Note: Descriptions are shown in the official language in which they were submitted.
CA 02831928 2013-11-01
MICROBIAL PROCESSES FOR INCREASING FLUID MOBILITY IN A HEAVY
OIL RESERVOIR
FIELD
[001] The invention relates generally to in situ processes for recovering
hydrocarbon from
oil sands, and particularly to processes for increasing fluid mobility by
inoculating a near-
wellbore region in an oil sand reservoir with one or more microorganism.
BACKGROUND
[002] Demand for crude oil in North America has outstripped production levels
for the last
several decades. Conventional oil recovery practices are only able to recover
50% of the total
oil present in even the most favourable reservoirs. Conventional recovery
levels in less
favourable reservoirs, including heavier oil and bitumen reservoirs, can be
10% or less. So-
called "enhanced oil recovery" techniques can help access some fraction of
total oil or
bitumen unavailable by conventional methods. These include: thermal processes,
employing,
for example, steam, hot water, solvent, or a combination thereof to heat the
reservoir and
reduce the viscosity of heavier oil; and non-thermal processes, which include
using substances
(e.g., solvents, polymers, acids, surfactants) to reduce the viscosity of the
oil, increase the
viscosity of displacing fluids, reduce interfacial tension between the oil and
displacing fluids,
and degrade rock formations to allow smoother displacement of oil.
CA 02831928 2013-11-01
[003] One example of an enhanced in situ oil recovery technique is steam-
assisted gravity
drainage ("SAGD"). SAGD is a known thermal approach to producing bitumen and
heavy
crude oil from reservoirs. It involves drilling two vertically-displaced
(typically about 5 m
apart), parallel, horizontal wells into, for example, the lower portion of an
oil reservoir. Steam
is gradually injected into the reservoir via the upper well (i.e., the
injector well). The high
temperature of the steam affords a transfer of heat between the steam and the
bitumen or
heavy crude oil in the surrounding formation, leading to a decrease in
viscosity of the bitumen
or heavy crude oil. Gravitational forces gradually displace oil and bitumen to
the lower well
(i.e., the producer well). The producer well collects hydrocarbons, such as
oil or bitumen, and
any water from the condensation of injected steam, from whence they are
removed to the
surface and fractionated. Steam injection can occur continuously or
discontinuously. As
steam rises upward and expands outward more oil and bitumen are gradually
displaced
towards the lower well, where production occurs. SAGD improves significantly
upon
conventional recovery methods: the low steam pressure means that fracturing
between the
wells is unlikely to occur; leaking of steam into the producer well occurs at
a low rate; and the
overall process is relatively efficient, resulting in recovery of up to 80% of
the total oil or
bitumen in place in some reservoirs. The state of a formation at which any
fluid such as
bitumen, oil, water or gas may travel through the region between the two wells
(referred to
herein as the inter-well region or inter-well space), thereby connecting one
well to the other
and vice versa, is the state at which "injector-producer communication" is
achieved. Typically
injector-producer communication (which is also referred to herein as fluid
communication or
communication) is achieved when the inter-well region is heated. In some
reservoirs
(particularly those that have little or no underlying aquifer), a long period
of heating is
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normally required to achieve initial communication ("start-up") of fluids
between the injector
and producer. Methods of shortening the time to inter-well communication
(which is also
referred to as "accelerating start-up") have previously been considered,
including, for
example, by lowering bitumen or oil viscosity (see, for e.g., U.S. Patent
7,934,549).
[004] Methods to enhance oil recovery that incorporate microorganisms have
been
described. In situ methods that employ microorganisms to dislodge oil from
rock formations,
or otherwise enhance the recovery of oil from reservoirs, are known as
"microbial-enhanced
oil recovery" ("MEOR") techniques. MEOR methods have many useful applications,
including, for example: producing biopolymers that increase viscosity of
waterfloods (see, for
e.g., U.S. Pat. No. 4,475,590 to Brown), and producing biosurfactants (see,
for e.g., U.S. Pat.
No. 4,522,261 to McInerney et al.).
