U.S. patent application number 13/103876 was filed with the patent office on 2011-11-17 for thermal mobilization of heavy hydrocarbon deposits.
This patent application is currently assigned to RESOURCE INNOVATIONS INC.. Invention is credited to Greg KURAN, Fred SCHNEIDER, Lynn P. TESSIER.
Application Number | 20110278001 13/103876 |
Document ID | / |
Family ID | 44910730 |
Filed Date | 2011-11-17 |
United States Patent
Application |
20110278001 |
Kind Code |
A1 |
SCHNEIDER; Fred ; et
al. |
November 17, 2011 |
THERMAL MOBILIZATION OF HEAVY HYDROCARBON DEPOSITS
Abstract
A method is provided for applying a thermal process to a lower
zone underlying an overlying hydrocarbon zone with thermal energy
from the thermal process mobilizing oil in the overlying zone. The
lower zone itself could be a hydrocarbon zone undergoing thermal
EOR. Further, one can economically apply a thermal EOR process to
an oil formation of low mobility and having an underlying zone such
as a basal water zone. Introduction gas and steam, the gas having a
higher density than the steam, into the underlying zone displaces
the basal water and creates an insulating layer of gas between the
steam and the basal water maximizing heat transfer upwardly and
mobilizing viscous oil greatly reducing the heat loss to the basal
water, economically enhancing production from thin oil bearing
zones with underlying basal water which are not otherwise economic
by other known EOR processes.
Inventors: |
SCHNEIDER; Fred; (Calgary,
CA) ; KURAN; Greg; (Calgary, CA) ; TESSIER;
Lynn P.; (Eckville, CA) |
Assignee: |
RESOURCE INNOVATIONS INC.
Calgary
CA
|
Family ID: |
44910730 |
Appl. No.: |
13/103876 |
Filed: |
May 9, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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61333645 |
May 11, 2010 |
|
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|
61356416 |
Jun 18, 2010 |
|
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61421481 |
Dec 9, 2010 |
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Current U.S.
Class: |
166/272.3 |
Current CPC
Class: |
E21B 43/24 20130101;
E21B 43/166 20130101; E21B 43/164 20130101; E21B 43/2406 20130101;
E21B 43/2408 20130101 |
Class at
Publication: |
166/272.3 |
International
Class: |
E21B 43/24 20060101
E21B043/24 |
Claims
1. A method of thermal oil recovery of oil from an oil formation
comprising: introducing thermal energy into a lower zone underlying
an upper zone containing a first oil formation; receiving the
thermal energy at the upper zone from the lower zone; and using the
thermal energy for thermally mobilizing the oil of the first oil
formation for recovery at one or more production wells completed in
the upper zone.
2. The method of claim 1 wherein introducing thermal energy into
the lower zone comprises injecting steam.
3. The method of claim 1 wherein introducing thermal energy into
the lower zone comprises operating a downhole burner for the
production of steam and combustion gases.
4. The method of claim 1 wherein introducing thermal energy into
the lower zone comprises generating in-situ steam.
5. The method of claim 1 wherein the upper zone is isolated from
the lower zone by a substantially non-permeable layer.
6. The method of claim 5 wherein the lower zone is a second oil
formation.
7. The method of claim 6 wherein the introducing of the thermal
energy into a lower zone further comprises: introducing steam to
the lower zone for thermally mobilizing oil in the second oil
formation for recovery at one or more production wells spaced
laterally from the location of introduction of the thermal energy
and completed in the lower zone.
8. The method of claim 7 wherein the introducing of steam to the
lower zone further comprises: providing a steam assisted gravity
drainage SAGD arrangement in the lower zone, the SAGD arrangement
having at least a steam injection well and at least a producer
well; and introducing steam from the at least a steam injection
well; thermally mobilizing the oil in the second oil formation;
recovering oil from the second oil formation at the at least a
producer well; and whereby receiving the thermal energy at the
upper zone further comprises receiving residual thermal energy from
the lower zone.
9. The method of claim 1 wherein the lower zone includes a basal
water zone, further comprising introducing gas and steam to the
lower zone underlying the oil formation for introducing thermal
energy to the lower zone, the gas having a density greater than
that of steam; gravity separating at least some of the gas from the
steam for forming an insulating layer of gas between the steam and
the basal water for transferring a predominate fraction of the
thermal energy upwardly; thermally mobilizing the oil in the upper
zone for recovery at one or more production wells spaced laterally
from the location of introduction of the thermal energy and
completed in the upper zone.
