U.S. patent application number 11/490257 was filed with the patent office on 2008-01-24 for in situ process to recover heavy oil and bitumen.
This patent application is currently assigned to Paramount Resources Ltd.. Invention is credited to Gary Bunio, Ian Donald Gates.
Application Number | 20080017372 11/490257 |
Document ID | / |
Family ID | 38970347 |
Filed Date | 2008-01-24 |
United States Patent
Application |
20080017372 |
Kind Code |
A1 |
Gates; Ian Donald ; et
al. |
January 24, 2008 |
In situ process to recover heavy oil and bitumen
Abstract
An in situ reservoir recovery process consisting of a horizontal
injection well and a horizontal production well to extract bitumen
or heavy oil from a reservoir. The process consists of a first
phase operated at high-pressure in which steam, hydrocarbon solvent
and non-condensable gases are injected into the reservoir and a
second phase in which the injected fluids are transitioned to a
high content of solvent and non-condensable gas and a reduced
amount of steam to maintain a warm zone in the neighbourhood of the
injection and production wells. The steam injection is sufficient
to promote vapor transport of the solvent into the vapor depletion
chamber and maintain the process at elevated temperatures in order
to maintain low fluid viscosities in the production wellbore and to
achieve preferred phase behaviour of the solvent hydrocarbon and
the heavy oil or bitumen. The operating pressure of the process is
controlled to prevent losses of the solvent hydrocarbon to the
formation and to aid in solvent production to the production well
in order for future re-cycling.
Inventors: |
Gates; Ian Donald; (Calgary,
CA) ; Bunio; Gary; (Calgary, CA) |
Correspondence
Address: |
OGILVY RENAULT LLP
1981 MCGILL COLLEGE AVENUE
SUITE 1600
MONTREAL
QC
H3A2Y3
CA
|
Assignee: |
Paramount Resources Ltd.
Calgary
CA
|
Family ID: |
38970347 |
Appl. No.: |
11/490257 |
Filed: |
July 21, 2006 |
Current U.S.
Class: |
166/254.1 ;
166/272.3; 166/272.4; 166/272.7 |
Current CPC
Class: |
E21B 43/16 20130101;
E21B 43/2408 20130101 |
Class at
Publication: |
166/254.1 ;
166/272.4; 166/272.3; 166/272.7 |
International
Class: |
E21B 47/00 20060101
E21B047/00; E21B 43/24 20060101 E21B043/24; E21B 43/22 20060101
E21B043/22 |
Claims
1. A method for recovering heavy hydrocarbons from an underground
reservoir containing heavy hydrocarbons, an injection well and a
production well, comprising: a) injecting steam into said reservoir
to form a steam vapor chamber; b) co-injecting predetermined
quantities of non-condensable gas, hydrocarbon solvent and steam
into said steam vapor chamber to maximize solubility of the solvent
in said heavy hydrocarbons; c) recovering produced hydrocarbons
within said production well; d) controlling the volume of said
steam vapor chamber by progressively adjusting the volume of said
steam, said non-condensable gas and hydrocarbon solvent injected
into said reservoir, whereby said hydrocarbon solvent and
non-condensable gas are predominant relative to the volume of said
steam; and e) recovering further produced heavy hydrocarbons.
2. (canceled)
3. The method as set forth in claim 1, wherein in step c) reservoir
pressure is progressively increased.
4. The method as set forth in claim 3, wherein reservoir
temperature is progressively lowered
5. The method as set forth in claim 4, wherein solvent solubility
in said heavy hydrocarbons is increased.
6. The method as set forth in claim 5, further including recovering
said hydrocarbon solvent.
7. The method as set forth in claim 1, wherein said hydrocarbon
solvent comprises an alkane selected from the group consisting of
C3 through C8 alkanes and mixtures thereof.
8. The method as set forth claim 1, wherein said hydrocarbon
solvent comprises an alkane derived from gas condensate.
9. The method as set forth in claim 1, wherein said hydrocarbon
solvent comprises an alkane derived from gas diluent.
10. The method as set forth in claim 1, wherein said
non-condensable gas comprises a gas selected from the group
consisting of C1 through C3 hydrocarbons
11. The method as set forth in claim 10, wherein said
non-condensable gas comprises carbon dioxide.
