U.S. patent application number 14/549479 was filed with the patent office on 2015-05-28 for waste heat recovery from depleted reservoir.
The applicant listed for this patent is Cenovus Energy Inc.. Invention is credited to Mark Bilozir, Christian CANAS, Subodh GUPTA, Arun SOOD.
Application Number | 20150144345 14/549479 |
Document ID | / |
Family ID | 53181663 |
Filed Date | 2015-05-28 |
United States Patent
Application |
20150144345 |
Kind Code |
A1 |
Bilozir; Mark ; et
al. |
May 28, 2015 |
WASTE HEAT RECOVERY FROM DEPLETED RESERVOIR
Abstract
Described herein is a method of producing heated water from a
hydrocarbon reservoir. The method includes injecting water into at
least a portion of the hot bitumen-depleted zone to heat the water;
and producing the heated water from a heated water production well.
The method can includes generating the hot bitumen-depleted zone
using steam-assisted gravity drainage, in situ combustion, steam
flooding, cyclic steam stimulation, a solvent aided thermal
recovery process, electric heating, electromagnetic heating, or any
combination thereof.
Inventors: |
Bilozir; Mark; (Calgary,
CA) ; CANAS; Christian; (Calgary, CA) ; GUPTA;
Subodh; (Calgary, CA) ; SOOD; Arun; (Calgary,
CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Cenovus Energy Inc. |
Calgary |
|
CA |
|
|
Family ID: |
53181663 |
Appl. No.: |
14/549479 |
Filed: |
November 20, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61907956 |
Nov 22, 2013 |
|
|
|
Current U.S.
Class: |
166/302 ;
166/256 |
Current CPC
Class: |
F24T 10/20 20180501;
Y02E 10/10 20130101; Y02E 10/14 20130101; E21B 43/24 20130101 |
Class at
Publication: |
166/302 ;
166/256 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 36/02 20060101 E21B036/02; E21B 43/243 20060101
E21B043/243; E21B 36/04 20060101 E21B036/04 |
Claims
1. A method of producing heated water from a hydrocarbon reservoir,
the method comprising: injecting water into at least a portion of
the hot bitumen-depleted zone to heat the water; and producing the
heated water from a heated water production well.
2. The method according to claim 1, further comprising: generating
the hot bitumen-depleted zone using steam-assisted gravity
drainage, in situ combustion, steam flooding, cyclic steam
stimulation, a solvent aided thermal recovery process, electric
heating, electromagnetic heating, or any combination thereof.
3. The method according to claim 1, wherein injecting the water
into at least a portion of the hot bitumen-depleted zone heats the
water sufficiently to generate steam in situ.
4. The method according to claim 3, wherein the heated water
production well is located above at least a portion of the hot
bitumen-depleted zone, and the water is injected into the portion
of the hot-bitumen depleted zone below the heated water production
well.
5. The method according to claim 1, wherein injecting the water
into at least a portion of the hot bitumen-depleted zone heats the
water sufficiently to generate hot liquid water in situ.
6. The method according to claim 5 wherein the heated water
production well is located below at least a portion of the hot
bitumen-depleted zone, and the water is injected into the portion
of the hot-bitumen depleted zone above the heated water production
well.
7. The method according to claim 1, wherein injecting the water
into at least a portion of the hot bitumen-depleted zone heats the
water sufficiently to generate both steam and hot liquid water in
situ.
8. The method according to claim 7, wherein the method comprises
producing heated water from a first and a second heated water
production well, wherein: the first heated water production well is
located above at least a portion of the hot bitumen-depleted zone;
and the second heated water production well is located below at
least a portion of the hot bitumen-depleted zone; and the water is
injected into a portion of the hot-bitumen depleted zone below the
first heated water production well and above the heated water
production well, and the first heated water production well
produces heated water from the generated steam, and the second
heated water production well produces heated water from the
generated hot liquid water.
Description
INCORPORATION BY REFERENCE OF PRIORITY APPLICATIONS
[0001] This application claims the benefit of priority of U.S.
Provisional Patent Application No. 61/907,956 filed Nov. 22, 2013,
which is hereby incorporated by reference in its entirety.
FIELD
[0002] The present disclosure relates generally to methods of
producing heat from a depleted reservoir.
BACKGROUND
[0003] A variety of processes are used to recover viscous
hydrocarbons, such as heavy oils and bitumen, from reservoirs such
as oil sands deposits. Extensive deposits of viscous hydrocarbons
exist around the world, including large deposits in the Northern
Alberta oil sands that are not susceptible to standard oil well
production technologies. One problem associated with producing
hydrocarbons from such deposits is that the hydrocarbons are too
viscous to flow at commercially relevant rates at the temperatures
and pressures present in the reservoir.
[0004] In some cases, such deposits are mined using open-pit mining
techniques to extract hydrocarbon-bearing material for later
processing to extract the hydrocarbons. Alternatively, thermal
techniques may be used to heat the hydrocarbon reservoir to
mobilize the hydrocarbons and produce the heated, mobilized
hydrocarbons from wells.
[0005] One thermal method of recovering viscous hydrocarbons using
two vertically spaced horizontal wells is known as steam-assisted
gravity drainage (SAGD). Various embodiments of the SAGD process
are described in Canadian Patent No. 1,304,287 and corresponding
U.S. Pat. No. 4,344,485. In the SAGD process, steam is pumped
through an upper, horizontal, injection well into a viscous
hydrocarbon reservoir while mobilized hydrocarbons are produced
from a lower, parallel, horizontal, production well that is
vertically spaced and near the injection well. The injection and
production wells are located close to the bottom of the hydrocarbon
deposit to collect the hydrocarbons that flow toward the
bottom.