10. A method of thermal oil recovery of oil from an oil formation
comprising: introducing gas and steam to a lower zone underlying
the oil formation for introducing thermal energy to the lower zone,
the gas having a density greater than that of steam; gravity
separating at least some of the gas from the steam for forming an
insulating layer of gas below the steam and transferring a
predominate fraction of the thermal energy upwardly; and thermally
mobilizing the oil for recovery at one or more production wells
spaced laterally from the point of introduction.
11. The method of claim 10 wherein the oil formation overlies basal
water, and wherein the gravity separating at least some of the gas
from the steam forms the insulating layer between the steam and the
basal water.
12. The method of claim 11 further comprising draining water from
condensed steam into the basal water.
13. The method of claim 11 further comprising displacing the basal
water for forming an inverted cone of gas and steam which is
insulated from the basal water.
14. The method of claim 10 further comprising displacing the
thermally mobilized oil for recovery at the one or more production
wells.
15. The method of claim 14 wherein the introducing of the gas and
steam displaces the thermally mobilized oil.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Application No. 61/333,645, filed May 11, 2010, U.S. Provisional
Application No. 61/356,416, filed Jun. 18, 2010, and U.S.
Provisional Application No. 61/421,481.
FIELD OF THE INVENTION
[0002] The present invention relates to a method for effectively
directing thermal energy into a heavy hydrocarbon zone overlying a
lower zone. More particularly steam, gas or combinations thereof
are introduced to the lower zone for contact and thermal heat
transfer upward and for stimulation of the overlying heavy
hydrocarbons. In one embodiment the lower zone is a water zone,
introduced gas being used to drive water radially away from a point
of introduction and injected steam riding over the heavier injected
gas. Injected steam condenses and gravity drains downward while the
associated non-condensable gas accumulates around the point of
introduction, creating an insulating layer between the thermal
energy and the surrounding heat sinks or thief zones. The result is
that heat rises into the overlying heat sink, lessening thermal
losses to the underlying water zone. The gas and the steam can be
formed in-situ by a downhole burner. In another embodiment, the
lower zone is a hydrocarbon zone, steam being used both for lower
zone stimulation and for thermal heat transfer upward to the
overlying hydrocarbon zone.
BACKGROUND OF THE INVENTION
[0003] It is known to conduct enhanced oil recovery (EOR) of
hydrocarbons from subterranean hydrocarbon-bearing formations after
primary recovery processes are no longer feasible. Viscous, heavy
oil, including bituminous deposits, can be too deep for surface
recovery and in-situ methodologies are employed.
[0004] Thermal methods include such as in-situ combustion and steam
flood, which use various arrangements of stimulation or injection
wells and production wells. In some techniques the injection and
production wells may serve both duties. Other techniques include
cyclic steam stimulation (CSS), in-situ combustion and steam
assisted gravity drainage (SAGD). SAGD uses closely coupled
generally parallel wells, a horizontally-extending steam injection
well forming a steam chamber for mobilizing heavy oil for recovery
at a substantially parallel and horizontally-extending production
well. Thermal in-situ approaches are typically applied for oilsands
which are heavy and viscous, having a gravity of 8-10.degree. API
and viscosities ranging from 10,000 to 300,000 cp. Non-thermal
approaches include Cold Heavy Oil Production with Sand (CHOPS) in
which sand is co-produced with the heavy oil, the oil typically
having viscosities in the range of 500 to 15000 cp. In Alberta, the
Energy Resources Conservation Board (ERCB) has deemed or classified
heavy oils by gravity as an ERCB Crude Oil Density (See directive
17 http://www.ercb.ca/docs/documents/directives/Directive017.pdf,
as of October 2009, "crude bitumen wells and heavy oil wells
density of 920 kilograms per cubic metre [kg/m3] or greater at
15.degree. C."). This specific gravity of about 0.92 is equivalent
to about 22.3 API or heavier, while bitumen having a specific
gravity of about 1.0 has an API gravity of about 10.