12. The method as set forth in claim 11, wherein said
non-condensable gas comprises a gaseous component of flue gas.
13. The method as set forth in claim 1, wherein said
non-condensable gas is selected from the group consisting of C1
through C3 alkane hydrocarbons, carbon dioxide, a component of flue
gas, natural gas and combinations thereof.
14. A method for recovering heavy hydrocarbons from an underground
reservoir containing heavy hydrocarbons, an injection well and a
production well, comprising: a) injecting steam into said
reservoir, to form a steam vapor chamber; b) co-injectinag
predetermined quantities of steam, hydrocarbon solvent and
non-condensable gas into said steam vapor chamber to maximize the
solubility of the solvent in said heavy hydrocarbons; c) recovering
produced hydrocarbons through said production well; d) determining
the formation of said vapor chamber by calculating the ratio of
cumulative injected steam to cumulative hydrocarbon production
volume; e) adjusting te volume of steam injected into said vapor
chamber to be subordinate to the volume of hydrocarbon solvent and
non-condensable gas whereby partial pressure of said steam in said
chamber is reduced and hydrocarbon solvent solubility is elevated
in said heavy hydrocarbons; and f) recovering further produced
hydrocarbons through said production well.
15. (canceled)
16. The method as set forth in claim 14, further including the step
of selecting the quantity of steam, non-condensable gas and
injection pressure to maximize the solubility of hydrocarbon
solvent in said heavy hydrocarbons.
17. (canceled)
18. The method as set forth in claim 14, further including
recovering said hydrocarbon solvent.
19. A method for recovering heavy hydrocarbons from an underground
reservoir containing heavy hydrocarbons, an injection well and a
production well, comprising: a) injecting steam into said
reservoir, to form a steam vapor chamber, b) co-injecting
predetermined quantities of steam, hydrocarbon solvent and
non-condensable gas into said steam vapor chamber to maximize the
solubility of the solvent in said heavy hydrocarbons, while
controlling the volume of said vapor chamber; c) recovering
produced hydrocarbons through said production well; d) adjusting
the volume of steam injected into said vapor chamber to be
subordinate to the volume of hydrocarbon solvent and
non-condensable gas whereby partial pressure of said steam in said
chamber is reduced and hydrocarbon solvent solubility is elevated
in said heavy hydrocarbons; and e) recovering further produced
hydrocarbons through said production well.
Description
FIELD OF THE INVENTION
[0001] The present invention relates to a method to improve heavy
oil and/or bitumen recovery from a hydrocarbon reservoir. The
invention, in particular, relates to a process in which steam,
solvent and non-condensable gas injection rates and pressure into
an injection well are phased throughout the process to achieve
improved thermal efficiency, mobilization of heavy oil and/or
bitumen within the hydrocarbon reservoir and improved solvent
recovery.
BACKGROUND OF THE INVENTION
[0002] There are many methods that are used to recover in situ
heavy oil or bitumen from oilsands reservoirs. Typically, in situ
methods are used in heavy oil or bitumen deposits that are greater
than about 70 m deep where it is no longer economic to recover the
hydrocarbon by current surface mining technologies. Depending on
the operating conditions of the in situ process and the geology of
the heavy oil or bitumen reservoir, in situ processes can recover
between about 25 and 75% of the initial hydrocarbon in the
reservoir. For most heavy oil or bitumen recovery processes, the
focus of the process is to reduce the in situ viscosity of the
heavy oil or bitumen so that its mobility rises to a sufficient
amount so that it can flow from the reservoir to a production
wellbore. The reduction of the in situ heavy oil or bitumen can be
achieved by raising the temperature and/or dilution with solvent
which is the typical practice in existing processes for recovering
heavy oil or bitumen.
[0003] The Steam Assisted Gravity Drainage (SAGD), as described in
U.S. Pat. No. 4,344,485, issued Aug. 17, 1982, to Butler, is a
relatively popular in situ recovery method which uses two
horizontal wells positioned in the reservoir to recover
hydrocarbons. In this process, the two wells are drilled
substantially parallel to each other by using directional drilling.
