Note: Descriptions are shown in the official language in which they were submitted.
CA 02839070 2014-01-14
THERMAL HYDROCARBON RECOVERY METHOD
WITH NON-CONDENSABLE GAS INJECTION
Field of the Invention
The present invention relates to methods for hydrocarbon recovery from a
subsurface reservoir,
and specifically to recovery of heavy hydrocarbon deposits in fractured
reservoirs.
Background of the Invention
In the field of subsurface hydrocarbon production, it is known to employ
various stimulation
procedures and techniques to enhance production. For example, in the case of
heavy oil and
bitumen housed in subsurface reservoirs, conventional drive mechanisms may be
inadequate to
enable production to surface, and it is well known to therefore inject steam
or steam-solvent
mixtures to make the heavy hydrocarbon more amenable to movement within the
reservoir
permeability pathways, by heating the hydrocarbon and/or mixing it with
lighter hydrocarbons or
hot water.
Such heavy hydrocarbon deposits are sometimes located within naturally
fractured reservoirs.
Designing an optimal recovery method for extracting bitumen from such
naturally fractured
reservoirs can be tremendously challenging due to the structural complexity of
the reservoirs.
Generally speaking, in carbonate bitumen reservoirs, three different types of
tectonic fractures
have been noted: tension gashes, conjugate shears and extensional fractures.
The tectonic
fractures, with the exception of the short tension gashes, are dominantly sub-
vertical and form an
orthogonal system with parallel and/or perpendicular orientations. These
fractures are usually
consistent with the fractal-scale regional pattern that is due to basement
reactivation as
documented in the technical literature and as delineated with seismic ant-
trackings.
Cyclic steam stimulation (CSS) is one of the most promising thermal recovery
methods for
producing high viscosity oil or bitumen from naturally fractured reservoirs.
This oil recovery
method requires a predetermined amount of steam to be injected into a well or
wells drilled into
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the hydrocarbon deposit, which well or wells are then shut in to allow the
steam and heat to soak
into the reservoir surrounding the well and create what is known as a "steam
chamber". This
assists the natural reservoir energy by thinning the oil (or, in the case of a
steam-solvent
injection, also mixing the heavy hydrocarbon with lighter hydrocarbons) so
that it will more
easily move through the fractures in the reservoir and into the production
well or wells. Once the
reservoir has been adequately heated and the steam chamber has been created,
the production
wells can be put back into production until the injected heat has been mostly
dissipated within
the fluids being produced and the surrounding reservoir rock and fluids. This
cycle can then be
repeated until the natural reservoir pressure has declined to a point that
production is
uneconomic, or until increased water production occurs.
While steam injection is one of the most promising thermal recovery methods
for producing high
viscosity oil, reservoir fracturing due to existing massive fracture networks
presents a significant
challenge for building a steam chamber in the reservoir. Steam that is
intended to heat the
reservoir and hydrocarbon can instead travel far from the source (injector
well or wells) through
the fracture system. Even steam that remains in the vicinity of the injector
well(s) flows within
the massive fracture systems and is subject to enormous heat transfer and high
heat losses, such
that it condenses relatively quickly and loses most of its heat energy. In the
result, the heat
energy in the steam fails to impact the hydrocarbon deposit to enhance
production.
Summary of the Invention
The present invention is accordingly directed to heating the reservoir prior
to steam injection.
This heating stage employs a non-condensable gas.
Injecting heated non-condensable gas (NCG) prior to the steam injection (or
along with steam)
can be used to produce heavy oil or bitumen under viscosity reduction and
gravity drainage
methods, including from fractured carbonate reservoirs. In this novel method,
heated NCG (for
non-limiting example, nitrogen) is injected prior to or at the same time as
steam injection,
optionally in an otherwise typical CSS recovery method to heat the reservoir
rock and fluid
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(primarily rock) and improve the efficiency of the injected steam, with less
unwanted heat
transfer/loss.
According to a first aspect of the present invention, then, there is provided
a method for
recovering a hydrocarbon from a reservoir, the method comprising the steps of:
a. drilling at least one well from surface to the reservoir;
b. heating a volume of non-condensable gas to a target temperature;
c. injecting the non-condensable gas down the at least one well to the
reservoir;
d. allowing the non-condensable gas to heat the reservoir and the
hydrocarbon;
c. injecting steam down the at least one well to the reservoir;
f. allowing the steam to heat the reservoir and the hydrocarbon; and
a producing a portion of the hydrocarbon to the surface.
In some exemplary embodiments of the present invention, the hydrocarbon is
preferably a heavy
hydrocarbon, which heavy hydrocarbon may be heavy crude oil or bitumen. The
reservoir may
be composed primarily of carbonate material or non-carbonate elastic material,
and it may
include naturally occurring fractures. The at least one well may be a single
well used for both
injection and production, or it may comprise at least two wells, at least one
of which is an
injector well and at least one of which is a producer well. As indicated
above, the non-
condensable gas injection may occur before or concurrently with the steam
injection.
