at approximately normal
operating pressure and temperature by a method further described in
FIG. 4.
[0103] FIG. 3 is similar to FIG. 2 except that the generator 321 is
placed in an alcove 303 and thus will be out of the general
traffic, ventilation ducts and utility conduits in the tunnel or
shaft. The generator 331 is shown with its steam, flue gas and
water outlets (conduits 325, 327 and 327) connected to a manifold
331 which is, in turn, attached to the well-head apparatus 312 and
controlled by valves as described in FIG. 4. Conduits 325, 327 and
327 are preferably connected to the well-head apparatus 312 through
a hole or holes drilled between alcove 303 and the well-head recess
302.
[0104] FIG. 4 is a schematic of a controllable injector well-head
apparatus and illustrates an example of how an injector well can be
controlled, serviced or its steam generator replaced while
maintaining the injector well at operating pressure and
temperature. The rate of injection of steam and, in some cases, hot
combustion products, from a steam generator is controlled by the
fuel/air input to the steam generator. The output of the steam
generator may include steam, some water and some combustion
products which are fed via conduits 401 to manifold 407. In the
example of FIG. 4, the manifold is shown injecting steam and other
gases via valve 424 and residual water by valve 425. The flow of
supplementary water and optional gases in conduits 402 can also be
controlled from their respective underground or surface storage
sources by valves. For example, supplementary water is injected
into well 404 via valve 423 and optional gases, such as for example
CO.sub.2, injected into well 404 via valve 424. The injector well
can be shut-in by closing valve 421 and shutting of the generator
and flow of combustion products by closing valves 424 and 425, and
shutting of the flow of optional supplementary water and optional
gases by closing valves 423 and 426. The upper master valve 422 and
lower master valve 421 can also be shut, thus fully and safely
shutting in the well. Once this is accomplished, the generator can
be serviced or replaced. If necessary, scale and precipitates can
be removed from the well-head apparatus, at least down to master
valve 422 or 421.
[0105] FIG. 5 is a schematic of a steam/gas generator based on a
diesel engine. The apparatus is designed to utilize all of the fuel
energy consumed by the engine and inject all its produced energy
and exhaust gases into a well along with water to create high
pressure, high temperature steam that can be used to heat and
mobilize heavy oil or bitumen in a reservoir. Typically, about 40%
to about 45% of the fuel energy supplied to a diesel is transformed
into mechanical shaft energy; about 30% appears as energy of
exhaust products and the remainder as heat energy in the cooling
system of the engine (these percentages vary somewhat with the type
of fuel used in the diesel).
[0106] In this concept, a diesel engine 508 is shown driving a
compressor 502 via drive shaft 506. The diesel 508 is powered by a
fuel supply 516 and oxidant supply 515. The fuel may be diesel
fuel, natural gas or another fuel, for example, made from a
bitumen, heavy oil or bio-feedstock. The oxidant may be air, oxygen
only or oxygen-enriched air. The choice of fuel and oxidant changes
the mechanical efficiency and mix of exhaust products of the engine
and so allows some control over the composition of injected gases.
In the present invention, the exhaust 509 from the diesel is routed
to the compressor 502 via conduit 504. The compressor 502
compresses the exhaust 505 and injects the compressed hot exhaust
gases 522 into a well 501 via conduit 503. Treated or untreated
water 517 is fed through a heat exchanger 518 where it becomes
heated from hot water in a closed cooling system 510 of the engine
508. This heated water is injected 521 into the well 501 via
conduit 507. Thus, almost all the energy from combustion of the
fuel 516/oxidant 515 mixture is injected into the well 501 where it
is mixed with the injected steam and water.
[0107] When the well-head steam generator is a diesel engine that
is modified to inject its own combustion gases into the injector
well, then an approximately 4,100 horsepower engine would be
required to maintain a production or collector well of 500 barrels
per day, where the Steam-Oil-Ratio is about 3. This well-head
system would require approximately 6.1 gallons of diesel fuel per
minute and 10.4 gallons of water per minute. This size of system,
while more efficient than used in current practice, is much too
large to place downhole from a well installed from the surface. If
placed on the surface, it would lose about 15% of its energy in
transmission losses and so would have to be still larger to
compensate. So the preferable placement of such a generator would
be in an underground workspace in close proximity to a
well-head.