The bottom well is the production well and is typically located
just above the base of the reservoir. The top well is the injection
well and is located roughly between 5 and 10 m above the production
well. The top well injects steam into the reservoir from the
surface. In the reservoir, the injected steam flows from the
injection well and forms a vapor phase steam chamber that as the
process evolves grows vertically until it reaches the top of the
reservoir. The steam loses its latent heat to the cool heavy oil or
bitumen at the edges of the steam chamber and as a result raises
the temperature of the heavy oil or bitumen. The viscosity of the
heated heavy oil or bitumen at the chamber edge drops and flows
under gravity down the edges of the chamber towards the production
wellbore located below the injection well. The fluids that enter
the wellbore are moved, either by natural pressure forces or by
pump, to the surface. The thermal efficiency of SAGD is reflected
in the steam (expressed as cold water equivalent) to oil ratio
(SOR) that is CWE m3 steam/m3 oil. Typically, a process is
considered thermally efficient if its SOR is between 2 and 3 or
lower. There is extensive published literature concerning the
successful design and operation of SAGD. The literature reveals
that while SAGD appears to be technically effective at producing
heavy oil or bitumen to the surface, there is a continued need for
processes that improve the SOR of SAGD. The major capital and
operating costs of SAGD involve the facilities to generate steam
and re-cycle produced water back to the steam generators.
Additionally, there is a need to design processes that improve the
capital and operating costs of SAGD.
[0004] An extension of SAGD is the Steam and Gas Push (SAGP)
process developed by Butler (Thermal Recovery of Oil and Bitumen,
Grav-Drain Inc., Calgary, Alberta, 1997). In the SAGP process,
steam and a non-condensable gas are co-injected into the reservoir.
It is believed that the non-condensable gas provides an insulating
layer at the top of the steam chamber that improves the thermal
efficiency of the process. At present, it remains unclear what the
optimal amount of non-condensable gas that should be added to the
injected steam.
[0005] Examples of published literature describing drainage rates
for SAGD in field operations include: Butler (Thermal Recovery of
Oil and Bitumen, Grav-Drain Inc., Calgary, Alberta, 1997), Komery
et al. (Paper 1998.214, Seventh UNITAR International Conference,
Beijing, China, 1998), Saltuklaroglu et al. (Paper 99-25, CSPG and
Petroleum Society Joint Convention, Calgary, Canada, 1999), Butler
et al. (J. Can. Pet. Tech., 39(1): 18, 2000).
[0006] There are other examples of the processes that use
combinations of steam and solvents to recover heavy oil.
[0007] U.S. Pat. No. 4,519,454, issued May 28, 1985, to McMillen
teaches what is essentially a cyclic thermal-solvent process which
consists of first steam heating the reservoir to raise the
temperature by 40-200.degree. F. (22-111.degree. C.) and second
producing the reservoir fluids directly after heating. In the
heating stage, the injection temperature is kept below the coking
temperature. The production interval continues until steam
production occurs after which liquid solvent is injected into the
injection well so that an oil-solvent mixture is produced. At some
point, steam injection re-commences and another cycle of the
process starts.
[0008] Another example is seen in U.S. Pat. No. 4,697,642, issued
Oct. 6, 1987, to Vogel which describes a steam and solvent flooding
process in which steam and vaporized solvent are injected in a
stepwise manner to lower the viscosity of in situ hydrocarbons to
aid their production to the surface. Vogel teaches that the choice
of solvent is not considered critical and suggests that the solvent
should be a light, readily distillable liquid, such as gasoline,
kerosene, naphtha, gas well condensates, benzene, toluene,
distillates, that is miscible with the in situ hydrocarbons. There
are two issues about this process: first the process uses high
solvent to hydrocarbon ratio and second the solvents are typically
more valuable than the produced hydrocarbon. Both of these issues
adversely impact process economics.
[0009] In an extension of SAGD, Palmgren (SPE Paper 30294, 1995)
describes a process where high temperature naphtha replaces steam
in the SAGD process. However, given the value of naphtha, a
substantial amount of the injected naphtha is required to be
recovered for the process to be economic and compete with SAGD. A
similar extension of SAGD which uses solvent, called Vapor
Extraction (VAPEX), has been proposed as a commercial alternative
to SAGD. VAPEX, similar to SAGD, consists of two horizontal wells
positioned in the reservoir. The top well is the injection well
whereas the bottom well is the production well. In VAPEX, a gaseous
solvent (for example ethane, propane, or butane) is injected into
the reservoir instead of steam. The injected solvent condenses and
mixes with the heavy oil or bitumen and reduces its viscosity.