The non-condensable gas is preferably selected from the group consisting of
nitrogen, air,
methane and carbon dioxide, and it may be injected through the same well as
the steam or they
may be injected through separate wells. While pure oxygen could be used as the
NCG, it is not
preferable due to the combustion and corrosion risk. The target temperature is
preferably in the
range of 100 to 400 degrees Celsius. In exemplary embodiments, steps b.
through g. are to be
repeated as desired.
According to a second aspect of the present invention, there is provided a
method for recovering
a hydrocarbon from a reservoir having at least one injector well therein, the
method comprising
the steps of:
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a. injecting a heated non-condensable gas down the at least one injector
well to the
reservoir;
b. injecting steam down the at least one injector well to the reservoir;
c. producing a portion of the hydrocarbon to the surface; and
d. repeating steps a. through c. as desired.
According to a third aspect of the present invention, there is provided a
method for recovering a
hydrocarbon from a reservoir, the method comprising the steps of:
a. drilling at least one well from surface to the reservoir;
b. heating a volume of non-condensable gas to a target temperature;
c. injecting the non-condensable gas down the at least one well to the
reservoir at a desired
volume per unit time and for a desired period of time;
d. ceasing injecting of the non-condensable gas and allowing the injected
non-condensable
gas to heat the reservoir and the hydrocarbon;
e. injecting steam down the at least one well to the reservoir;
f. ceasing injection of the steam and allowing the steam to heat the
reservoir and the
hydrocarbon; and
a producing a portion of the hydrocarbon to the surface.
In exemplary embodiments of the third aspect of the present invention, the
target temperature is
preferably in the range of 100 to 400 degrees Celsius, although target
temperatures outside this
preferred range may have utility in a given context, and the desired volume
per unit time is
preferably in the range of 20 to 100 mmcfd, although a useful desired volume
per unit time may
fall outside this range in a given context. The desired period of time is
contextual and is directed
to process optimization, which would be within the knowledge of the skilled
person. Steps b.
through g. can be repeated as desired.
According to a fourth aspect of the present invention, there is provided a
method for building a
steam chamber in a fractured subsurface hydrocarbon reservoir having at least
one injector well
therein, the method comprising the steps of:
a. heating a volume of non-condensable gas to a target temperature;
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b. injecting the non-condensable gas down the at least one injector well to
the reservoir;
c. allowing the injected non-condensable gas to heat the reservoir and
hydrocarbon in the
reservoir;
d. injecting steam down the at least one injector well to the reservoir;
e. shutting in the at least one injector well and allowing the injected
steam to heat the
reservoir and the hydrocarbon in the reservoir; and
f. producing a portion of the hydrocarbon to the surface.
In exemplary embodiments of the fourth aspect of the present invention, the
method can
additionally comprise the step after injecting the non-condensable gas of
shutting in the at least
one injector well, followed by opening the at least one injector well before
injecting the steam.
A detailed description of an exemplary embodiment of the present invention is
given in the
following. It is to be understood, however, that the invention is not to be
construed as being
limited to this embodiment.
Brief Description of the Drawings
In die accompanying drawings, which illustrate an exemplary embodiment of the
present
invention:
Figure 1 is a flowchart illustrating an exemplary method according to the
present
invention;
Figure 2 is a chart presenting numerical simulation test results comparing
three different
flow and temperature regimes compared to a standard CSS base case; and
Figure 3 is a chart presenting numerical simulation test results comparing two
different
temperature regimes compared to a standard CSS base case, with nitrogen as the
non-
condensable gas.
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An exemplary embodiment of the present invention will now be described with
reference to the
accompanying drawings.
Detailed Description of Exemplary Embodiment
In the following detailed description, a specific application of the present
invention is described,
in particular an application for use with a CSS recovery method for bitumen
housed in a
fractured carbonate reservoir. However, it will be clear to those skilled in
the art that other
applications are possible within the scope of the present invention, including
unique operating
conditions and parameters specific to a particular reservoir context. That
being the case, the
following description is intended to be exemplary and non-limiting.
The present invention is intended for use with heavy hydrocarbons such as
heavy oil and
bitumen. although it can be used with lighter oils in appropriate
circumstances that would be
clear to one skilled in the art. Heavy and extra-heavy crude oils and bitumens
are composed
primarily of hydrocarbons, but they may also contain high molecular weight
aliphatic and
terpenoid hydrocarbons, asphaltenes, and oxygen-, nitrogen- and sulfur-
bearing compounds.
They occur naturally in porous and fractured reservoirs. Heavy oils and
bitumens are commonly
defined and characterized on the basis of both viscosity and density, and
those skilled in the art
will know of accepted viscosity and density ranges.
Turning to Figure 1, an exemplary method 10 according to the present invention
is illustrated.