[0006] The SAGD process works as follows. The injected steam
initially mobilizes the hydrocarbons to create a steam chamber in
the reservoir around and above the horizontal injection well. The
term "steam chamber" is utilized to refer to the volume of the
reservoir that is saturated with injected steam and from which
mobilized oil has at least partially drained. As the steam chamber
expands upwardly and laterally from the injection well, viscous
hydrocarbons in the reservoir are heated and mobilized, in
particular, at the margins of the steam chamber where the steam
condenses and heats the viscous hydrocarbons by thermal conduction.
The mobilized hydrocarbons and aqueous condensate drain, under the
effects of gravity, toward the bottom of the steam chamber, where
the production well is located. The mobilized hydrocarbons are
collected and produced from the production well. The rate of steam
injection and the rate of hydrocarbon production may be modulated
to control the growth of the steam chamber and ensure that the
production well remains located at the bottom of the steam chamber
in an appropriate position to collect mobilized hydrocarbons.
[0007] In situ Combustion (ISC) is another thermal method which may
be utilized to recover hydrocarbons from underground hydrocarbon
reservoirs. ISC includes the injection of an oxidizing gas into the
porous rock of a hydrocarbon-containing reservoir to ignite and
support combustion of the hydrocarbons around the wellbore. ISC may
be initiated using an artificial igniter such as a downhole heater
or by pre-conditioning the formation around the wellbores and
promoting spontaneous ignition. The ISC process, also known as fire
flooding or fireflood, is sustained and the ISC fire front moves
due to the continuous injection of the oxidizing gas. The heat
generated by burning the heavy hydrocarbons in place produces
hydrocarbon cracking, vaporization of light hydrocarbons and
reservoir water in addition to the deposition of heavier
hydrocarbons known as coke. As the fire moves, the burning front
pushes a mixture of hot combustion gases, steam, and hot water,
which in turn reduces oil viscosity and the oil moves toward the
production well. Additionally, the light hydrocarbons and the steam
move ahead of the burning front, condensing into liquids,
facilitating miscible displacement and hot water flooding, which
contribute to the recovery of hydrocarbons.
[0008] Canadian Patent 2,096,034 to Kisman et al. and U.S. Pat. No.
5,211,230 to Ostapovich et al. disclose a method of in situ
combustion for the recovery of hydrocarbons from underground
reservoirs, sometimes referred to as Combustion Split production
Horizontal well Process (COSH) or Combustion Overhead Gravity
Drainage (COGD). The disclosed processes include gravity drainage
to a basal horizontal well in a combustion process. A horizontal
production well is located in the lower portion of the reservoir. A
vertical injection and one or more vertical vent wells are provided
in the upper portion of the reservoir. Oxygen-enriched gas is
injected down the injector well and ignited in the upper portion of
the reservoir to create a combustion zone that reduces viscosity of
oil in the reservoir as the combustion zone advances downwardly
toward the horizontal production well. The reduced-viscosity oil
drains into the horizontal production well under the force of
gravity.
[0009] Canadian Patent 2,678,347 to Bailey discloses a pre-ignition
heat cycle (PIHC) using cyclic steam injection and steam flood
methods that improve the recovery of viscous hydrocarbons from a
subterranean reservoir using an overhead in situ combustion
process, referred to as combustion overhead gravity drainage
(COGD). Bailey discloses a method where the reservoir well network
includes one or more injection wells and one or more vent wells
located in the top portion of the reservoir, and where the
horizontal drain is located in the bottom portion of the
reservoir.
[0010] The use of ISC as a follow up process to SAGD is disclosed
in Canadian Patent 2,594,414 to Chhina et al. The disclosed
hydrocarbon recovery processes may be utilized in hydrocarbon
reservoirs. Chhina discloses a process where a former steam
injection well, used during the preceding SAGD recovery process, is
used as an oxidizing gas injection well and where another former
steam injection well, adjacent to the oxidizing gas injection well,
is converted into a combustion gas production well. This results in
the horizontal hydrocarbon production well being located below the
horizontal oxidizing gas injection well and at least one combustion
gas production well being spaced from the injection well by a
distance that is greater than the spacing between hydrocarbon
production well and the oxidizing gas injection well. Since the
process disclosed by Chhina uses at least two wells pairs, ISC is
initiated after the production well is sufficiently depleted of
hydrocarbons to establish communication between the two well
pairs.
[0011] At the end of thermal based hydrocarbon recovery processes
there is residual energy stored in the bitumen-depleted reservoir.
In the case of steam-based recovery processes, this energy is the
result of steam injection in the reservoir during the life time of
the process. In the case of combustion-based recovery processes,
this energy is the result of the heat of the combustion used to
produce the hydrocarbons. It is desirable to recover thermal energy
from hydrocarbon reservoir that has a hot bitumen-depleted
zone.
SUMMARY
[0012] In a first aspect, the present disclosure provides a method
of producing heated water from a hydrocarbon reservoir having a hot
bitumen-depleted zone. The method includes injecting water into at
least a portion of the hot bitumen-depleted zone to heat the water;
and producing the heated water from a heated water production
well.
[0013] The method may also include generating the hot
bitumen-depleted zone using steam-assisted gravity drainage, in
situ combustion, steam flooding, cyclic steam stimulation, a
solvent aided thermal recovery process, electric heating,
electromagnetic heating, or any combination thereof.