[0005] Where a heavy oil formation overlies a water zone, where the
water forms a base of the formation, typically known as a basal
water zone, in-situ techniques become more limited, in part due to
the huge thermal heat sink of the water zone. One recovery approach
which incorporated the water zone in the recovery was implemented
by Shell Canada Limited and the Alberta Oilsands Technology and
Research Authority (AOSTRA) in the late 1970's and 1980's in the
Peace River leases of Alberta Canada. The approach was termed the
pressure-cycle steam drive (PCSD). The PCSD utilized steam
injection to heat the basal water zone underlying the oilsand. Once
communication was established between wells, continuous steam
injection was begun, with the injection and production rates
controlled to alternately pressure up and blow down the reservoir
(see Alberta Oil Sands Technology and Research Authority, AOSTRA
Technical Handbook on Oil Sands, Bitumens and Heavy Oils. Edmonton,
1989). Shell Canada Limited set forth a historical review of
resource recovery alternatives in their 2009 application to the
Energy Resources Conservation Board (ERCB) of Alberta, CANADA,
Carmon Creek Project. Reviewing their own PCSD concept, Shell
stated: "steam is injected into the bottom water zone (the lowest 4
m to 6 m of the 25 m-thick reservoir) at high injection rates and
pressures. Production rates at producers would vary between periods
of low and high rates. This caused cycles of high reservoir
pressure during low production rates and low reservoir pressure
during high production rates. Expectations were that steam would be
forced into the upper parts of the reservoir, and bitumen would be
produced by gravity drainage. These expectations were not met
during the large-scale development stage, and recovery was found to
be uneconomic."
[0006] Applicant understands that CSS techniques were subsequently
employed to continue exploitation of this resource. CSS in this
circumstance is still associated with difficulties. Typically, an
upper injection well, for injecting steam and forming a steam
chamber for mobilizing oil, and a lower producer well would have
been provided for collecting heated, mobilized oil. The producer
well is located about 5 m above the base of the oilsand formation
and the injector well another about 5 m above the producer well.
The location of the producer well, being about 5 m above the base,
is known to be an arrangement to avoid or delay breakthrough from a
thief zone or basal water zone. This also results in lost potential
to exploit this lower 5 m of what might only be a 15 to 25 m thick
zone. This and other thin payzones are still greatly
underexploited.
[0007] Applicant believes the expense of surface steam production,
only to be lost to the large heat sink of the water zone,
contributed to the discontinuance of this methodology.
[0008] Another well known issue with underlying water zones is the
tendency for water coning. The water, being more mobile,
preferentially migrates to the production well to the exclusion of
the oil resource.
[0009] Further, in thermal EOR, heat transfer to overburden has
conventionally been an unfortunate energy loss.
[0010] Applicant believes that in-situ processes to date have not
successfully accommodated due to energy losses and compromised as a
result of underlying water. Further, some formations have had
stimulation limited to cold production, such as heavy oil in
unconsolidated sand, which can be situated in payzones too narrow
for SAGD.
[0011] Improved techniques are required which recover more of the
resource and with favourable economics.
SUMMARY OF THE INVENTION
[0012] In one embodiment, a method of thermal EOR for subterranean
formation is provided comprising introducing thermal energy to a
lower zone which underlies a first oil formation in an upper zone.
Thermal energy, travelling upwardly through the lower zone, heats
this first oil formation from below. The heated oil become
mobilized for ready production from the upper zone.
[0013] In another embodiment, the lower zone might be isolated from
the upper zone by a substantially impermeable layer, such as a
caprock or shale layer. Accordingly, the thermal energy travels to
the upper zone by conduction, and production from the upper zone is
conventional or implements a drive to assist in the production of
the mobilized oil.
[0014] In another embodiment, the lower zone itself is a second oil
formation isolated from the upper, first oil formation. The thermal
energy received by the upper zone can be heat lost to the
overburden from a thermal EOR being conducted in the lower
zone.
[0015] A variety of known methodologies can be employed for
introducing thermal energy into the lower zone including SAGD
arrangements, steam injection, in-situ steam generation and
downhole burners.
[0016] In another embodiment, a method of thermal EOR is provided
comprising introducing gas and steam to a lower zone containing
basal water, both of which underlie an oil formation in an upper
zone. The heavier gas and lighter steam gravity separate to
stratify, forming an insulating layer of gas below a steam layer.