Under the action of gravity, the mixture of solvent and bitumen
flow towards the production well and are produced to the surface.
Due to absence of steam generation and water handling facilities,
capital costs associated with VAPEX facilities are lower than that
of SAGD. However, it is unclear how interwell communication is to
be established and how the process is to be operated in order to
make the process economic. Also there are unresolved issues on how
to prevent significant solvent losses to the reservoir which will
be vitally important for economic success of the process.
Additionally, the operating pressure range of VAPEX is limited
because of required condensation of the injected gaseous solvent at
the edges of the vapor chamber. In several papers, Butler and
Mokrys (J. Can. Pet. Tech., 30(1): 97, 1991; J. Can. Pet. Tech.,
32(6): 56, 1994) documented a version of VAPEX which uses hot water
and solvent vapor, for example propane, near its dew point in an
experimental Hele-Shaw cell to recover heavy oil. The solvent vapor
fills the vapor chamber and at the chamber edges, the solvent
dissolves into the heavy oil lowering the oil phase viscosity. The
reduced-viscosity oil flows at the chamber edges to the production
well located at the bottom of the formation. Butler and Mokrys,
supra, describe that the solvent is co-injected with hot water to
raise the reservoir temperature by between 4.degree. and 80.degree.
C. The hot water also re-vaporizes some of the solvent from the
heavy oil to create refluxing and additional utilization of the
solvent. Butler, in U.S. Pat. No. 5,607,016, issued Mar. 4, 1997,
to Butler, discloses a variant of VAPEX for recovering hydrocarbons
in reservoirs that are located on top of an aquifer. A
non-condensable displacement gas is co-injected with a hydrocarbon
solvent at sufficient pressure to limit water ingress into the
recovery zone. Butler and Jiang (J. Can. Pet. Tech., 39(1): 48,
2000) describe means to manage VAPEX in the field. In a paper,
Luhning et al. (CHOA Conference, Calgary, Canada, 1999) describe
the economics of VAPEX.
[0010] In a solvent-aided process, Canadian Patent No. 1,059,432
(Nenninger) discloses a method in which sub-critical solvent gas
maintained just below its saturation pressure, such as ethane or
carbon dioxide, is injected into the reservoir to lower the
viscosity of heavy oil.
[0011] In U.S. Pat. No. 5,899,274, issued May 4, 1999, to
Frauenfeld et al., a method is described that mobilizes heavy oil
by using a vapor mixture of at least two solvents whose dew point
corresponds to the reservoir temperature and pressure. The main
concern with this process is that the solvent mixture has to be
adjusted to fit the reservoir temperature and pressure.
[0012] Canadian Patent Number 2,323,029, issued Mar. 16, 2004, to
Nasr et al., describes the Expanding Solvent-SAGD (ES-SAGD) method
that comprises continuously co-injecting steam and an additive (one
or a combination of C1 to C25 hydrocarbons and carbon dioxide) into
the reservoir. The additive is chosen so that its saturation
temperature is in the range of about .+-.150.degree. C. of the
steam temperature at the operating pressure. After injection, a
fraction of the additive changes from vapor to liquid phase in the
reservoir. This patent teaches that the additive concentration in
the injected stream is between about 0.1% and about 5% liquid
volume.
[0013] In Canadian Patent Number 2,325,777, issued May 27, 2003, to
Gutek et al., a thermal-solvent process is disclosed called the
Steam and Vapor Extraction Process (SAVEX). This process has two
stages. First, steam is injected into an upper horizontal well
until the top of the steam chamber is between about 25 to 75% of
the distance from the injection well to the top of the reservoir or
the production rate of hydrocarbons from the reservoir is about 25
to 75% of the peak rate anticipated from the SAGD process. Second,
a solvent is injected in vapor phase into the steam chamber. The
solvent helps to reduce the viscosity of the heavy oil or bitumen
and permits additional recovery of heavy oil or bitumen.
[0014] Canadian Patent Application Number 2,391,721, issued Jun.
