Note: Descriptions are shown in the official language in which they were submitted.
CA 02642078 2007-09-27
1 METHOD OF HEATING HYDROCARBONS
2
3 FIELD OF THE INVENTION
4 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
6 installed at or near the well-head of an injector well.
7
8 BACKGROUND
9 Oil is a nonrenewable natural resource having great importance to the
industrialized world. The increased demand for and decreasing supplies of
11 conventional oil has led to the development of alternate sources of oil
such as deposits
12 of heavy crude and bitumen and to a search for more efficient methods for
recovery
13 from such hydrocarbon deposits.
14 Examples of efficient method for recovery methods of unconventional oil
deposits are the Steam Assisted Gravity Drain ("SAGD") process which uses
steam as
16 the fluid injected into the hydrocarbon formation and the VAPEX process
which uses a
17 diluent as the fluid injected into the hydrocarbon formation. In both
methods, horizontal
18 well pairs are typically installed at the bottom of a heavy oil or bitumen
reservoir. A well
19 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
21 injector well. is commonly installed above the producer well, separated by
about 1 to
22 about 5 meters. A mobilizing fluid is introduced into the injector well and
injected into
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1 the heavy oil or bitumen formation where it is used to heat or dilute the
heavy oil or
2 bitumen in order to mobilize (reduce its viscosity) and allow the
hydrocarbon to flow
3 more readily (such as the case for heavy crude) or flow at all (the case for
bitumen
4 which is normally an in-situ solid).
When steam is used as the injected fluid, it is typically generated in a large
6 boiler on the surface and is typically transmitted by an insulated piping
system to a
7 manifold feeding six or eight near-by wells for injection into the
formation. The injected
8 steam must travel from the surface down to a horizontal section of the well
in the
9 hydrocarbon deposit where it is forced by pressure into the formation
through many
narrow slits in the horizontal portion of the well pipe.
11 The SAGD method has been applied to heavy oil and bitumen recovery with
12 varying degrees of success, both in terms of total recovery factor and
economics. A
13 SAGD operation may be characterized by its Steam-Oil-Ratio ("SOR") which is
a
14 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
16 divided by the number of barrels of oil or bitumen recovered). Thus, an SOR
of 3
17 means that 3 barrels of water are required to be injected as steam to
recover 1 barrel
18 of oil or bitumen). This ratio is often determined by geological factors
within the
19 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
21 steam upwards and the flow of mobilized oil downwards; or thief zones
comprised of
22 lenses of formation waters. An acceptable SOR may be in the range of 2 to 3
whereas
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1 an uneconomical SOR is commonly 3 or higher. In addition to good reservoir
geology,
2 a low SOR reflects good energy efficiency in the use of steam. If steam
could be
3 generated and delivered to the formation at significantly higher
efficiencies than is
4 currently achieved, then SAGD operations characterized by high average SOR
would
become more economically viable, even if the geology of the reservoir remains
non-
6 optimal.
7 In current practice, steam is generated in a large boiler or boilers located
on the
8 surface. Boilers powered by natural gas, for example, have efficiencies in
the range of
9 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
11 add to local air pollution and greenhouse gases but represent lost energy.
The
12 generated steam typically loses an additional 10% to 20% of its energy as
it is
13 transmitted from the boiler downhole to the horizontal section of the SAGD
injectors.
14 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
16 formation in the form of hot steam. Some of the remaining 32% of waste
energy may
17 be used to generate electrical energy by any number of co-generation
methods.
18 Another technology proposed for recovery of hydrocarbons, including heavy
oil
19 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
21 installed from under or from within a reservoir. This approach overcomes a
number of
22 problems such as surface access, product lifting difficulties and
reliability of downhole
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1 pumps. In these mining for access technologies, the wellhead and its
associated
2 equipment is readily accessible and is typically in close proximity to the
formation.
3 Also, the wells are installed from the underground workspace either
horizontally or
4 inclined upwards. A discussion of these mining for access methods can be
found in
US Patent Application Serial No.11/737,578 filed April 19, 2006 entitled
"Method of
6 Drilling from a Shaft" and U.S. Patent Application Serial No. 11/441,929
filed May 25,
7 2006, entitled "Method for Underground Recovery of Hydrocarbons".
8 Installing wells from an underground workspace opens up possibilities for
9 improving steam generation efficiencies. For example, the steam boilers may
be
installed underground, shortening the transmission distances and thereby
reducing
11 transmission losses. The combustion products from these boilers may be
captured
12 and injected into the producing formation or into an underground
sequestering
13 repository if the geology is favorable.