[0014] Injecting the water into at least a portion of the hot
bitumen-depleted zone may heat the water sufficiently to generate
steam in situ. The heated water production well may be located
above at least a portion of the hot bitumen-depleted zone, and the
water may be injected into the portion of the hot-bitumen depleted
zone below the heated water production well.
[0015] Injecting the water into at least a portion of the hot
bitumen-depleted zone may heat the water sufficiently to generate
hot liquid water in situ. The heated water production well may be
located below at least a portion of the hot bitumen-depleted zone,
and the water may be injected into the portion of the hot-bitumen
depleted zone above the heated water production well.
[0016] Injecting the water into at least a portion of the hot
bitumen-depleted zone may heat the water sufficiently to generate
both steam and hot liquid water in situ. Heated water may be
produced from a first and a second heated water production well,
where the first heated water production well is located above at
least a portion of the hot bitumen-depleted zone; and the second
heated water production well is located below at least a portion of
the hot bitumen-depleted zone. The water may be injected into a
portion of the hot-bitumen depleted zone below the first heated
water production well and above the heated water production well.
In such a situation, the first heated water production well may
produce heated water from the generated steam, and the second
heated water production well may produce heated water from the
generated hot liquid water.
[0017] Some embodiments described herein include a method of
producing heated water from a hydrocarbon reservoir, the method
comprising injecting water into at least a portion of the hot
bitumen-depleted zone to heat the water; and producing the heated
water from a heated water production well.
[0018] In some embodiments, the method further comprises generating
the hot bitumen-depleted zone using steam-assisted gravity
drainage, in situ combustion, steam flooding, cyclic steam
stimulation, a solvent aided thermal recovery process, electric
heating, electromagnetic heating, or any combination thereof.
[0019] In some embodiments, injecting the water into at least a
portion of the hot bitumen-depleted zone heats the water
sufficiently to generate steam in situ.
[0020] In some embodiments, the heated water production well is
located above at least a portion of the hot bitumen-depleted zone,
and the water is injected into the portion of the hot-bitumen
depleted zone below the heated water production well.
[0021] In some embodiments, injecting the water into at least a
portion of the hot bitumen-depleted zone heats the water
sufficiently to generate hot liquid water in situ.
[0022] In some embodiments, the heated water production well is
located below at least a portion of the hot bitumen-depleted zone,
and the water is injected into the portion of the hot-bitumen
depleted zone above the heated water production well.
[0023] In some embodiments, injecting the water into at least a
portion of the hot bitumen-depleted zone heats the water
sufficiently to generate both steam and hot liquid water in
situ.
[0024] In some embodiments, the method comprises producing heated
water from a first and a second heated water production well,
wherein the first heated water production well is located above at
least a portion of the hot bitumen-depleted zone; and the second
heated water production well is located below at least a portion of
the hot bitumen-depleted zone; and the water is injected into a
portion of the hot-bitumen depleted zone below the first heated
water production well and above the heated water production well,
and the first heated water production well produces heated water
from the generated steam, and the second heated water production
well produces heated water from the generated hot liquid water.
[0025] Other aspects and features of the present disclosure will
become apparent to those ordinarily skilled in the art upon review
of the following description of specific embodiments in conjunction
with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[0026] Embodiments of the present disclosure will now be described,
by way of example only, with reference to the attached Figures. The
patent or application file contains at least one drawing executed
in color, Copies of this patent or patent application publication
with color drawing(s) will be provided by the Office upon request
and payment of the necessary fee,
[0027] FIG. 1 is an illustration of a first simulated
reservoir.
[0028] FIG. 2 is an illustration of the temperature profile of the
first simulated reservoir after 4 years of SAGD.
[0029] FIG. 3 is an illustration of the temperature profile of the
first simulated reservoir after 1 year of injection of methane.
[0030] FIG. 4 is an illustration of the temperature profile of the
first simulated reservoir after 2.28 years of injection of
water.
[0031] FIG. 5 is a graph showing the cumulative energy injected and
produced for the first simulated reservoir.
[0032] FIG. 6 is a graph showing the energy distribution at
different stages of the process for the first simulated
reservoir.
[0033] FIG. 7 is an illustration of a second simulated
reservoir.
[0034] FIG. 8 is an illustration of the temperature profile of the
second simulated reservoir after 4 years of SAGD.
[0035] FIG. 9 is an illustration of the temperature profile of the
second simulated reservoir after 1 year of injection of
methane.
[0036] FIG. 10 is an illustration of the temperature profile of the
second simulated reservoir after 3.31 years of injection of
water.
[0037] FIG. 11 is a graph showing the cumulative energy injected
and produced for the second simulated reservoir.
[0038] FIG. 12 is a graph showing the energy distribution at
different stages of the process for the second simulated
reservoir.
[0039] FIG. 13 is an illustration of a third simulated
reservoir.
[0040] FIG. 14 is an illustration of the temperature profile of the
third simulated reservoir after 4 years of SAGD.
[0041] FIG. 15 is an illustration of the temperature profile of the
third simulated reservoir after 1 year of injection of methane.
[0042] FIG. 16 is an illustration of the temperature profile of the
third simulated reservoir after 5.82 years of injection of
water.
[0043] FIG. 17 is a graph showing the cumulative energy injected
and produced for the third simulated reservoir.
[0044] FIG. 18 is a graph showing the energy distribution at
different stages of the process for the third simulated
reservoir.