Accordingly, the steam is insulated from the substantially infinite
heat sink of the basal water wherein the steam transfers a
predominate fraction of its thermal energy upwardly to the oil
formation thereabove. As above, the thermal energy heats the oil,
reducing its viscosity, and mobilizing the oil for production.
Where the lower zone is in communication with the upper zone, the
steam also serves to drive the mobilized oil to one or more
production wells spaced laterally from the location of introduction
of the steam. Basal water in the lower zone is progressively driven
radially outward, forming a bowl-like interface or inverted cone,
exposing ever greater areas of the upper zone to thermal energy. As
the steam condenses, the greater density of the condensed water
causes it to percolate down through the gas layer to the underlying
basal water. In an embodiment, the one or more production wells are
completed within the oil formation. In another embodiment, one or
more of the temperature, viscosity, or gas is monitored for
detection of, location of, or extent of oil mobilization and the
one or more production wells are correspondingly completed within
the oil formation where the oil has been mobilized. The production
wells can be re-completed at different elevations as the
mobilization conditions change.
[0017] In another embodiment, one or both of the first or second
oil formations are heavy oil formations. In another embodiment, the
oil formations are oilsand formations. In another embodiment, oil
formation is an oilsand formation too thin for conventional
exploitation using SAGD. In another embodiment, and as a source of
thermal energy, gas and steam are introduced into the lower zone
from the operation of a downhole burner. In another embodiment, the
downhole burner produces high temperature, hot CO.sub.2 gas, and
steam is created by the interaction of the hot gas and water, the
water being selected from in-situ basal water or injected
water.
BRIEF DESCRIPTION OF THE DRAWINGS
[0018] FIG. 1 is a schematic of a thermal injection well completed
in a lower water zone according to a first embodiment;
[0019] FIG. 2 illustrates a thermal injection well in a lower water
zone, development of a gas/water insulating layer and optimized
thermal stimulation and mobilization;
[0020] FIGS. 3A through 3C illustrate various completions over
time, or different spacing, for optimal recovery of mobilized
oil;
[0021] FIG. 4 is a schematic illustration of a thermal process in
an underburden zone, for transfer of thermal energy from that
process to be received at an upper hydrocarbon zone for Thermal
EOR;
[0022] FIG. 5 is a schematic illustration of a thermal EOR in a
lower hydrocarbon zone and thermal energy of that process received
at an upper hydrocarbon zone for thermal EOR;
[0023] FIG. 6A is a schematic illustration of another embodiment
having a steam EOR, such as SAGD, in a lower hydrocarbon zone and
thermal energy of that SAGD received at an upper hydrocarbon zone
for thermal EOR; and
[0024] FIG. 6B is a schematic illustration of another thermal
process conducted in a first underburden zone underlying a second
and lower hydrocarbon zone, a second thermal process for thermal
EOR, and a third and overlying upper hydrocarbon zone for thermal
EOR.
DESCRIPTION OF EMBODIMENTS OF THE INVENTION
[0025] In a broad embodiment, heat of thermal energy is introduced
to a lower zone for delivering heat to an overlying upper zone
having at least a first oil formation which benefits from a heated
formation, including heavy oil suitable for enhanced oil recovery
(EOR). The lower zone can be underburden, even including a water or
basal zone, or can be another zone undergoing EOR.
[0026] In one embodiment, this first oil formation is a heavy oil
zone unsuitable for SAGD for one reason or another, including being
too narrow or shallow to accommodate parallel injection and
production wells, can benefit from thermal stimulation as disclosed
therein. One such form of formation is one produced using Cold
Heavy Oil Production with Sand or CHOPS. In conventional CHOPS, oil
is co-produced with formation sand with the formation of
"wormholes" in the sand formation which allows more oil to reach
the production wells. As Applicant understands the mechanism, a low
pressure area is created near the production wells, typically using
progressive cavity pumps. Solution gas phase changes into a vapour,
fluidizes oil and sand that flows into the low pressure area and is
produced. In Alberta, Canada, co-production of sand, wormholes and
fluidization produces between 3% to 8% of the original oil in
place. Further, Applicant believes the existence of wormholes,
prevalent in an upper portion of the formation, can contraindicate
use of steam enhanced recovery as the wormholes can preferentially
channel steam away from target oil.