14 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
16 generation including devices that inject their products of combustion into
the formation
17 along with steam. If these devices are installed downhole near the entrance
to the
18 horizontal injection section, then they are difficult to service because
they have to be
19 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
21 subject to transmission losses in the portion of the well connecting the
surface to the
22 underground horizontal. Additionally, these devices are generally not be
able to
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1 generate sufficient power to produce the quantity and quality of steam
required for a
2 stimulation of a SAGD well that may produce several hundred barrels of oil
per day.
3 There remains, therefore, a need for a method and system to: (1) reduce or
4 eliminate 'the energy losses from the process of energizing and transmitting
the
injection fluids; (2) eliminating greenhouse gas emissions; and (3) maintain
the ability
6 to rapidly service or replace steam generation equipment without disrupting
well
7 injection and production operations. There also remains a need for large
horsepower
8 steam generators that can utilize untreated water and utilize technology
that can
9 reduce capital costs of the steam generating function.
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1 SUMMARY OF THE INVENTION
2 These and other needs are addressed by the present inventions. The various
3 inventions are directed generally to substantially increasing energy
efficiency of thermal
4 recovery operations by utilizing the energy of the combustion products while
simultaneously sequestering them underground.
6 In a first invention, a method for recovering a hydrocarbon from an
underground
7 hydrocarbon-containing material is provided that includes the steps:
8 (a) in a manned excavation positioned in proximity to the hydrocarbon-
9 containing material, generating a heated hydrocarbon production fluid;
(b) introducing, via a wellhead positioned in the manned excavation, the
heated
11 hydrocarbon production fluid into the hydrocarbon-containing material to
mobilize at
12 least part of the hydrocarbons in the hydrocarbon-containing material; and
13 (c) thereafter recovering the mobilized hydrocarbon from the hydrocarbon-
14 containing material.
In one configuration, each well-head has its own steam generator, and the
16 steam generator is capable of simulating a substantial zone of the
formation by steam
17 stimulation and/or flooding.
18 In one configuration, the heated hydrocarbon production fluid is steam, the
19 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
21 material, and the generating step (a) is performed by a steam generating
device
22 positioned in the manned excavation.
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1 Waste heat from the steam generating device can be used to preheat at least
a
2 portion of input water to the device. In one configuration, a heat exchanger
is used to
3 transfer heat from the engine to pre-heat water prior to converting it to
steam and
4 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
6 to converting it to steam and injecting it into the hydrocarbon-containing
material.
7 An exhaust gas of the steam generating device can be combined with the
8 production fluid and introduced into the hydrocarbon-containing material in
step (b).
9 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
11 meters from the hydrocarbon-containing material. In some applications, the
manned
12 excavation is at ieast about 150 meters from the heated formation to comply
with safety
13 regulations.
14 The wellhead can include a controllable welihead apparatus. The apparatus
includes a first input for the heated hydrocarbon production fluid, a second
input for a
16 heated gaseous exhaust products, a third input for water, and a manifold in
17 communication with the first, second, and third inputs to introduce, in
step (b), a
18 mixture of the heated hydrocarbon production fluid, heated gaseous exhaust
products
19 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
21 water into the wellhead apparatus, for example for well servicing.
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1 In a second invention, a hydrocarbon production system is provided that
2 includes:
3 (a) a manned excavation positioned in proximity to a hydrocarbon-containing
4 material;
(b) a generating device, positioned in the manned excavation, operable to
6 generate a heated hydrocarbon production fluid;
7 (c) an injection well comprising a wellhead, the wellhead being positioned
in the
8 manned excavation and the injection well extending from the manned
excavation, the
9 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
11 hydrocarbon-containing material; and
12 (c) a collector well operable to recover the mobilized hydrocarbon from the
13 hydrocarbon-containing material.
14 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
16 of a number of gaseous, liquid or solid fuels propellants and can work at
reasonably
17 high injection pressures. In yet another configuration, the generator may
be a robust
18 device that burns any of a number of liquid propellants and can work at
much higher
19 injection pressures than, for example a diesel engine, and therefore be
applied to
formations at pressures as high as about 50,000 psi.
21 These gas and/or steam generators can be installed in or near the wellhead.
22 Their combustion products can be directed into the injection well along
with steam.
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1 The generators can utilize essentially all the energy of combustion to heat
the heavy oil
2 or bitumen deposit, thus converting almost all of the generated energy into
energy
3 delivered into the formation. Further, the generators can dispose of the
combustion
4 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
6 further, the generators can eliminate a significant SAGD steam generation
problem.
7 The generators can be substantially unaffected by precipitation and scaling
problems
8 common to steam boilers and steam transmission piping and thus can minimize
or
9 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
11 well at pressure and temperature. Servicing or replacing well-head
components can be
12 accomplished in a very short time so that production is not interrupted and
the
13 temperature in the injector well can be maintained at a level at which the
bitumen
14 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
16 from the surface. Finally, when the gas and/or steam generators is located
17 underground approximately at the level of the reservoir, it can utilize a
substantial
18 pressure head for injection fluids stored on the surface.