26, 2002, to Nasr, teaches a thermal-solvent process, referred to
as the Tapered Steam and Solvent-SAGD (TSS-SAGD) process, in which
a steam and/or hot water and a solvent (C1 to C30 hydrocarbons,
carbon dioxide; carbon monoxide and associated combinations) is
injected into the heavy oil reservoir. Initially, the injectant
composition has steam and water-to-solvent volume ratio greater
than or equal to about 1. As the process evolves, the steam and
water-to-solvent volume ratio is lowered, at least once, to a
different steam and water-to-solvent volume ratio greater than or
equal to about 1. The injected volume ratio of steam and liquid
water-to-solvent is reduced as the process evolves.
[0015] The literature contains many examples of attempts to recover
in situ heavy oil or bitumen economically yet there is still a need
for more thermally-efficient and cost-effective in situ heavy oil
or bitumen recovery technologies. The present invention provides a
method to recover heavy oil and/or bitumen from an underground
reservoir in a manner that is more thermally efficient and cost
effective than present methods.
SUMMARY OF THE INVENTION
[0016] The invention relates generally to a process to recover
hydrocarbons from an underground reservoir.
[0017] One object of one embodiment of the present invention is to
provide a method for recovering heavy hydrocarbons from an
underground reservoir containing heavy hydrocarbons, an injection
well and a production well, comprising injecting steam and
optionally at least one of non-condensable gas and hydrocarbon
solvent into the reservoir, receiving produced hydrocarbons within
the production well, progressively adjusting the volume of the
steam, the non-condensable gas and hydrocarbon solvent injected
into the reservoir, whereby the hydrocarbon solvent and
non-condensable gas are predominant relative to the volume of the
steam, and recovering further produced heavy hydrocarbons.
[0018] In one embodiment of the invention, a method is provided to
extract heavy oil or bitumen from a reservoir located underground.
The reservoir is penetrated by a horizontal wellpair that comprise
a top injection well and a bottom production well both being
substantially parallel to each other. In the method, steam,
solvent, and non-condensable gas are injected through the injection
well into the reservoir over time while reservoir fluids are
produced through the production well. The injected fluids enter a
vapor chamber that surrounds and extends above the injection well.
In the present invention, the injection rates and injection
pressure are controlled in order to minimize heat losses to the
overburden and maximize the action of the solvent in reducing the
viscosity of the heavy oil and/or bitumen. Additionally, the
operating pressure is controlled together with the relative amounts
of steam, solvent, and non-condensable gas to maximize the solvent
recovery from the process. The partial pressure of the solvent is
controlled in the vapor chamber as the process is evolved.
[0019] The solvent may be a hydrocarbon solvent that consists of
one or a combination of the C3+ hydrocarbons or any of the
components that may normally be found in gas condensates or
diluent. The non-condensable gas may include nitrogen gas, natural
gas methane, carbon dioxide, or the flue gas that results from the
combustion of a fuel.
[0020] The recovery method may include the additional step of
adjusting the injection pressure and relative amounts of steam,
solvent, and non-condensable gas to control the vapor chamber
temperature to enhance the solubility of solvents.
[0021] In an embodiment, the method may include recovering
additional solvent and heavy oil or bitumen from the reservoir
during a blowdown stage at the end of the process.
[0022] A further object of one embodiment of the present invention
is to provide a method for recovering heavy hydrocarbons from an
underground reservoir containing heavy hydrocarbons, an injection
well and a production well, comprising injecting steam into the
reservoir, to form a steam vapor chamber, co-injecting
predetermined quantities of steam, hydrocarbon solvent and
non-condensable gas into the steam vapor chamber to maximize the
solubility of the solvent in the heavy hydrocarbons, recovering
produced hydrocarbons through the production well, adjusting the
volume of steam injected into the vapor chamber to be subordinate
to the volume of hydrocarbon solvent and non-condensable gas
whereby partial pressure of the steam in the chamber is reduced and
hydrocarbon solvent solubility is elevated in the heavy
hydrocarbons, and recovering further produced hydrocarbons through
the production well.
[0023] Having thus generally described the invention, reference
will now be made to the accompanying drawings illustrating
preferred embodiments.