[0045] FIG. 19 is an illustration of a fourth simulated
reservoir.
[0046] FIG. 20 is an illustration of the temperature profile of the
fourth simulated reservoir after 3.6 years of SAGD.
[0047] FIG. 21 is an illustration of the temperature profile of the
fourth simulated reservoir after 2 year of injection of butane.
[0048] FIG. 22 is an illustration of the temperature profile of the
fourth simulated reservoir after 1.2 years of injection of
water.
[0049] FIG. 23 is a graph showing the cumulative energy injected
and produced for the fourth simulated reservoir.
[0050] FIG. 24 is an illustration of a fifth simulated
reservoir.
[0051] FIG. 25 is an illustration of the temperature profile of the
fifth simulated reservoir after 3.6 years of SAGD.
[0052] FIG. 26 is an illustration of the temperature profile of the
fifth simulated reservoir after 2 year of injection of butane.
[0053] FIG. 27 is an illustration of the temperature profile of the
fifth simulated reservoir after 3.8 years of injection of
water.
[0054] FIG. 28 is a graph showing the cumulative energy injected
and produced for the fifth simulated reservoir.
[0055] FIG. 29 is a graph showing the energy distribution at
different stages of the process for the fifth simulated
reservoir.
[0056] FIG. 30 is an illustration of a sixth simulated
reservoir.
[0057] FIG. 31 is an illustration of the temperature profile of the
sixth simulated reservoir after 5 years of SAGD and 4.5 years of in
situ combustion.
[0058] FIG. 32 is an illustration of the temperature profile of the
sixth simulated reservoir after 0.3 years of injection of
water.
[0059] FIG. 33 is an illustration of the temperature profile of the
sixth simulated reservoir after 0.9 years of injection of
water.
[0060] FIG. 34 is an illustration of the temperature profile of the
sixth simulated reservoir after 1.5 years of injection of
water.
[0061] FIG. 35 is a graph showing the cumulative energy injected
and produced for the sixth simulated reservoir.
[0062] FIG. 36 is a graph showing the energy distribution at
different stages of the process for the sixth simulated
reservoir.
DETAILED DESCRIPTION
[0063] Generally, the present disclosure provides a method of
producing heated water from a hydrocarbon reservoir having a hot
bitumen-depleted zone. The method includes: injecting water into at
least a portion of the hot bitumen-depleted zone to heat the water;
and producing the heated water from a heated water production well.
The water may be injected using an injection well.
[0064] The method may also include generating the hot
bitumen-depleted zone using steam-assisted gravity drainage, in
situ combustion, steam flooding, cyclic steam stimulation, a
solvent aided thermal recovery process, electric heating,
electromagnetic heating, or any combination thereof.
[0065] Injecting the water into at least a portion of the hot
bitumen-depleted zone may heat the water sufficiently to generate
steam in situ. The heated water production well may be located
above at least a portion of the hot bitumen-depleted zone, and the
water may be injected into the portion of the hot-bitumen depleted
zone below the heated water production well.
[0066] Injecting the water into at least a portion of the hot
bitumen-depleted zone may heat the water sufficiently to generate
hot liquid water in situ. The heated water production well may be
located below at least a portion of the hot bitumen-depleted zone,
and the water may be injected into the portion of the hot-bitumen
depleted zone above the heated water production well.
[0067] Injecting the water into at least a portion of the hot
bitumen-depleted zone may heat the water sufficiently to generate
both steam and hot liquid water in situ. Heated water may be
produced from a first and a second heated water production well,
where the first heated water production well is located above at
least a portion of the hot bitumen-depleted zone; and the second
heated water production well is located below at least a portion of
the hot bitumen-depleted zone. The water may be injected into a
portion of the hot-bitumen depleted zone below the first heated
water production well and above the heated water production well.
In such a situation, the first heated water production well may
produce heated water from the generated steam, and the second
heated water production well may produce heated water from the
generated hot liquid water.
[0068] It is not necessary that the bitumen-depleted zone be
completely depleted of bitumen. Accordingly, in the context of the
present application, a bitumen-depleted zone would be understood to
refer to a zone in the hydrocarbon reservoir where it is not
commercially viable to continue to extract bitumen from the
hydrocarbon reservoir, even though residual bitumen may be present
in the hydrocarbon reservoir. In some hydrocarbon reservoirs, it
may no longer be commercially viable to extract bitumen once the
average residual oil saturation level is less than 40%. In other
hydrocarbon reservoirs, it may no longer be commercially viable to
extract bitumen once the average residual oil saturation level is
less than 30%. In yet other hydrocarbon reservoirs, it may no
longer be commercially viable to extract bitumen once the average
residual oil saturation level is less than 20%. In some especially
productive hydrocarbon reservoirs, it may no longer be commercially
viable to extract bitumen once the average residual oil saturation
level is less than 10-15%.
[0069] A hot bitumen-depleted zone is to be understood to refer to
a bitumen-depleted zone whose temperature is elevated by heat used
in a thermal bitumen-recovery process that generates the
bitumen-depleted zone. In particular examples, the hot
bitumen-depleted zone is generated by steam-assisted gravity
drainage, in situ combustion, a solvent aided thermal recovery
process, electric heating, electromagnetic heating, or any
combination thereof.