19 In a third invention, a hydrocarbon production system is provided that
includes:
(a) a diesel engine;
21 (b) a compressor;
22 (c) a drive shaft interconnecting the diesel engine to the compressor; and
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1 (d) a conduit transporting an exhaust gas of the diesel engine to the
compressor
2 for injection, by an injection well, into a hydrocarbon-containing material
to mobilize the
3 hydrocarbons.
4 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.
6 In a fourth invention, a hydrocarbon production method includes the steps:
7 (a) operating a diesel engine to produce an exhaust gas comprising carbon
8 oxides and a rotating drive shaft;
9 (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
11 engine; and
12 (c) introducing the compressed gas into a hydrocarbon-containing material
to
13 mobilize the hydrocarbons for production.
14 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
16 combustion products to the desired injection well pressure. In this
configuration, heat
17 accumulated in the engine's cooling system is used, via a heat exchanger
apparatus,
18 to transfer energy otherwise lost to heat inlet water before injection into
a well. A heat
19 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
21 material.
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I As can be seen from the above inventions, the well-head gas and steam
2 generators may be operated on a variety of fuels and oxidizers. For example,
the
3 generator may be operated on a natural gas/air combustion system; a
diesel/air
4 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
6 in combustion can be oxygen-enriched or replaced entirely by oxygen to
reduce or
7 eliminate unwanted flue gas components, especially nitrogen. The combustion
system
8 may use a gaseous fuel system but preferably uses a liquid or solid fuel
system when
9 operated underground.
Although the various inventions may be applied to surface wellheads, in this
11 configuration transmission energy losses remain, and there remains the
possibility of
12 precipitation and scaling problems in the non-horizontal portions of the
well. In
13 addition, it can be more difficult to service the well casing in the event
of corrosion,
14 precipitation, scaling and the like.
It is therefore preferable, though not necessary, to apply the present
invention to
16 wellheads installed from an underground workspace where the wellhead is
typically
17 within a few to several meters of the reservoir.
18 Finally, the present invention allows the use of large horsepower, high-
efficiency
19 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.
21 The following definitions are used herein:
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1 It is to be noted that the term "a" or "an" entity refers to one or more of
that
2 entity. As such, the terms "a" (or "an"), "one or moren and "at least one"
can be used
3 interchangeably herein. It is also to be noted that the terms "comprising",
"including",
4 and "having" can be used interchangeably.
A blow out preventer or BOP is a large valve at the top of a well that may be
6 closed if the drilling crew loses control of formation fluids. By closing
this valve (usually
7 operated remotely via hydraulic actuators), the drilling crew usually
regains control of
8 the reservoir, and procedures can then be initiated to increase the mud
density until it
9 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
11 components in the well (drillpipe, casing or tubing) and others are fitted
with hardened
12 steel shearing surfaces that can actually cut through drillpipe.
13 A christmas tree (also Subsea Tree or Surface Tree) in petroleum and
natural
14 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
16 to both prevent the release of oil or gas from an oil well into the
environment and also
17 to direct and control the flow of formation fluids from the well. When the
well is ready to
18 produce oil or gas, valves are opened and the release of the formation
fluids is allowed
19 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
21 none-producing well in order to sustain producer volumes. On producing
wells
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1 injection of chemicals or alcohols or oil distillates to solve production
problems (such as
2 blockages) may be used.
3 A downhole steam generator as used herein is a steam generator that is
4 installed in the bore of a well.
A drilling room as used herein is any self-supporting space that can be used
to
6 drill one or more wells through its floor, walls or ceiling. The drilling
room is typically
7 sealed from formation pressures and fluids.
8 A hydrocarbon is an organic compound that includes primarily, if not
exclusively,
9 of the elements hydrogen and carbon. Hydrocarbons generally fall into
two.classes,
namely aliphatic, or straight chain, hydrocarbons, cyclic, or closed ring,
hydrocarbons,
11 and cyclic terpenes. Examples of hydrocarbon-containing materials include
any form
12 of natural gas, oil, coal, and bitumen that can be used as a fuel or
upgraded into a fuel.
13 Hydrocarbons are principally derived from petroleum, coal, tar, and plant
sources.
14 Hydrocarbon production or extraction refers to any activity associated with
extracting hydrocarbons from a well or other opening. Hydrocarbon production
16 normally refers to any activity conducted in or on the well after the well
is completed.