BRIEF DESCRIPTION OF THE DRAWINGS
[0024] FIG. 1A is a side view of a reservoir and horizontally
drilled wells during the initial start up phase of the process;
[0025] FIG. 1B is a cross-section of FIG. 1A;
[0026] FIG. 2 is a graph showing a sample injection profile
conforming to the process;
[0027] FIG. 2A is a graph showing a sample injection pressure
profile conforming to the process;
[0028] FIG. 3A is a side view of a reservoir and horizontally
drilled wells during the second phase of the process;
[0029] FIG. 3B is a cross-section of FIG. 3A;
[0030] FIG. 4 is a graph of the energy requirements of the SAGD,
ES-SAGD, and processes as indicated by the cumulative steam to oil
ratio over the time of production;
[0031] FIG. 5 is a graphical representation comparing bitumen
recovery of the SAGD, ES-SAGD, and processes as a function of
time;
[0032] FIG. 6 is a graphical representation comparing cumulative
solvent recovery of the ES-SAGD, and processes as a function of
time.
[0033] Similar numerals denote similar elements.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0034] With reference to the Figures, a phased heating and solvent
enhanced recovery process for recovery of in situ bitumen or heavy
oil is described. Broadly, the invention consists of a sequence of
fluid injection and operating pressure changes that results in
significantly improved heavy oil or bitumen production from a heavy
oil or bitumen reservoir.
[0035] Heavy oil and bitumen is a more viscous material compared to
light oils at in situ initial reservoir temperatures and pressures.
Also, at elevated temperatures, heavy oil and bitumen has higher
viscosity than lighter hydrocarbons such as solvent at the same
temperature. At even more elevated temperatures, even though heavy
oil and bitumen remains in liquid state, the solvent can be in the
gaseous state and freely move throughout the reservoir providing
there is a driving pressure gradient to motivate the solvent
motion. The amount of solvent that can dissolve in heavy oil or
bitumen depends on the reservoir temperature and pressure. There
are two means to deal with the effectiveness of a heavy oil or
bitumen solvent to produce heavy oil or bitumen to a production
wellbore: first, the solvent must be chosen to substantially match
the reservoir pressure and temperature to maximize its
effectiveness in the targeted heavy oil or bitumen and second,
change the operating conditions, i.e. the operating pressure and
temperature, in order to control the solvent effectiveness in the
heavy oil or bitumen. The temperature of the depletion zone from
which heavy oil and bitumen are being extracted can be controlled
by injecting saturated steam into the formation.
[0036] In gravity-drainage processes, there is a requirement to
form a vapor chamber in the reservoir. This is to produce the
density contrast between the vapor and liquid which allows the
gravity-induced flow of liquid to the lower portion of the vapor
chamber where a production well is located. The production well
then removes the liquid from the chamber and carries it to the
surface. The heavy oil and bitumen drains at the edges of the
chamber, expanding the chamber in the reservoir. It is also
required to expand the chamber to ensure that fresh heavy oil and
bitumen is accessed by injected steam and solvent as the process
evolves and to manage the operating pressure in the chamber so that
solvent carried to the chamber edge mixes and dissolves in the
heavy oil and bitumen so that the viscosity of the heavy oil and
bitumen is reduced.
[0037] It should be noted that when referring to volumes of
solvent, volumes are specified as the ratio of liquid hydrocarbon
solvent to total liquid injected, and steam volume is expressed in
terms of the volume of cold water required to produce the steam
volume. In accordance with this invention, as shown in FIGS. 1A and
1B, a horizontal production well 10 is drilled into a reservoir 12
penetrating the surface of the earth 14 and the overburden 16. The
reservoir 12 is bounded by the bottom of the overburden 16 and the
top of understrata 18. Above the reservoir 12 is overburden 20
which consists of any one or more of shale, rock, sand layers, and
other formations such as aquifers. A horizontal injection well 22,
positioned several meters above in vertical alignment with a
production well 24 is also drilled into the reservoir 12. In the
present methodology, steam and solvent, injected through the
injection well 22 into the reservoir 12, flow from the injection
well 22 into a vapor chamber 26 which develops during this,
surrounding the injection well 22. By injecting the fluids supra
into the reservoir 12, heat and pressure are transmitted to the
reservoir 12. The steam and solvent eventually reach the edge of
the vapor chamber 26 and contact the virgin heavy oil or bitumen
oil sand denoted by numeral 28. The steam releases its latent heat
and the solvent dissolves into the oil, both of which reduce the
viscosity of the heavy oil or bitumen which in turn, under the
action of gravity, mobilizes the viscosity-reduced heavy oil or
bitumen to flow to the production well 10 which carries it to the
surface 14 by known techniques.