[0070] In some examples, the hot bitumen-depleted zone has an
average temperature of at least 10.degree. C. For example, the hot
bitumen-depleted zone may have an average temperature of between 20
and 300.degree. C. when the hot bitumen-depleted zone is generated
by steam-assisted gravity drainage. In another example, the hot
bitumen-depleted zone may have an average temperature of between 20
and 600.degree. C. when the hot bitumen-depleted zone is generated
by in situ combustion. In yet another example, the hot
bitumen-depleted zone may have an average temperature of between 20
and 400.degree. C. when the hot bitumen-depleted zone is generated
by electromagnetic heating.
[0071] Regardless of the thermal bitumen recovery method used to
generate the hot bitumen-depleted zone, some hot bitumen-depleted
zones may have conditions that generate steam from the water, while
other hot bitumen-depleted zones may have conditions that generate
hot liquid water. A hot bitumen-depleted zone may, at a specific
point in time, have conditions that generate steam, and, at a later
point in time, may have conditions that generate hot liquid
water.
[0072] When generating steam in the hot bitumen-depleted zone, it
is desirable to place the heated water production well above at
least a portion of the hot bitumen-depleted zone. In such a manner,
the water that is injected into the portion of the hot-bitumen
depleted zone below the heated water production well may be turned
into steam, which rises up to the heated water production well.
[0073] It is not necessary for the heated water production well to
be placed above at least a portion of the hot bitumen-depleted
zone. Steam may be driven from an upper portion of the hot
bitumen-depleted zone downwards to a heated water production well
placed below at least a portion of the hot bitumen-depleted zone.
Alternatively, steam may be driven substantially across a portion
of the hot bitumen-depleted zone to a heated water production well
that is at substantially the same level as the liquid water
injection well. The steam may be produced from the heated water
production well as steam or as hot liquid water.
[0074] When generating hot liquid water in the hot bitumen-depleted
zone, it is desirable to place the heated water production well
below at least a portion of the hot bitumen-depleted zone. In such
a manner, the water that is injected into the portion of the
hot-bitumen depleted zone above the heated water production well
may be turned into hot liquid water, which descends due to gravity
to the heated water production well.
[0075] It is not necessary for the heated water production well to
be placed below at least a portion of the hot bitumen-depleted
zone. Liquid water may be driven from a lower portion of the hot
bitumen-depleted zone upwards to a heated water production well
placed above at least a portion of the hot bitumen-depleted zone.
Alternatively, liquid water may be driven substantially across a
portion of the hot bitumen-depleted zone to a heated water
production well that is at substantially the same level as the
liquid water injection well.
[0076] In some examples, injecting the liquid water in at least a
portion of the hot bitumen-depleted zone may heat the water
sufficiently to generate both steam and hot liquid water in situ.
When generating both steam and hot liquid water, the method may
include producing heated water from a first and a second heated
water production well. In such situations, the first heated water
production well is located above at least a portion of the hot
bitumen-depleted zone; and the second heated water production well
is located below at least a portion of the hot bitumen-depleted
zone. The water is injected into a portion of the hot-bitumen
depleted zone below the first heated water production well and
above the heated water production well, and the first heated water
production well produces heated water from the generated steam, and
the second heated water production well produces water from the
generated hot liquid water.
[0077] In the context of the presently disclosure, when referring
to `injecting water`, the term "water" should be understood to
refer to a generally aqueous solution that is injected into at
least a portion of the hot bitumen-depleted zone. The generally
aqueous solution may include salts, non-aqueous solvents that are
soluble in water, or both. The generally aqueous solution may be
mixed with one or more non-aqueous solvents that are not soluble in
water. The expression "injecting water" should be understood to
also include injecting this mixture into at least a portion of the
hot bitumen-depleted zone.
[0078] The expression "heated water" should be understood to mean
water that is at a temperature higher than the temperature of the
injected water. Heated water may be liquid water, or steam. The
steam may be saturated steam (or "wet steam"), or superheated steam
(or "dry steam"). Saturated steam could be considered to be a
mixture of liquid water and water vapor.
[0079] Since both temperature and pressure affect whether the
heated water is a hot liquid water or steam, water that is injected
into a hot bitumen-depleted zone as liquid water may be produced at
the heated water production well as steam. Accordingly, it is the
conditions in the hot bitumen-depleted zone that would determine
whether steam or hot liquid water is being driven through the
portion of the hot-bitumen depleted zone. In the context of the
present disclosure, it should be understood that reservoir
conditions may promote the co-existence of both steam and liquid
water. It should be understood that the term "steam" includes:
water vapor in a vapor-liquid equilibrium (also referred to as
"saturated steam" or "wet steam"), and a water vapor that is at a
temperature higher than its boiling point for the pressure, which
occurs when all the liquid water has evaporated or has been removed
from the system (also referred to as "superheated steam" or "dry
steam").
[0080] Hot bitumen-depleted zones that have conditions that
generate steam in the hot bitumen-depleted zone may, after thermal
energy is removed from the hot bitumen-depleted zone, have
conditions that generate hot liquid water in the hot
bitumen-depleted zone. The method may use a first heated water
production well that is located above at least a portion of the hot
bitumen-depleted zone when the hot bitumen-depleted zone has
conditions that generate steam, and a second heated water
production well that is located below at least a portion of the hot
bitumen-depleted zone when the hot bitumen-depleted zone has
conditions that generate hot liquid water.
EXAMPLE 1
[0081] A simulation of a process according to the present
disclosure reservoir was performed.
[0082] An illustration of the simulated reservoir is shown in FIG.