The method 10 begins with the step 12 of drilling a well into the reservoir to
access the
hydrocarbon deposit, which in the exemplary case is a bitumen housed in a
massively fractured
reservoir. Note that where the term "well" is used herein, it can mean either
a vertical well or a
horizontal well, and the term "wells" can mean vertical and/or horizontal
wells or a combination
of vertical and horizontal wells, as would be obvious to one skilled in the
art. Once the well has
been completed, a non-condensable gas is heated at step 14 and then injected
down the well to
the reservoir at step 16. The operator then continues the injection of the gas
at a desired volume
per unit time, for a desired period of time, allowing the non-condensable gas
at step 18 to impart
heat energy to the reservoir surrounding the wellbore. The well can optionally
be shut in at this
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time, while the heat transfer continues. The specific volumes, time periods
and even the heat
level for the injected gas will depend in large part on the nature and
structure of the reservoir, the
type of hydrocarbon deposit being produced, and the availability of surface
equipment. One
skilled in the art will be able to select and operate available equipment to
meet reasonable
desired operating conditions for the method.
After the injected gas has imparted heat energy to the reservoir surrounding
the wellbore, steam
is then injected downhole to the reservoir at step 20. The skilled person will
again know how to
manage steam injection in a thermal hydrocarbon recovery operation. A mixture
of steam and a
selected solvent could also be used for this step, as is well known in the
art. As the exemplary
method is described in the context of a CSS operation, the next step 22 is
shutting in the well.
The injected steam is then allowed to heat the bitumen deposit at step 24. As
is noted above, in
prior art CSS methods, highly fractured carbonate reservoirs would sometimes
drain away the
steam or cause the heat energy to dissipate too quickly, making it a challenge
to create the steam
chamber necessary to enable hydrocarbon production at step 26. Due to
injection of the non-
condensable gas at step 16 and heating of the reservoir rock at step 18, the
reservoir is already
heated and the heat energy from the steam injection will accordingly not be as
quickly dissipated.
It is believed that this will enhance mobility of the heavy hydrocarbon
material.
After the target hydrocarbon has been mobilized and produced, the cycle can be
repeated at step
28. It is also possible to repeat the injection cycles one or more times
before initial production.
Turning now to Figures 2 and 3. numerical simulation tests were conducted to
assess the
potential impact of the present invention when compared to a conventional CSS
method. A
series of dual-permeability flow simulation models were constructed based on
the average
geological properties from the Grosmont fractured carbonate formation. In this
work STARSTm
(advanced process and thermal reservoir simulator, version 2012) from Computer
Modeling
Group Ltd. was used to simulate and evaluate the process.
In the tests giving rise to the data presented in Figure 2, simulations were
run in which heated
nitrogen gas at different volumes and temperatures was injected into the
reservoir prior to the
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steam injection in each cycle, and the results were compared with the base
case (CSS only).
Note that in all cases, three full cycles are illustrated with increasing oil
recovery factors. Each
cycle begins with injection of NCG and steam, and then the plateau illustrates
the elevated
recovery level achieved by the dual injection method. In the base CSS case 30,
a conventional
CSS approach is used for a period over 300 days involving steam injection
alone, shutting in and
subsequent production, and the oil recovery factor (RF) was found to be only
1.4% in the
simulation. In the first NCG case 32, nitrogen was heated to 400 degrees
Celsius and injected at
20 mmcfd, with a result that the RF after three full cycles increased to 5.2%.
This combination
of a heated gas and a modest injection rate demonstrates a substantial
potential improvement
over CSS alone.
in the second NCG case 34, the gas is heated to a lower temperature,
specifically 200 degrees
Celsius, but injected at a higher rate of 100 mmcfd, with the result that the
RF was increased to
9.5%. In the third NCG case 36, the gas was heated to 400 degrees Celsius and
injected at a rate
of 100 inincfd, with the result that the RF was increased to 13.3%.
The results based on three simulated cycles illustrate that hydrocarbon
recovery can be
substantially increased by implementing the present invention by a factor of 3
to 9 compared to a
conventional CSS recovery technique alone.
In the tests giving rise to the data presented in Figure 3, simulations were
run in which heated
nitrogen gas was injected into the reservoir prior to the steam injection in
each cycle, and the
results were compared with the base case (CSS only). Note that in all cases,
three full cycles are
illustrated with increasing oil recovery factors. Each cycle begins with
injection of NCG and
steam. and then the plateau illustrates the elevated recovery level achieved
by the dual injection
method. Unlike the test results shown in Figure 2, the test results shown in
Figure 3 are the
result of NCG temperature modification alone, without reference to injection
rate as the injection
rate was the same for each run. In the base CSS case 40, a conventional CSS
approach is used
for a period over 300 days involving steam injection alone, shutting in and
subsequent
production. and the RF was found to be only 1.4% in the simulation. In the
first NCG case 42,
nitrogen was heated to 200 degrees Celsius, with a result that the RF after
three full cycles
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increased to 9.5%. In the second NCG case 44, nitrogen was heated to 400
degrees Celsius, with
a result that the RF after three full cycles increased to 13.3%. The
preliminary results of three
cycles illustrate that hydrocarbon recovery may be increased by a factor of 6
to 9 compared to a
conventional CSS recovery technique alone.
The foregoing is considered as illustrative only of the principles of the
invention. The scope of
the claims should not be limited by the exemplary embodiment set forth in the
foregoing, but
should be given the broadest interpretation consistent with the specification
as a whole.
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