[0038] In FIG. 2, a typical injection and production profile for
steam 30, solvent 32, and non-condensable gas 34 is displayed. At
the start of the process, in stage 1, steam 30 is the major
injectant flowing into the reservoir 12 from the injection well 22
that penetrates the reservoir 12. In stage 1, the vapor chamber 26
is created in the reservoir 12. Also, as shown in FIG. 2A, the
injection pressure, 8 is maintained as sufficient to create the
vapor chamber in the reservoir.
[0039] In stage 1, a small amount of solvent 32 or non-condensable
gas 34 can be co-injected with the steam 30 but if desired, steam
30 can be injected alone into the reservoir 12 as is done in the
SAGD process. After the steam chamber has formed, in stage 2, steam
30, solvent 32, and non-condensable gas 34 are injected together
into the reservoir 12. One means of determining that a steam vapor
chamber has formed is the requirement that continuous production of
the heavy oil or bitumen is occurring and that the ratio of the
cumulative injected steam (expressed as cold water equivalent) to
cumulative heavy oil or bitumen production volume (this ratio is
called the cumulative steam to oil ratio, cSOR) is under the value
4. This value of the cSOR implies that the heat from the injected
steam is reaching the heavy oil or bitumen at the edges of the
chamber and that the mobilized bitumen is flowing under gravity
drainage to the production well.
[0040] The amounts of the steam 30, solvent 32, and non-condensable
gas 34 and the injection pressure are chosen so that the solubility
of the solvent in the heavy oil and bitumen 36 is maximized. The
addition of the solvent improves heavy oil or bitumen mobilization
beyond that only due to heating because it dissolves in the heavy
oil or bitumen, dilutes the hydrocarbon phase, and reduces its
viscosity so that it can readily flow to the production well 32. A
further benefit of solvent 30 addition to the hydrocarbon phase is
that it also dilutes the produced heavy oil or bitumen towards the
specifications of fluid flow and density properties required for
pipeline transport of the heavy oil or bitumen.
[0041] As the process evolves, the chamber 26 reaches the top of
the reservoir and thereafter spreads laterally as shown in FIGS. 3A
and 3B. As the chamber 26 grows, heat losses to the overburden 16
increase because the greater exposed area of the heated vapor
chamber 26 to the colder overburden 16. To enhance the thermal
efficiency of the recovery process, in stage 2, the steam 30
injection rate is lowered and the solvent 32 and non-condensable
gas 34 injection rates are raised. The solvent 32 content in the
injected fluids is between 1 and 80 volume percent, preferably
between 10 and 30 volume percent. The extent of the vapor chamber
26 is maintained by the increasing volume of solvent 31 and
non-condensable gas 32 injected into the reservoir 12.
[0042] Because the steam injection rate is reduced, the partial
pressure of the steam in the vapor chamber 26 falls and as a result
the corresponding saturation temperature of the steam drops and
heat losses from the vapor chamber 26, in turn, are reduced because
the temperature difference between the vapor chamber 26 and the
overburden 16 is lowered. If the overburden 16 temperature is
higher than the vapor chamber 26, then heat previously lost to the
overburden 16 is harvested back to the vapor chamber. This improves
the overall efficiency of the process. Furthermore, as the
temperature of the vapor chamber 26 falls, the solubility of the
solvent 32 increases in the heavy oil or bitumen 36. This leads to
reduced viscosity of the heavy oil or bitumen 36 that would not
have been possible without the solvent 32. Also, the addition of
the non-condensable gas 34 helps to maintain or raise the operating
pressure which also enhances the solubility of solvent 32 into the
heavy oil or bitumen 36. The relative amounts of the solvent 32 and
non-condensable gas 34 are chosen to maximize the effectiveness of
the solvent to reduce the viscosity of the heavy oil or bitumen and
can be chosen from thermodynamic pressure-volume-temperature (PVT)
and viscosity calculations.