[005] U.K. Patent No. 2,450,502 to Kotlar describes methods for enhancing
heavy oil
recovery from a reservoir using a microorganism capable of lowering oil
viscosity. Kotlar
indicates that microorganisms be injected during or after an extraction
process. U.S. Patent
No. 8,235,110 to Larter et al. describes general methods of using a
preconditioning agent in a
mobile water film to precondition oil reservoirs.
[006] The following publications describe methods which employ microorganisms
for
production or treatment of oil: Canadian Patent Application No. 2,638,451;
Canadian Patent
No. 2,761,048; Canadian Patent No. 2,531,963; Canadian Patent No. 1,317,540;
Canadian
Patent No. 2,100,328; U.S. Patent Publication No. US/2013/0062053; U.S. Patent
Publication
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CA 02831928 2013-11-01
No. US/2012/0325457; U.S. Patent Publication No. US/2012/0261117; U.S. Patent
Publication No. US/2012/0301940; U.S. Patent Publication No. US/2012/0214713;
U.S.
Patent Publication No. US/2011/0257052; U.S. Patent Publication No.
US/2011/0083843;
U.S. Patent Publication No. US/2011/0067856; U.S. Patent Publication No.
US/2010/0212888; U.S. Patent Publication No. US/2011/0308790; U.S. Patent
Publication
No. US/2010/0012331; U.S. Patent No. 7,922,893; PCT Publication No.
W02011/076925;
U.S. Patent Application No. US/2009/0130732. U.S. Patent No. 5,174,378; Harner
et al., J.
Ind. Microbiol. Biotechnol. 2011; Nov: 38(11):1761-1775; PCT Publication No.
WO/
2011/159924; PCT Publication No. WO/ 2008/070990; Canadian Patent Application
No.
2,640,999; Canadian Patent Application No. 2,767,846; Canadian Patent
Application No.
2,823,752; and Canadian Patent Application No. 2,823,750.
SUMMARY
[007] In various embodiments, methods are provided which increase overall
fluid mobility
in a near-wellbore region in an oil sands reservoir. The near-wellbore region
may for example
be within an inter-well region between a first well and a second well of a
well pair, or
alternatively may be a single well that is not a component of a well pair.
Accordingly, for
embodiments where the near-wellbore region is proximal to one or both wells of
a well pair,
the method may involve increasing overall fluid mobility in the inter-well
region between the
first well and the second well of the well pair, for example in connection
with start-up process
associated with SAGD production methods.
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[008] In
one aspect, the method increases overall fluid mobility in a near-wellbore
region
in an oil sands reservoir. The method involves (a)inoculating the near-
wellbore region with
one or more microorganism, wherein the near-wellbore region comprises a
hydrocarbon phase
and an aqueous phase, the viscosity of the hydrocarbon phase being greater
than the viscosity
of the aqueous phase; and (b) maintaining conditions in the near-wellbore
region so that the
one or more microorganism metabolizes at least a portion of the hydrocarbon
phase so that
saturation of the near-wellbore region by the hydrocarbon phase decreases and
saturation of
the near-wellbore region by the aqueous phase increases, increasing overall
fluid mobility.
[009] In one embodiment, the method increases the overall fluid mobility in an
inter-well
region between a first well and a second well of a well pair in the oil sands
reservoir, wherein
the near-wellbore region is associated with at least one of the first and
second well, and at
least a portion of the near-wellbore region is within the inter-well region.
For example, the
first well may be an injection well, and the second well may be a production
well. In other
embodiments, the method increases overall fluid mobility in the region of a
single well
located in the oil sands reservoir which is not a component of a well pair.
[0010] In some aspects, inoculating may occur prior to steam-assisted gravity
drainage
(SAGD) to pre-condition the oil sands reservoir for SAGD. Optionally, the
inoculating may
occur after SAGD is completed. Further, the instant process may be used as an
alternative to
SAGD, and thus inoculating may occurs in lieu of SAGD in an oil sands
reservoir from which
oil may subsequently be produced. The method may be used in association with
thermal
CA 02831928 2013-11-01
recovery methods, generally, such as cyclic steam stimulation (CSS), and/or
other recovery
methods involving in situ drilling.