1. The SAGD pattern is a two-dimensional model whose dimensions are
50 m.times.2 m.times.24 m. These dimensions correspond to a
horizontal well pair that is 2 m long with a 24 m pay thickness and
a 100 m lateral well spacing. However, only half of the reservoir
was simulated due to symmetry, with the SAGD well pair on the left
and the water injection well on the right of the model.
Additionally, only 2 m of well pair length were simulated as the
model is 2-dimensional.
[0083] 1500 grid blocks were used as this number was adequate
enough to build an accurate model. The dimensions for each of these
blocks are 1 m.times.2 m.times.0.8 m in the X, Y, and Z directions
respectively. The SAGD injection well was placed 4 m above the SAGD
producing well which is located at the bottom of the reservoir.
[0084] Table 1 shows the reservoir and fluid parameters used in the
simulation.
TABLE-US-00001 TABLE 1 Average Gross Pay (m) 24 Porosity (%) 0.33
Bitumen Saturation (%) 0.8 Water Saturation (%) 0.2 Vertical
Permeability (mD) 4000 K.sub.v/K.sub.h 0.8 Viscosity (mPa s) at
20.degree. C. 2,670,000 Bitumen Density (kg/m.sup.3) at 20.degree.
C. 1014.8 Reservoir Temperature (.degree. C.) 11 Reservoir Pressure
(kPa) 2200
[0085] Table 2 shows the injection rates used in the simulation,
where the *'ed entries assume a 700 m length well pair.
TABLE-US-00002 TABLE 2 Steam injection (CWE) t/d 0.65 455* Methane
injection t/d 0.0057 4* Cold water injection t/d 1.5 1050*
[0086] In the simulation, bitumen is produced via steam-assisted
gravity drainage for a period of 4 years. After the 4 years of SAGD
operation, steam injection is ended and the hydrocarbon recovery
factor is 65.2%. The temperature profile of the simulated hot
bitumen depleted zone is shown in FIG. 2. The temperature ranges
from 228.degree. C. to 11.degree. C. with color indicating the
temperature in each simulated cell. Red represents hotter
temperatures and blue represents cooler temperatures.
[0087] At the end of 4 years, methane is injected for a period of 1
year in order to continue to produce hydrocarbon without injecting
additional heat into the reservoir. This may be referred to as
"methane blowdown". After the 1 year of injection of methane, the
hydrocarbon recovery factor is 71.4%. The temperature profile of
the simulated hot bitumen depleted zone is shown in FIG. 3.
[0088] After injection of methane, water is injected for a period
of 2.28 years. The water is injected into a portion of the hot
bitumen-depleted zone that is above the heated water production
well and heated water is produced from what was previously the SAGD
producing well. After the 2.28 years of injection of water, the
hydrocarbon recovery factor is 72.9%. The temperature profile of
the simulated hot bitumen depleted zone is shown in FIG. 4.
[0089] The cumulative energy injected and produced for the
simulation is illustrated in FIG. 5. The energy distribution at
different stages of the process is illustrated in FIG. 6. The
energy recovered between blow-down and the end of water injection
(4.53e8 kJ) represents 57.6% of the energy accumulated at blow-down
(7.859e8 kJ).
EXAMPLE 2
[0090] A simulation of a process according to the present
disclosure reservoir was performed.
[0091] An illustration of the simulated reservoir is shown in FIG.
7. The reservoir initial parameters were the same as in Example 1.
Only half of the reservoir was simulated due to symmetry, with the
water injection well located on the top right and two SAGD well
pairs.
[0092] Table 3 shows the injection rates used in the simulation,
where the *'ed entries assume a 700 m length well pair.
TABLE-US-00003 TABLE 3 Steam injection (CWE) t/d 1.95 1365* Methane
injection t/d 0.0171 11.97* Cold water injection t/d 4 2800*
[0093] In the simulation, bitumen is produced via steam-assisted
gravity drainage for a period of 4 years. After the 4 years of SAGD
operation, steam injection is ended and the hydrocarbon recovery
factor is 64.2%. The temperature profile of the simulated hot
bitumen depleted zone is shown in FIG. 8. The temperature ranges
from 233.degree. C. to 11.degree. C. with color indicating the
temperature in each simulated cell. Red represents hotter
temperatures and blue represents cooler temperatures.
[0094] At the end of 4 years, methane is injected for a period of 1
year in order to continue to produce hydrocarbon without injecting
additional heat into the reservoir. This may be referred to as
"methane blowdown". After the 1 year of injection of methane, the
hydrocarbon recovery factor is 72.9%. The temperature profile of
the simulated hot bitumen depleted zone is shown in FIG. 9.
[0095] After injection of methane, water is injected for a period
of 3.31 years. The water is injected into a portion of the hot
bitumen-depleted zone that is above the heated water production
well and heated water is produced from what was previously the SAGD
producing well. Water is injected into the well located at the
upper corners of the reservoir. When the temperature of the
produced water in the outer producing wells decreased to 90.degree.
C., these wells were closed. In this simulation, the first SAGD
well pair is shut-in at 6.16 years (i.e. after 1.16 years of water
injection). Water continues to be injected and is produced through
the middle producer until T=90.degree. C. After the 3.31 years of
injection of water, the hydrocarbon recovery factor is 73.7%. The
temperature profile of the simulated hot bitumen depleted zone is
shown in FIG. 10.
[0096] The cumulative energy injected and produced for the
simulation is illustrated in FIG. 11. The energy distribution at
different stages of the process is illustrated in FIG. 12. The
energy recovered between blow-down and the end of water injection
(1.88e9 kJ) represents 77.36% of the energy accumulated at
blow-down (2.43e9 kJ).