[0043] The amount of injected solvent 32 is such that only
sufficient solvent is provided that is needed by the produced
bitumen. This minimizes the build-up and storage of solvent 32 in
the reservoir 12 which enhances the economic performance of the
recovery process. As the process further evolves, the amount of
solvent 32 and non-condensable gas 34 are reduced and
con-currently, the injection pressure is reduced. This helps to
promote production of the solvent 32 which enhances the economic
efficiency of the process. At the end of the process, a blowdown
stage (not shown) can be done to recover additional solvent and
heavy oil or bitumen from the reservoir 12. Heavy oil or bitumen
production from the production well is initiated during stage 1 and
continues throughout the rest of the process.
[0044] As the process evolves, the injection rates and injection
pressure is controlled to result in the most economical recovery of
heavy oil or bitumen and solvent 32.
[0045] The solvent 32 preferentially consists of one or a
combination of C3+ hydrocarbons, for example propane, butane,
pentane, hexane, heptane, octane, nonane, and decane or any one or
more components normally present in gas condensates or diluent.
Preferably, the solvent 32 is hexane or heptane, or is a
combination of C5 to C8 hydrocarbons including any of the
components that may normally be present in gas condensates or
diluent. The non-condensable gas 34 preferentially consists of C1
to C3 hydrocarbons, for example methane, ethane, and propane,
natural gas, or other gases such as carbon dioxide or any one or
more of the components normally present in the flue gas that
results from combustion of a fuel to produce steam.
[0046] The solvent 32, non-condensable gas 34, and injection
pressure are chosen so that the solvent 32 exist in substantially
the vapor state at the conditions of the reservoir but so that the
solubility of the solvent is maximized in the heavy oil or bitumen
at the edges of the chamber 26.
[0047] Computer-aided reservoir simulation models can be used to
predict pressure, oil, solvent, water, and gas production rates,
and vapor chamber 26 dimensions to help design the injection
strategy of the present invention. Also, the reservoir simulation
calculations can be used to assist in the estimation of the length
of stage 1 and 2 time intervals.
[0048] Given that the steam injection rate falls during the
process, the process yields reduced capital and operating costs
that arise from the activities surrounding steam 4 generation and
water handling. Also, given that the solvent is introduced directly
to the heavy oil or bitumen in the reservoir, there is inherent in
situ upgrading depending on the temperature and pressure evolution
of the process. Advantageously, due to solvent addition in the
reservoir, the amount of diluent needed to transport the heavy oil
or bitumen once it is on surface is reduced leading to reduced
surface facilities requirements. Thus, the process delivers equal
or more heavy oil or bitumen to currently known methods with higher
thermal efficiency and economic performance. With reduced steam
usage, the process also has less environmental pollution than
current thermal recovery processes such as SAGD.
[0049] FIG. 4 is a plot that compares the cumulative steam to oil
ratio (cSOR) from field scale numerical model predictions of the
SAGD, ES-SAGD, and the process of the present invention processes.
The cSOR is a measure of the thermal efficiency of the process and
is closely correlated with the economic performance of the recovery
processes. The cSOR SAGD results are typical of results found in
current field operations. The results show that for the majority of
the process life, the process of the present invention performance
is substantially greater than that of the SAGD and ES-SAGD
processes. FIG. 5 compares the cumulative oil produced (only
contains oil component, no solvent) for the SAGD, ES-SAGD, and
inventive processes. The results demonstrate that the process of
the present invention produces more oil than the other processes.
FIG. 6 displays a representation of the cumulative solvent recovery
of the ES-SAGD and the instant processes. The results show that the
injection rate and pressure strategy of the present process yields
significantly higher solvent recovery and thus higher economic
performance of the process.
[0050] The process operated as described has improved economic
benefit with relatively high production at the start of the
process, reduction of heat injection after the process starts to
lose heat to the overburden to improve thermal efficiency of the
process after the overburden is contacted, heated solvent injection
to deliver diluted and possibly partially upgraded heavy oil or
bitumen to the production wellbore, and high solvent re-cycling
capability to improve the economics of the process.
[0051] The embodiment(s) of the invention described above is(are)
intended to be exemplary only. The scope of the invention is
therefore intended to be limited solely by the scope of the
appended claims.
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