17 Accordingly, hydrocarbon production or extraction includes not only primary
18 hydrocarbon extraction but also secondary and tertiary production
techniques, such as
19 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
21 increased flow, well servicing, well logging, and other well and wellbore
treatments.
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1 A liner as defined for the present invention is any artificial layer,
membrane, or
2 other type of structure installed inside or applied to the inside of an
excavation to
3 provide at least one of ground support, isolation from ground fluids (any
liquid or gas in
4 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-
6 section. Liners are commonly formed by pre-cast concrete segments and less
7 commonly by pouring or extruding concrete into a form in which the concrete
can
8 solidify and attain the desired mechanical strength.
9 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,
11 injection ports, collection ports, attachment points (such as attachment
flanges and
12 attachment rings), and the like.
13 A manned excavation refers to an excavation that is accessible directly by
14 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,
16 and the like. A typical manned excavation has at least one dimension normal
to the
17 excavation heading that is at least about 1.5 meters.
18 A mobilized hydrocarbon is a hydrocarbon that has been made flowable by
19 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
21 under the prevailing drive pressure. Most liquid hydrocarbons may be
mobilized by
22 increasing the drive pressure on them, for example by water or gas floods,
so that they
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1 can overcome interfacial and/or surface tensions and begin to flow. Bitumen
particles
2 may be mobilized by some hydraulic mining techniques using cold water.
3 Primary production or recovery is the first stage of hydrocarbon production,
in
4 which natural reservoir energy, such as gasdrive, waterdrive or gravity
drainage,
displaces hydrocarbons from the reservoir, into the wellbore and up to
surface.
6 Production using an artificial lift system, such as a rod pump, an
electrical submersible
7 pump or a gas-lift installation is considered primary recovery. Secondary
production or
8 recovery methods frequently involve an artificial-lift system and/or
reservoir injection for
9 pressure maintenance. The purpose of secondary recovery is to maintain
reservoir
pressure and to displace hydrocarbons toward the wellbore. Tertiary production
or
11 recovery is the third stage of hydrocarbon production during which
sophisticated
12 techniques that alter the original properties of the oil are used. Enhanced
oil recovery
13 can begin after a secondary recovery process or at any time during the
productive life
14 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
16 enhanced oil recovery operations are chemical flooding, miscible
displacement and
17 thermal recovery.
18 A seal is a device or substance used in a joint between two apparatuses
where
19 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
21 target material, e.g., a solid, liquid and/or gas. As used herein, a seal
may reduce the
22 in-flow of a liquid or gas over a selected period of time to an amount that
can be readily
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1 controlled or is otherwise deemed acceptable. For example, a seal between
sections
2 of a tunnel may be sealed so as to (1) not allow large water in-flows but
may allow
3 water seepage which can be controlled by pumps and (2) not allow large gas
in-flows
4 but may allow small gas leakages which can be controlled by a ventilation
system.
A shaft is a long approximately vertical underground opening commonly having
6 a circular cross-section that is large enough for personnel and/or large
equipment. A
7 shaft typically connects one underground level with another underground
level or the
8 ground surface.
9 Steam flooding as used herein means using steam to drive a hydrocarbon
through the producing formation to a production well.
11 Steam stimulation as used herein means using steam to heat a producing
12 formation to mobilize the hydrocarbon in order to allow the steam to drive
a
13 hydrocarbon through the producing formation to a production well.
14 A tunnel is a long approximately horizontal underground opening having a
circular, elliptical or horseshoe-shaped cross-section that is large enough
for personnel
16 and/or vehicles. A tunnel typically connects one underground location with
another.
17 An underground workspace as used in the present invention is any excavated
18 opening that is effectively sealed from the formation pressure and/or
fluids and has a
19 connection to at least one entry point to the ground surface.
A well is a long underground opening commonly having a circular cross-section
21 that is typically not large enough for personnel and/or vehicles and is
commonly used
22 to collect and transport liquids, gases or slurries from a ground formation
to an
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1 accessible location and to inject liquids, gases or slurries into a ground
formation from
2 an accessible location.
3 Well drilling is the activity of collaring and drilling a well to a desired
length or
4 depth.
Well completion refers to any activity or operation that is used to place the
drilled
6 well in condition for production. Well completion, for example, includes the
activities of
7 open-hole well logging, casing, cementing the casing, cased hole logging,
perforating
8 the casing, measuring shut-in pressures and production rates, gas or
hydraulic
9 fracturing and other well and well bore treatments and any other commonly
applied
techniques to prepare a well for production.