[0027] However, Applicant notes that introducing an additional
factor, by creating a foamy oil drive by increasing the temperature
by a few degrees, is heretofore unknown in CHOPS production.
Herein, a Stimulated Foamy Oil Drive (SFOD) is applicable to virgin
or depleted fields with appropriate reservoir conditions. The
process can enhance and extend the life of wormhole development.
The SFOD process stimulates the first oil formation by subjecting
the target reservoir to heat from below, which is received from the
underburden or lower zone. This creates a generally linear
contiguous temperature increase within the overlying target
formation which enhances solution gas release from the liquid
oil/water phase. Any source delivering thermal energy to the bottom
of the reservoir underburden will facilitate the process. Solution
gas is stimulated to disassociate from the fluid state by raising
the temperature, enhancing the original drive and recovery
mechanisms to a predominant temperature drive. Herein, if a thermal
EOR project is already implemented in a lower zone, waste heat will
drive the process in the upper zone.
[0028] As the overlying heavy oil reservoir responds to the thermal
propagation, a foamy oil drive is created which flows through a
network of worm-holes into a gathering system of production wells.
As voidage is created, and the network of high permeability
channels (wormholes) expands, breakthrough occurs which creates a
network. Over time, production shifts to a free flowing gravity
drain exploitation. The wormhole network grows as the process
mobilizes oil, creating voidage which provides a route for bypassed
virgin oil to flow into the production wells.
[0029] Applying SFOD to depleted CHOPS reservoirs will extend the
life of the field, resulting in an increase in oil recovery. For
optimal advantage, certain geological and reservoir conditions can
dictate which formations are candidates for underburden thermal
stimulation. Ideally the lower zone is a second oil formation
capable of supporting a thermal EOR project and which happens to be
separated from the first oil formation of the upper zone by a low
to non-permeable layer or caprock. The target zone is one suitable
for supporting a foamy oil drive.
[0030] Having reference to FIG. 4, one can see a general embodiment
utilizing underburden heat for thermal stimulation of an overlying
target formation. This overlying or upper zone 10 contains a first
heavy oil formation suitable for CHOPS production which overlies a
lower zone 12. Heat is provided to the lower zone 12 from a thermal
source 14, such as using steam injection from a steam injection
well, in-situ-steam generation or using a greater energy source
such as that from operating a downhole burner for hot combustion
gas and steam formation. One form of downhole burner is set forth
in PCT publication WO 2010/081239, published Jul. 22, 2010, for the
production of steam and combustion gases. Particularly, where the
upper zone 10 is isolated from the lower zone 12 by a substantially
non-permeable strata or layer 16, thermal energy Q from the process
occurring in the lower zone 12, is transferred upwardly through
conduction, in this case into the upper zone 10. Heavy oil 20 in
the upper zone 10 is mobilized, such as through SFOD, and produced
at production wells 22 completed into the upper zone 10. In the
lower zone 12, water or emulsion can be removed as necessary using
recovery wells 24 completed in the lower zone 12 and at locations
spaced laterally from the thermal source 14.
[0031] Having reference to FIG. 5, one can see another embodiment
utilizing underburden heat for a first thermal stimulation of an
overlying target or upper zone 10, while performing a second
thermal stimulation in a lower zone 12. A first oil formation in an
upper zone 10 overlies a second oil formation in the lower zone 12.
Heat is provided to the lower zone 12, in this instance also being
a hydrocarbon zone receiving thermal stimulation. In this
embodiment, heat can be provided via a SAGD arrangement having at
least a steam injection well and a producer well for thermal
stimulation and production from that lower zone 12. The lower zone
12 may be appropriate for SAGD including having sufficient
thickness and geology. If not appropriate, such as being deemed too
thin or shallow to accept conventional SAGD injection and producer
wells due to minimum spacing requirements and the like, then such
concerns are alleviated using a thermal source 14 such as steam
injection, in-situ-steam generation or using a greater energy
source such as that from a downhole burner. One form of downhole
burner is set forth in PCT publication WO2010/081239, published
Jul. 22, 2010 to Schneider et al. A thermal source 14, in the form
of a steam injector can be a vertical or horizontal steam injector
or one or more horizontal in-situ steam generators which traverse
the zone coupled with one or more vertical or horizontal producers
24 arranged for collection of mobilized oil from the lower zone 12.