EXAMPLE 3
[0097] A simulation of a process according to the present
disclosure reservoir was performed.
[0098] An illustration of the simulated reservoir is shown in FIG.
13. The full reservoir was simulated due to asymmetry, with the
water injection well located on the top right and the heated water
production well located on the top left. The SAGD pattern is a
two-dimensional model whose dimensions are 300 m.times.2 m.times.24
m. These dimensions correspond to a horizontal well pair that is 2
m long with a 24 m pay thickness and a 100 m lateral well spacing.
9000 grid blocks were used as this number was adequate enough to
build an accurate model. The dimensions for each of these blocks
are 1 m.times.1 m.times.0.8 m in the X, Y, and Z directions
respectively.
[0099] Table 4 shows the injection rates used in the simulation,
where the *'ed entries assume a 700 m length well pair.
TABLE-US-00004 TABLE 4 Steam injection (CWE) t/d 3.9 1365* Methane
injection t/d 0.0342 11.97* Cold water injection t/d 3-5
1050-1750*
[0100] In the simulation, bitumen is produced via steam-assisted
gravity drainage for a period of 4 years. After the 4 years of SAGD
operation, steam injection is ended and the hydrocarbon recovery
factor is 64.6%. The temperature profile of the simulated hot
bitumen depleted zone is shown in FIG. 14. The temperature ranges
from 233.degree. C. to 11.degree. C. with color indicating the
temperature in each simulated cell. Red represents hotter
temperatures and blue represents cooler temperatures.
[0101] At the end of 4 years, methane is injected for a period of 1
year in order to continue to produce hydrocarbon without injecting
additional heat into the reservoir. This may be referred to as
"methane blowdown". After the 1 year of injection of methane, the
hydrocarbon recovery factor is 73.4%. The temperature profile of
the simulated hot bitumen depleted zone is shown in FIG. 15.
[0102] After injection of methane, water is injected into the water
injection well at the top right, and produced from the heated water
production well at the top left, for a period of 5.82 years. After
the 5.82 years of injection of water, the hydrocarbon recovery
factor is 73.44%. The temperature profile of the simulated hot
bitumen depleted zone is shown in FIG. 16.
[0103] The cumulative energy injected and produced for the
simulation is illustrated in FIG. 17. The energy distribution at
different stages of the process is illustrated in FIG. 18. The
energy recovered between blow-down and the end of water injection
(4.32e9 kJ) represents 88.5% of the energy accumulated at blow-down
(4.88e9 kJ).
EXAMPLE 4
[0104] A simulation of a process according to the present
disclosure reservoir was performed.
[0105] An illustration of the simulated reservoir is shown in FIG.
19. The SAGD pattern is a two-dimensional model whose dimensions
are 50 m.times.2 m.times.24 m. These dimensions correspond to a
horizontal well pair that is 2 m long with a 24 m pay thickness and
a 100 m lateral well spacing. However, only half of the reservoir
was simulated due to symmetry, with the SAGD well pair on the left
and the water injection well on the right of the model.
Additionally, only 2 m of well pair length were simulated as the
model is 2-dimensional.
[0106] 1500 grid blocks were used as this number was adequate
enough to build an accurate model. The dimensions for each of these
blocks are 1 m.times.2 m.times.0.8 m in the X, Y, and Z directions
respectively. The SAGD injection well was placed 4 m above the SAGD
producing well which is located at the bottom of the reservoir.
[0107] Table 5 shows the reservoir and fluid parameters used in the
simulation.
TABLE-US-00005 TABLE 5 Average Gross Pay (m) 24 Porosity (%) 0.33
Bitumen Saturation (%) 0.8 Water Saturation (%) 0.2 Vertical
Permeability (mD) 4000 K.sub.v/K.sub.h 0.8 Viscosity (mPa s) at
20.degree. C. 2,670,000 Bitumen Density (kg/m.sup.3) at 20.degree.
C. 1014.8 Reservoir Temperature (.degree. C.) 11 Reservoir Pressure
(kPa) 2200
[0108] Table 6 shows the injection rates used in the simulation,
where the asterisked entries assume a 700 m length well pair.
TABLE-US-00006 TABLE 6 Steam injection (CWE) t/d 0.65 455* Butane
injection t/d 0.0057 4* Cold water injection t/d 1.5 1050*
[0109] In the simulation, bitumen is produced via steam-assisted
gravity drainage for a period of 3.6 years. After the 3.6 years of
SAGD operation, steam injection is ended and the hydrocarbon
recovery factor is 60.7%. The temperature profile of the simulated
hot bitumen depleted zone is shown in FIG. 20. The temperature
ranges from 234.degree. C. to 11.degree. C. with color indicating
the temperature in each simulated cell. Red represents hotter
temperatures and blue represents cooler temperatures.
[0110] At the end of 3.6 years, butane is injected for a period of
2 years in order to continue to produce hydrocarbon without
injecting additional heat into the reservoir. This may be referred
to as "butane blowdown". After the 2 year of injection of butane,
the hydrocarbon recovery factor is 83.7%. The temperature profile
of the simulated hot bitumen depleted zone is shown in FIG. 21.
[0111] After injection of methane, water is injected for a period
of 1.2 years. The water is injected into a portion of the hot
bitumen-depleted zone that is above the heated water production
well and heated water is produced from what was previously the SAGD
producing well. After the 1.2 years of injection of water, the
hydrocarbon recovery factor is 83.7%. The temperature profile of
the simulated hot bitumen depleted zone is shown in FIG. 22.