11 A wellhead consists of the pieces of equipment mounted at the opening of
the
12 well to regulate and monitor the extraction of hydrocarbons from the
underground
13 formation. It also prevents leaking of oil or natural gas out of the well,
and prevents
14 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
16 escaping gases and liquids. These wellheads must be able to withstand
pressures of
17 up to 20,000 psi (pounds per square inch). The wellhead consists of three
components:
18 the casing head, the tubing head, and the'christmas tree'. The casing head
consists
19 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
21 well. This piece of equipment typically contains a gripping mechanism that
ensures a
22 tight seal between the head and the casing itself..
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1 Wellhead control assembly as used in the present invention joins the manned
2 sections of the underground workspace with and isolates the manned sections
of the
3 workspace from the well installed in the formation. The wellhead control
assembly can
4 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,
6 including shutting off the flow; effecting a rapid shutdown of fluid flows
commonly
7 known as blow out prevention; and controlling hydrocarbon production
operations.
8 It is to be understood that a reference to oil herein is intended to include
low API
9 hydrocarbons such as bitumen (API less than -10) and heavy crude oils (API
from
-10' to -20 ) as well as higher API hydrocarbons such as medium crude oils
(API from
11 -20' to -35) and light crude oils (API higher than -35) .
12 As used herein, "at least one", "one or more", and "and/or" are open-ended
13 expressions that are both conjunctive and disjunctive in operation. For
example, each
14 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,
16 B alone, C alone, A and B together, A and C together, B and C together, or
A, B and C
17 together.
18
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1 BRIEF DESCRIPTION OF THE DRAWINGS
2 Figures 1A and B are schematics of generic steam generators.
3 Figure 2 is a schematic of an underground placement of a steam generator
4 apparatus.
Figure 3 is a schematic of an alternate underground placement of a steam
6 generator apparatus.
7 Figure 4 is a schematic of a controllable injector well-head apparatus.
8 Figure 5 is a schematic of a steam generator based on a diesel engine.
9 Figure 6 is a schematic of an alternate configuration of a steam generator
based
on a diesel engine.
11 Figure 7 is a schematic of a steam generator based on a liquid propellant
12 injector system.
13 Figure 8 illustrates a method of pressurizing injection fluids when
operating
14 underground.
DETAILED DESCRIPTION
16 The well-head gas and steam generator apparatus of the present invention
may
17 be operated on a variety of fuels and oxidizers. For example, the generator
may be
18 operated on a natural gas/air combustion system; a diesel/air combustion
system; a
19 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
21 oxygen enriched or replaced entirely by oxygen to reduce or eliminate
unwanted flue
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1 gas components, especially nitrogen. The combustion system preferably uses a
liquid
2 or solid fuel system when operated underground.
3 In one configuration, the generator is based on a diesel engine where the
load
4 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
6 accumulated in the engine's cooling system is used, via a heat exchanger
apparatus,
7 to transfer energy otherwise lost to heat inlet water before injection into
a well.
8 In another configuration, the generator may be a robust burner device, such
as
9 that 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.
11 In yet another configuration, the generator may be a robust device that
burns
12 any of a number of liquid propellants and can work at much higher injection
pressures
13 than, for example a diesel engine, and therefore be applied to formations
at pressures
14 as high as about 50,000 psi.
The present invention may be applied to surface wellheads but in this
16 configuration, transmission energy losses remain and there remains the
possibility of
17 precipitation and scaling problems in the non-horizontal portions of the
well. In
18 addition, it is more difficult to service the well casing in the event of
corrosion,
19 precipitation, scaling and the like.
It is therefore preferable to apply the present invention to wellheads
installed
21 from an underground workspace where the wellhead is typically within a few
to several
22 meters of the reservoir.
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CA 02642078 2007-09-27
1 Finally, the present invention allows the use of large horsepower, high-
efficiency
2 engines to produce the quantities and qualities of steam necessary to
operate SAGD
3 wells capable of producing several hundred barrels of oil per day.
4 As described in "Thermal Recovery of Oil and Bitumen", Roger M. Butler, ISBN
0-9682563-0-9, 2"d Printing by GravDrain, Inc. Calgary, Alberta 1998., there
has been a
6 significant effort to develop downhole steam generators for oil field steam
generation.
7 One of the main advantages seen for this approach is the reduction of well-
bore heat
8 losses and, because of this, improved economics for production in very deep
deposits.
9 There are two basic approaches:
1. Low-pressure combustion, in which the downhole combustion is carried out at
11 relatively low pressure and in which the flue gas products are vented up
the
12 injection well. This approach requires a heat exchanger down the well to
isolate
13 the low-pressure combustion zone from the high-pressure steam.
14 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
16 production or collector wells.
17 An important possible variation of the second approach involves the use of
18 oxygen-enriched air or primarily oxygen rather than air for the combustion.
This also
19 has the potential advantage that the resulting high concentration of carbon
dioxide may
improve the effect of the steam in recovering oil.