Regardless of the means for thermal-enhanced oil recovery in the
lower zone, the thermal energy Q, which would otherwise be lost, is
now recovered by a heating of the upper zone 10, in this case the
upper heavy oil zone.
[0032] Thermal energy from the process occurring in the lower zone
12 is transferred by conduction, through the substantially
non-permeable layer 16, and into the overlying, heavy oil upper
zone 10. Heavy oil 20 in the upper zone 10 is mobilized and
produced therefrom. Mobilized oil, water, oil or emulsion can be
removed as necessary using the producers or recovery wells 24
completed in the lower zone 12, spaced from the thermal source
14.
[0033] Having reference to FIG. 6A one can see several other
embodiments including a general embodiment, similar to that of FIG.
5, in which a thermal source 14 such as SAGD, via a horizontal
steam injection well 30 stimulates thermal mobilization of oil 36
for recovery by a horizontal producer well 31, both of which are
completed in the lower zone 12. Steam 34 from the thermal source 14
or injection well 30 provides heat Q1 to the upper zone 10 for
mobilizing oil 20 for collection at the horizontal producer well
31. The residual waste heat or thermal energy Q1 is conducted
upwardly for secondary stimulation of heavy oil 20 in the upper
zone 10.
[0034] Having reference to FIG. 6B one can see that several zones
can be stimulated using a variety of combinations of thermal
sources in underlying zones. As shown in FIG. 6B, a first and
deepest source 44 of thermal energy Q2 is a downhole burner and
steam generation process such as that detailed in WO 2010/081239 to
Schneider et al. Heat Q2 from that deepest process is received by a
second, overlying lower zone 12. The heat Q2 received by the lower
zone 12 is supplemented by a second source 14 of thermal energy Q1,
such as a steam EOR process, located in the lower zone 12. A steam
EOR process can include SAGD having horizontal injection well 30
and horizontal producer well 31. The thermal energy Q1 from the
second thermal source 14 and residual heat Q2 from the first
thermal source 44 are received by a third, upper zone 10 for
thermal EOR.
Basal Water Zones
[0035] As shown in FIG. 1, in another embodiment, an oil formation
or upper zone 110 overlies and is in communication with an
underlying zone containing basal water 112 such as an underlying
base or basal water zone 113, characteristic of some areas in
Alberta, Canada.
[0036] Heavy oil formations benefit most from the embodiments
disclosed herein including forms of oil typically recovered using
the thermal methods and non-thermal methods described above. The
basal water zone 113 is accessed and means are completed for
introducing hot non-condensable gases into the water zone. The term
non-condensable means the gases are non-condensable at the
formation conditions. The term "introducing" includes injecting at
a point, such as an injection well 114, into the formation or
generation at a point in the formation, such as at a downhole tool
115 situated in the formation. The non-condensable gases can be hot
gases which include products of combustion, such as carbon dioxide
CO.sub.2 which are introduced hot or are formed downhole, such as
by a downhole combustor. The pressure injection (Pinj) will be
greater than the pressure in the basal water zone (Pbw) and the
pressure Pbw in basal water zone 113 will be greater than the
pressure in the heavy oil formation Poil. Pressure management can
assist with the drive and avoiding gravity drainage of mobilized
oil.
[0037] Mobility of the heavy oil 120 is poor at initial, in-situ
temperature conditions. According, the heavy oil 120 initially
forms a low permeability barrier, and hot gases 117, injected into
the basal water zone 113, displace the water 112 radially and
laterally from the point of introduction, such as the injection
well 114, creating a bowl-like interface or inverted cone of rising
hot gases 117. The hot gases 117 impart sufficient energy to create
steam 116, either from the water 112 in the water zone 113 or
injected water. Water is introduced for mixing with the hot gases,
or connate water or basal water is heated by the hot gases,
creating steam 116. The steam 116 and the hot gases 117 flow out
into the basal water zone 113.