[0108] FIG. 6 is a schematic of an alternate configuration of a
steam/gas generator based on a diesel engine. This configuration is
similar to that of FIG. 5 except an additional heat exchanger 628
is added to a compressor 602 to moderate the temperature of the hot
compressed exhaust gases 605 from the engine 608 and to transfer
heat from the compressor 602 to additional treated or untreated
water 617. The water heated in compressor heat exchanger 628 is
added to the water heated in engine heat exchanger 608 at junction
619.
[0109] FIG. 7 is an example of liquid propellant gun technology
adapted to form a downhole water jet that can work against
extremely high back pressures. These back pressures can be in the
range of about 10,000 psi to about 50,000 psi. The liquid
propellant jet drill shown in FIG. 7 can be modified so that it
functions like the diesel engine shown in FIGS. 5 and 6. The
pistons are driven by combustion of a suitable liquid propellant in
chambers 65 and pressure water or steam in chambers 61 which is
then injected into an injector well. Although not shown, the
combustion products may be exhausted into the injector well to add
their energy to the process. The liquid propellant water jet drill
shown in FIG. 7 was taken from FIG. 5 of U.S. Pat. No.
3,620,313.
[0110] Another advantage of the present invention is illustrated in
FIG. 8. Since the present invention is preferably practiced
underground, water, for example, may be stored in a tank 803 on the
surface. The water can be sent underground via conduit 804 down
shaft 805 where it will arrive at the bottom of the shaft 805 with
a substantial pressure head. These shafts are typically in the
range of 100 meters to over 500 meters deep so this represents a
water pressure head in the range of about 140 psi to about 700 psi.
This pressurized water can be fed into an underground storage tank
807 and from there can be injected into a nearby injector well with
little or no additional pressurizing. This capability can also be
used for pressurizing liquid or gaseous fuels, if necessary, for a
selected generator.
[0111] A number of variations and modifications of the above
inventions can be used. As will be appreciated, it would be
possible to provide for some features of the invention without
providing others. For example, large prior-art gas burners can be
used. Other injectors based on, for example, a free piston engine
can also be modified and used to compress their own exhaust
products. In another variation, exhaust gases other than steam can
be routed and sequestered in geological repositories distant from
the producing reservoir. Before re-routing these gases, energy can
be extracted and transferred to heat a water supply using a heat
exchanger apparatus. The present invention, in various embodiments,
includes components, methods, processes, systems and/or apparatus
substantially as depicted and described herein, including various
embodiments, sub-combinations, and subsets thereof. Those of skill
in the art will understand how to make and use the present
invention after understanding the present disclosure. The present
invention, in various embodiments, includes providing devices and
processes in the absence of items not depicted and/or described
herein or in various embodiments hereof, including in the absence
of such items as may have been used in previous devices or
processes, for example for improving performance, achieving ease
and\or reducing cost of implementation.
[0112] The foregoing discussion of the invention has been presented
for purposes of illustration and description. The foregoing is not
intended to limit the invention to the form or forms disclosed
herein. In the foregoing Detailed Description for example, various
features of the invention are grouped together in one or more
embodiments for the purpose of streamlining the disclosure. This
method of disclosure is not to be interpreted as reflecting an
intention that the claimed invention requires more features than
are expressly recited in each claim. Rather, as the following
claims reflect, inventive aspects lie in less than all features of
a single foregoing disclosed embodiment. Thus, the following claims
are hereby incorporated into this Detailed Description, with each
claim standing on its own as a separate preferred embodiment of the
invention.
[0113] Moreover though the description of the invention has
included description of one or more embodiments and certain
variations and modifications, other variations and modifications
are within the scope of the invention, e.g., as may be within the
skill and knowledge of those in the art, after understanding the
present disclosure. It is intended to obtain rights which include
alternative embodiments to the extent permitted, including
alternate, interchangeable and/or equivalent structures, functions,
ranges or steps to those claimed, whether or not such alternate,
interchangeable and/or equivalent structures, functions, ranges or
steps are disclosed herein, and without intending to publicly
dedicate any patentable subject matter.
[0114] In one configuration, a heat exchanger is used to transfer
heat from the engine to pre-heat water prior to converting it to
steam and injecting it into the hydrocarbon-containing
material.
[0115] In one configuration, a used to transfer waste heat energy
from the compressor to the water prior to converting it to steam
and injecting it into the hydrocarbon-containing material.
* * * * *