21 A major advantage seen for the use of downhole steam generators with the
22 direct injection of the flue gas into the reservoir is that the sulphur and
nitrogen oxides
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CA 02642078 2007-09-27
1 can be absorbed in the reservoir, either as anions in the water or by the
rocks directly
2 and flue gas scrubbing is avoided. An example is a high-pressure downhole
steam
3 generator developed by Sandia National Laboratories in the DOE "Deep Steam"
4 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
6 another device in which steam mixed with flue gas is produced for injection
into a
7 reservoir. Up until now, downhole steam generation has not advanced to the
point
8 where it is accepted as a commercial alternative. The equipment that has
evolved is
9 complicated and not easily serviceable. Although the use of downhole steam
generators may become practical for steamflooding, it is unlikely to be so for
steam
11 stimulation, where the requirement for large quantities of steam cannot be
met. Steam
12 stimulation typically requires steam generators of several hundreds to
several
13 thousands of horsepower per producing well.
14 This prior art shows however, that the concept of a downhole steam
generator
that also injects its combustion products can have significant operational and
16 environmental advantages. However, as noted, they have proved impractical
because
17 they must be large to provide the quantities of steam for a typical SAGD
well and they
18 would most likely have to be installed on the surface near the wellhead
where they
19 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.
21 Consider an example of a SAGD operation where a typical producer well
yields
22 500 barrels of oil per day at Steam-Oil-Ratio ("SOR") of 3 and where the
steam is
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CA 02642078 2007-09-27
1 injected at a temperature of 200 C. If the water must be heated from room
2 temperature, a surface boiler operating at 85% efficiency with energy
transmission
3 losses of 15% to get to the horizontal portion of the injector well have to
generate 34.3
4 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
6 25% of the recovered energy in the heavy crude (or its equivalent of another
boiler fuel)
7 must be consumed to produce the next barrel of heavy crude.
8 If a steam generator is located at the entrance to the horizontal portion of
the
9 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,
11 will have to generate 26.1 million BTUs per hour. This means that 19% of
the
12 recovered energy in the heavy crude (or its equivalent of another generator
fuel) must
13 be consumed to produce the next barrel of heavy crude.
14 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
16 required by a surface boiler and does not release flue gases into the
atmosphere.
17 Although the present invention, which also seeks to increase energy
efficiency
18 and sequester flue gases into the formation, can be applied at the surface,
it is
19 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
21 generators large enough to sustain production rates in the range of 100 to
1,000
22 barrels per producer well per day.
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CA 02642078 2007-09-27
1 Figures 1 A and B are schematics of two types of generic steam generators
such
2 as might be located underground for producing steam for injection into an
injector well.
3 Fig. 1A illustrates an electrically-powered steam generator 101. Electrical
energy 102
4 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
6 heat energy is produced in the steam generator much of which can be captured
using a
7 heat exchanger to preheat all or a portion of the input water 104. Typically
an
8 electrically powered steam generator is in the range of 80% to about 90%
efficient at
9 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
11 the input electrical energy to energy of steam for injection into an
injector well. At such
12 high energy conversion efficiencies the amount of output water 108 is
essentially zero.
13 The input electrical energy 102 may be obtained, for example, from an
external electric
14 generating source such as an on-site surface generator facility or distant
power
generating plant.
16 Fig. 1 B illustrates a prime-power steam generator 111 which uses a fuel
112
17 and oxidant 113 to generate power. Water 114 is input separately from the
fuel 112
18 and oxidant 113 so the mass inputs are water, fuel and oxidant. The
generator outputs
19 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
21 heat exchanger to preheat all or a portion of the input water 114.
Typically a prime
22 power steam generator can convert about 25% to 45% of the total energy the
energy of
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CA 02642078 2007-09-27
1 combusted fuel into mechanical energy (typically rotating shaft energy),
approximately
2 25% to 30% to energy of exhaust gases and the remainder to waste heat
produced
3 mainly in the generator cooling system. If the exhaust gases 116 are
combined with
4 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
6 of the input water 114, then about 90% to about 95% of the energy of
combusted fuel
7 can be captured and made available for injecting energized steam and other
gases into
8 an injector well.
9 Examples of low cost fuel/oxidant combinations are: diesel fuel/air; diesel
fuel/oxygen; methane/air; methane/oxygen; various emulsion fuels/air; various
11 emulsion fuels/oxygen; JP4/red fuming nitric acid; and the like.
12 A principal objective of the present invention is to locate a steam
generator in
13 close proximity to an injector well-head and to produce steam at high
levels of
14 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
16 injected mixture is an energetic gas in the desired temperature and
pressure range and
17 with a mixture of gaseous constituents compatible with the reservoir
geology.