[0038] Where the hot gas is CO.sub.2, the density of the hot gas,
at the same downhole pressure and temperature conditions, is
several times greater than the density of the steam. Further, the
mobility of hot CO.sub.2 through the reservoir is less than the
steam. Accordingly, the steam 116 tends to gravity separate from
the hot gas 117 or CO.sub.2 and stratify, the heavier CO.sub.2
migrating downward and steam migrating upward. The CO.sub.2 forms
an insulating layer 119 between the basal water 112 and the steam
116.
[0039] Thus the steam 116 rises to contact the overlying heavy oil
bearing zone 110, transferring thermal energy Q, as a result of the
water's latent heat of vaporization, preferentially to this
overlying upper zone 110 as the steam condenses and accordingly
heat loss to the basal water 112 is minimized. As steam condenses
to water, the water's greater density causes it to percolate down
through the CO.sub.2 layer and join or mix in with the basal water
112.
[0040] Thus transfer of thermal energy Q is maximized to the
overlying heavy oil formation 110 and heat loss is minimized to the
heat sink of the basal water 112 in the basal water zone 113. In
contradistinction, in the prior art PCSD and conventional steam
flood processes, introduced heat is designed to flow to the basal
water.
[0041] As shown in FIG. 2, the mobilized oil 120 is displaced in a
steam or gas drive towards the production wells 122.
[0042] At original formation conditions the heavy oil can be very
viscous, having a viscosity up to the hundreds of thousands of
centipoise (cp), being intractable and immobile and unrecoverable
using conventional means. In comparison, water has viscosity less
than 1 cp. Using a steam 116 and hot gas 117 layer embodiment,
having an insulating layer 119, heat Q is now effectively
transferred to the heavy oil formation of the upper zone 110. At
steam condensation temperatures, the heavy oil viscosity can drop
many orders of magnitude and into the hundreds or tens of
centipoise, being recoverable using known production well
techniques. As heavy oil mobility in the heavy oil formation
increases, steam continues to be effectively directed higher and to
ever greater radial extent in the heavy oil formation.
[0043] As shown in FIG. 2, one or more production wells 122, or an
array of production wells 122, recover mobilized heavy oil 120 from
locations in the upper zone 110 spaced laterally from the injection
well 114 completed in the lower zone 113. A variety of production
scenarios are possible and which can vary over the life of the
mobilization.
[0044] As shown in FIGS. 3A, 3B and 3C, and in one embodiment, the
production well or wells are completed in the heavy oil formation
or upper zone 110. As water can be more than 100 times more mobile
than the oil, and there is effectively an infinite reserve of
water, one would typically avoid completion in the basal water zone
113 to avoid a high water fraction in the produced fluid and,
further, one would complete high enough in the heavy oil formation
to avoid water-coning.
[0045] In one embodiment, one can track wellbore temperature and
complete or perforate the production well 122 to place perforations
130 in the oil formation according to an oil mobility or thermal
profile. The well 122 can be re-completed (FIG. 3B, 3C) to place
perforations 130 higher in the well 122 as the thermal profile
changes over time. Alternate means for sensing a change in oil
mobility adjacent the production well 122 includes neutron logs or
measuring gas effect.
[0046] In another embodiment, one would perforate high in the oil
zone 110 and rely on bottom water drive to push the mobilized oil
up to the production well 122. In another scenario, one might
perforate in the middle of the oil zone 110 and rely on a
horizontal pressure gradient to push the oil to the production
well. And in another scenario, one could operate the hot gas and
steam generator injector cyclically. After injection stops, all of
the steam will eventually condense and the CO.sub.2 migrates to the
top of the oil zone forming a gas cap. In this case one could then
perforate low in the oil zone 110 and rely on the gas cap to drive
the oil to the production well. Any of the scenarios could be used
at different stages of the formation or reservoir depletion.
[0047] The injection well 114 can inject hot gas, of hot gas and
water as water or as steam, or constituents which result in the
production of hot gas and steam.
[0048] One method and apparatus for downhole production of heat in
the form of steam and hot combustion gases (primarily CO, CO.sub.2,
and H.sub.2O) is set forth in Applicant's co-pending patent
application for apparatus and methods for downhole steam generation
and enhanced oil recovery (EOR). The downhole steam generator was
filed Jan. 14, 2010 in Canada as serial number 2,690,105 and in the
United States published Jul. 22, 2010 as US 2010/0181069 A1, the
entirety of both of which are incorporated herein by reference.