[0112] The cumulative energy injected and produced for the
simulation is illustrated in FIG. 23. The energy recovered between
blow-down and the end of water injection (2.92e8 kJ) represents
43.5% of the energy accumulated at blow-down (7.71e8 kJ).
EXAMPLE 5
[0113] A simulation of a process according to the present
disclosure reservoir was performed.
[0114] An illustration of the simulated reservoir is shown in FIG.
24. The reservoir initial parameters were the same as in Example 2,
except that butane is injected at a rate of 0.195 t/d (10% of the
steam injection rate), which is higher than the rate of methane
injection to account for the larger simulated reservoir. Only half
of the reservoir was simulated due to symmetry, with the water
injection well located on the top right and two SAGD well
pairs.
[0115] In the simulation, bitumen is produced via steam-assisted
gravity drainage for a period of 3.6 years. After the 3.6 years of
SAGD operation, steam injection is ended and the hydrocarbon
recovery factor is 60.2%. The temperature profile of the simulated
hot bitumen depleted zone is shown in FIG. 25. The temperature
ranges from 239.degree. C. to 11.degree. C. with color indicating
the temperature in each simulated cell. Red represents hotter
temperatures and blue represents cooler temperatures.
[0116] At the end of 3.6 years, butane is injected for a period of
2 years in order to continue to produce hydrocarbon without
injecting additional heat into the reservoir. This may be referred
to as "butane blowdown". After the 2 year of injection of butane,
the hydrocarbon recovery factor is 81.1%. The temperature profile
of the simulated hot bitumen depleted zone is shown in FIG. 26.
[0117] After injection of butane, water is injected for a period of
3.8 years. The water is injected into a portion of the hot
bitumen-depleted zone that is above the heated water production
well and heated water is produced from what was previously the SAGD
producing well. Water is injected into the well located at the
upper corners of the reservoir. When the temperature of the
produced water in the outer producing wells decreased to 90.degree.
C., these wells were closed. In this simulation, the first SAGD
well pair is shut-in at 6.25 years (i.e. after 0.65 years of water
injection). Water continues to be injected and is produced through
the middle producer until T=90.degree. C. After the 3.8 years of
injection of water, the hydrocarbon recovery factor is 81.1%. The
temperature profile of the simulated hot bitumen depleted zone is
shown in FIG. 27.
[0118] The cumulative energy injected and produced for the
simulation is illustrated in FIG. 28. The energy distribution at
different stages of the process is illustrated in FIG. 29. The
energy recovered between blow-down and the end of water injection
(1.59e9 kJ) represents 79.5% of the energy accumulated at blow-down
(2.00e9 kJ).
EXAMPLE 6
[0119] A simulation of a process according to the present
disclosure reservoir was performed.
[0120] An illustration of the simulated reservoir is shown in FIG.
30. The reservoir initial parameters were the same as in Example 5.
Only a third of the reservoir was simulated due to symmetry, with
two oxidizing gas injector wells located on the top corners and one
SAGD well pair located at the bottom center.
[0121] In the simulation, bitumen is produced via steam-assisted
gravity drainage for a period of 5 years. After the 5 years of SAGD
operation, steam injection is ended and the hydrocarbon recovery
factor is 68.74%.
[0122] At the end of 5 years, oxidizing gas is injected for a
period of 4.5 years in order to produce hydrocarbons through
in-situ combustion. After the 4.5 years of in-situ combustion,
oxidizing gas injection is ended and the hydrocarbon recovery
factor is 75.43%.
[0123] After injection of oxidizing gas, water is injected for a
period of 1.5 years. The water is injected into a portion of the
hot bitumen-depleted zone through the former SAGD injection wells
and heated water is produced from the former oxidizing gas
injection wells as steam. After the 1.5 years of injection of
water, the hydrocarbon recovery factor is 75.43%.
[0124] The temperature profile of the simulated hot bitumen
depleted zone after 9.5 years, corresponding to the reservoir after
in situ combustion but before injection of water, is shown in FIG.
31. The temperature ranges from 1245.degree. C. to 11.degree. C.
with color indicating the temperature in each simulated cell. Red
represents hotter temperatures and blue represents cooler
temperatures.
[0125] Temperature profiles of the simulated hot bitumen depleted
zone after 9.8 and 10.4 years, corresponding to the reservoir at
two points during heat recovery, are shown in FIGS. 32 and 33. In
FIG. 32, the temperature ranges from 900.degree. C. to 11.degree.
C. In FIG. 33, the temperature ranges from 300.degree. C. to
11.degree. C. The temperature profile of the simulated hot bitumen
depleted zone after 11 years, corresponding to the reservoir at the
end of the heat recovery phase, is shown in FIG. 34.
[0126] The cumulative energy injected and produced for the
simulation is illustrated in FIG. 35. The energy distribution at
different stages of the process is illustrated in FIG. 36. The
energy recovered between in-situ combustion and the end of water
injection (1.353e9 kJ) represents 92.5% of the energy accumulated
at the end of in situ combustion (1.463e9 kJ).
[0127] In the preceding description, for purposes of explanation,
numerous details are set forth in order to provide a thorough
understanding of the examples. However, it will be apparent to one
skilled in the art that these specific details are not required.
The above-described examples are intended to be exemplary only.
Alterations, modifications and variations can be effected to the
particular examples by those of skill in the art without departing
from the scope, which is defined solely by the claims appended
hereto.
* * * * *