18 Examples of well-head generators will be provided (Figures 5, 6 and 7) for
controlling a
19 high efficiency steam generator so that pressure, temperature, mass and gas
constituents can be tailored to conditions required for thermal recovery in a
heavy
21 hydrocarbon reservoir.
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CA 02642078 2007-09-27
1 Figure 2 is a plan view schematic of an example of a one of a number of
2 possible placements for the downhole combustion apparatus of the present
invention.
3 The interior workspace of a tunnel or shaft is shown enclosed, for example,
by concrete
4 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
6 alcove wall 202 by a flange 211. The alcove wall 202 is formed and sealed
into the
7 shaft or tunnel liner. A method of installing such recesses under formation
pressure is
8 fully described in US Patent Application Serial No. 11/737,578 filed April
19, 2006
9 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
11 are in the range of about 4 meters to about 10 meters. Once installed, the
recesses
12 202 serve as the working space for installing , operating and servicing the
well-head
13 equipment. In the present invention, this wellhead apparatus 212 is adapted
for use
14 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
16 process as well as shut down the well so that the downhole steam and flue
gas
17 generator can be serviced or replaced. This process of well-head control is
described
18 more fully in Figure 4. In the configuration shown in Figure 2, a generator
221 is shown
19 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
21 well-head apparatus 212 and controlled by valves as described in Figure 4.
The
22 generator 221 consumes fuel and all the mechanical and exhaust energy
produced by
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CA 02642078 2007-09-27
1 the generator 221 is injected through manifold 231. In addition,
supplementary water
2 may be injected through conduit 234 and optional gases (CO2 for example) may
be
3 injected through conduit 235. The steam, water and other gases from the
generator
4 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
6 be mixed in any combination and then injected into the formation (reservoir
rock) via
7 injector well 205. It is appreciated that the supplementary water in conduit
234 may
8 routed to the generator 221 and used as coolant for the generator 221 so
that the
9 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
11 cooling system for generator 221 is operable with untreated water. In the
event that the
12 generator has to be serviced or replaced, then well 205 can be shut in at
approximately
13 normal operating pressure and temperature by a method further described in
Figure 4.
14 Figure 3 is similar to Figure 2 except that the generator 321 is piaced in
an
alcove 303 and thus will be out of the general traffic, ventilation ducts and
utility
16 conduits in the tunnel or shaft. The generator 331 is shown with its steam,
flue gas and
17 water outlets (conduits 325, 327 and 327) connected to a manifold 331which
is, in turn,
18 attached to the well-head apparatus 312 and controlled by valves as
described in
19 Figure 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
21 recess 302.
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CA 02642078 2007-09-27
1 Figure 4 is a schematic of a controllable injector well-head apparatus and
2 illustrates an example of how an injector well can be controlled, serviced
or its steam
3 generator replaced while maintaining the injector well at operating pressure
and
4 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
6 generator. The output of the steam generator may include steam, some water
and
7 some combustion products which are fed via conduits 401 to manifold 407. In
the
8 example of Figure 4, the manifold is shown injecting steam and other gases
via valve
9 424 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
11 surface storage sources by valves. For example, supplementary water is
injected into
12 well 404 via valve 423 and optional gases, such as for example CO2,
injected into well
13 404 via valve 424. The injector well can be shut-in by closing valve 421
and shutting
14 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
16 valves 423 and 426. The upper master valve 422 and lower master valve 421
can also
17 be shut, thus fully and safely shutting in the well. Once this is
accomplished, the
18 generator can be serviced or replaced. If necessary, scale and precipitates
can be
19 removed from the well-head apparatus, at least down to master valve 422 or
421.
Figure 5 is a schematic of a steam/gas generator based on a diesel engine. The
21 apparatus is designed to utilize all of the fuel energy consumed by the
engine and
22 inject all its produced energy and exhaust gases into a well along with
water to create
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CA 02642078 2007-09-27
1 high pressure, high temperature steam that can be used to heat and mobilize
heavy oil
2 or bitumen in a reservoir. Typically, about 40% to about 45% of the fuel
energy
3 supplied to a diesel is transformed into mechanical shaft energy; about 30%
appears
4 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
6 diesel).
7 In this concept, a diesel engine 508 is shown driving a compressor 502 via
drive
8 shaft 506. The diesel 508 is powered by a fuel supply 516 and oxidant supply
515.
9 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-
11 enriched air. The choice of fuel and oxidant changes the mechanical
efficiency and
12 mix of exhaust products of the engine and so allows some control over the
composition
13 of injected gases. In the present invention, the exhaust 509 from the
diesel is routed to
14 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.
16 Treated or untreated water 517 is fed through a heat exchanger 518 where it
becomes
17 heated from hot water in a closed cooling system 510 of the engine 508.