[0049] In Applicant's co-pending downhole steam generation and EOR,
a downhole burner assembly is fluidly connected to a main tubing
string, and is positioned within a target zone. The burner assembly
creates a combustion cavity by combusting fuel and an oxidant at a
temperature sufficient to melt the reservoir or otherwise create a
cavity. The burner assembly then continues steady state combustion
to create and sustain hot combustion gases for flowing and
permeating into the target zone for creating a gaseous drive front.
Water is injected into the target zone, uphole of the combustion
cavity for creating a steam drive front. Therein, the burner
assembly could be positioned within a cased wellbore at the target
zone, the burner assembly having a high temperature casing seal
adapted for sealing a casing annulus between the downhole burner
and the cased wellbore, and a means for injecting water into the
target zone above the casing seal. The high temperature casing seal
can pass through casing distortions, and is reusable, not being
affected substantially by thermal cycling.
[0050] A combustion chamber can be formed operating the burner
assembly at a temperature sufficient enough to melt the formation
of the target zone. Thereafter, steady state combustion is
maintained for sustaining a sub-stoichiometric combustion of the
fuel and oxygen for producing hot combustion gases (primarily CO,
CO.sub.2, and H.sub.2O) which enter and permeate through the target
zone. The hot combustion gases create a gaseous drive front and
heat the target zone adjacent the combustion cavity and the
wellbore. Addition of water to the target zone along the casing
annulus above the combustion chamber injects water into an upper
portion of the target zone adjacent the wellbore for lateral
permeation therethrough. The lateral movement of the injected water
cools the wellbore from the heat of the hot combustion gases and
minimizes heat loss to the formation adjacent the wellbore. The
water further laterally permeates through the target zone and
converts into steam. The steam and the hot combustion gases in the
target zone form a steam and gaseous drive front.
[0051] Applied in the context of the basal water displacement
scenario, and in an embodiment of the present invention, the use of
a downhole burner and in-situ generation of steam meets both
objectives of producing a hot gas, containing CO.sub.2, and
generation of steam 116, either through reaction of the energy from
the downhole burner and the basal water or the reaction of the
energy from the downhole burner and added water. One can anticipate
employing the addition of water, such as through the casing
annulus, once the basal water is further and further displaced from
the injection well.
[0052] In another embodiment, also represented graphically by FIG.
1, a first oil formation in an upper zone 110 overlies a
non-hydrocarbon-bearing, underburden or other lower zone such as
basal water zone 113. The lower zone is accessed and means 114 are
completed for introducing non-condensable gases 117 into the lower
zone. Again, the term "non-condensable" means the gases are
non-condensable at the formation conditions. The non-condensable
gas also has a higher density than that of the steam. The
non-condensable gases can include products of combustion, such as
carbon dioxide CO.sub.2 which are introduced hot or are formed
downhole, such as by a downhole combustor. The non-condensable gas
117 can also be other available gas such as nitrogen (N.sub.2).
Carbon Dioxide and N.sub.2 are heavier than steam 116 and will pool
or form an insulating bubble or layer 119 below the injected steam
116. For example, where the heavier gas is CO.sub.2, the density of
the gas, even at hot conditions such as combustion, steam
generation or injection, are several times greater than the density
of the steam. Further, the mobility of CO.sub.2 through the
formation is less than the steam.
[0053] Accordingly, the steam 116 tends to separate from the
CO.sub.2, the heavier CO.sub.2 migrating downward and steam
migrating upward. The CO.sub.2 forms an insulating bubble or layer
between the underlying zone and the steam thereabove. Thus the
steam 116 rises to contact the overlying heavy oil bearing zone
110, transferring the water's latent heat Q of vaporization to this
zone as the steam 116 condenses and heat loss to the underlying
zone 113 or basal water 112 is minimized. As the water from the
steam/heavy oil interface condenses, its greater density causes it
to percolate down through the CO.sub.2 layer to the lower zone and,
in the case of a basal water zone 113, to join or mix in with the
basal water 112.
[0054] Advantageously, industrially-produced CO.sub.2, such as that
earmarked for carbon capture, storage or sequestration can be
injected from surface for forming the gas bubble or insulating
layer 119 at the lower layer and buoying steam 116 thereabove for
heat transfer Q to the overlying zone 110.
* * * * *
References