This heated
18 water is injected 521 into the well 501 via conduit 507. Thus, almost all
the energy
19 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.
21 When the well-head steam generator is a diesel engine that is modified to
inject
22 its own combustion gases into the injector well, then an approximately
4,100
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CA 02642078 2007-09-27
1 horsepower engine would be required to maintain a production or collector
well of 500
2 barrels per day, where the Steam-Oil-Ratio is about 3. This well-head system
would
3 require approximately 6.1 gallons of diesel fuel per minute and 10.4 gallons
of water
4 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
6 the surface, it would lose about 15% of its energy in transmission losses
and so would
7 have to be still larger to compensate. So the preferable placement of such a
generator
8 would be in an underground workspace in close proximity to a well-head.
9 Figure 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 Figure 5
except an
11 additional heat exchanger 628 is added to a compressor 602 to moderate the
12 temperature of the hot compressed exhaust gases 605 from the engine 608 and
to
13 transfer heat from the compressor 602 to additional treated or untreated
water 617.
14 The,water heated in compressor heat exchanger 628 is added to the water
heated in
engine heat exchanger 608 at junction 619.
16 Figure 7 is an example of liquid propellant gun technology adapted to form
a
17 downhole water jet that can work against extremely high back pressures.
These back
18 pressures can be in the range of about 10,000 psi to about 50,000 psi. The
liquid
19 propellant jet drill shown in Figure 7 can be modified so that it functions
like the diesel
engine shown in Figures 5 and 6. The pistons are driven by combustion of a
suitable
21 liquid propellant in chambers 65 and pressure water or steam in chambers 61
which is
22 ' then injected into an injector well. Although not shown, the combustion
products may
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CA 02642078 2007-09-27
1 be exhausted into the injector well to add their energy to the process. The
liquid
2 propellant water jet drill shown in Figure 7 was taken from Fig. 5 of US
Patent
3 3,620,313.
4 Another advantage of the present invention is illustrated in Figure 8. Since
the
present invention is preferably practiced underground, water, for example, may
be
6 stored in a tank 803 on the surface. The water can be sent underground via
conduit
7 804 down shaft 805 where it will arrive at the bottom of the shaft 805 with
a substantial
8 pressure head. These shafts are typically in the range of 100 meters to over
500
9 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
11 807 and from there can be injected into a nearby injector well with little
or no additional
12 pressurizing. This capability can also be used for pressurizing liquid or
gaseous fuels,
13 if necessary, for a selected generator.
14 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
16 invention without providing others. For example, large prior-art gas
burners can be
17 used. Other injectors based on, for example, a free piston engine can also
be modified
18 and used to compress their own exhaust products. In another variation,
exhaust gases
19 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
21 transferred to heat a water supply using a heat exchanger apparatus. The
present
22 invention, in various embodiments, includes components, methods, processes,
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CA 02642078 2007-09-27
1 systems and/or apparatus substantially as depicted and described herein,
including
2 various embodiments, sub-combinations, and subsets thereof. Those of skill
in the art
3 will understand how to make and use the present invention after
understanding the
4 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
6 in various embodiments hereof, including in the absence of such items as may
have
7 been used in previous devices or processes, for example for improving
performance,
8 achieving ease and\or reducing cost of implementation.
9 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
11 form or forms disclosed herein. In the foregoing Detailed Description for
example,
12 various features of the invention are grouped together in one or more
embodiments for
13 the purpose of streamlining the disclosure. This method of disclosure is
not to be
14 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,
16 inventive aspects lie in less than all features of a single foregoing
disclosed
17 embodiment. Thus, the following claims are hereby incorporated into this
Detailed
18 Description, with each claim standing on its own as a separate preferred
embodiment
19 of the invention.
Moreover though the description of the invention has included description of
one
21 or more embodiments and certain variations and modifications, other
variations and
22 modifications are within the scope of the invention, e.g., as may be within
the skill and
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CA 02642078 2007-09-27
1 knowledge of those in the art, after understanding the present disclosure.
It is intended
2 to obtain rights which include alternative embodiments to the extent
permitted,
3 including alternate, interchangeable and/or equivalent structures,
functions, ranges or
4. steps to those claimed, whether or not such alternate, interchangeable
and/or
equivalent structures, functions, ranges or steps are disclosed herein, and
without
6 intending to publicly dedicate any patentable subject matter.
7 In one configuration, a heat exchanger is used to transfer heat from the
engine
8 to pre-heat water prior to converting it to steam and injecting it into the
hydrocarbon-
9 containing material.
In one configuration, a used to transfer waste heat energy from the compressor
11 to the water prior to converting it to steam and injecting it into the
hydrocarbon-
12 containing material.
13
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