[0011] Maintaining propagating conditions in at least a portion of the inter-
well region may
be undertaken so as to ensure viability of the microorganism within the inter-
well region.
Such conditions may permit the microorganism to metabolize at least a portion
of the
hydrocarbon phase, thereby decreasing saturation of the inter-well region by
the hydrocarbon
phase and increasing saturation of the inter-well region by the aqueous phase.
[0012] According to another aspect, a cycling process may be employed
comprising: (c)
injecting or circulating a heated cycling fluid within one or both of the
first or second well in
fluid communication with the near-wellbore region, to mobilize fluids within
the near-
wellbore region; and (d) repeating steps (a) and (b) so that the microorganism
metabolizes a
further portion of the hydrocarbon phase. Optionally, the cycling process
steps (c) and (d)
may be repeated more than once. The cycling process steps may be repeated for
a period of
time, such as for about two weeks or more. The heated cycling fluid may
comprise steam or
water, optionally with a solvent, surfactant, or a combination thereof.
[0013] The one or more microorganism may be contained in an inoculant
solution, and
following step (a) the inoculant solution may be absorbed into the near-
wellbore region over a
soaking period. Optionally, after the soaking period, additional inoculant
solution can be
added into the near-wellbore region well to increase overall fluid mobility.
Optionally,
unabsorbed inoculant solution can be withdrawn from the near-wellbore region
after the
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soaking period; and may be combined with the additional inoculant solution for
adding and
re-circulating in the near-wellbore region. An exemplary total volume of
inoculant solution,
including that used in step (a) plus the additional inoculant solution, when
utilized, may be
from about 2X to about 3X the volume of the volume of inoculant solution used
in step (a).
[0014] In aspects of the method, the saturation of the near-wellbore region by
the aqueous
phase can increase by amounts of 5% or greater, 10% or greater, for example
about 25% or
greater. A decrease in the hydrocarbon phase saturation is also observed. As
an example, the
saturation of the near-wellbore region by the hydrocarbon phase may decrease
by about 50%
after a period of about two weeks. In certain reservoirs with high irreducible
water saturation,
the increase in water saturation observed may not be as great of a percentage
increase,
because of the high initial aqueous phase saturation.
[0015] Fluid communication may be established between the first well and the
second well of
a well pair upon completion of step (a) and (b). Subsequently, injecting or
circulating a fluid
in: (i) the first well; (ii) the second well; or (iii) both the first well and
the second well to
establish the fluid communication between the first well and the second well
may be
conducted, using a fluid such as steam or water, optionally including a
solvent, a surfactant, or
combinations thereof
[0016] Aspects of the method may involve determining a first saturation level
of the aqueous
phase in the near-wellbore region prior to inoculating, and determining a
second saturation
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level of the aqueous phase in the near-wellbore region following inoculating,
and optionally
determining the increase in aqueous phase saturation.
[0017] Further aspects of the method may involve determining a first fluid
mobility level of
in the near-wellbore region prior to inoculating, and determining a second
fluid mobility level
in the near-wellbore region following inoculating, and optionally determining
the increase in
fluid mobility.
[0018] The one or more microorganism may, for example, be one which can
metabolize
hydrocarbons of C16 or greater. The microorganism may be one which
preferentially
metabolizes hydrocarbons of C20 or greater. The inoculant may comprise
microorganisms in
the form of a mixture of bacteria. The mixture may preferentially metabolize
heavy ends of
the oil in the oil sands reservoir, and may comprise both aerobic and
anaerobic bacteria.
[0019] Some aspects of the method involve step of injecting heated fluid into
the injection
well or circulating heated fluid in the well pair prior to the step of
inoculating. The wells in
the well pair each may have a section that extends substantially in a
horizontal direction,
wherein fluid communication is established between the substantially
horizontal sections.
The substantially horizontal sections of the wells may be substantially
parallel, and vertically
spaced apart.
[0020] According to a further aspect, there is provided herein a method of
recovering
hydrocarbon from in an inter-well region in an oil sands reservoir located
between an
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injection well and a production well. The method comprises (a) inoculating the
inter-well
region with a mixture of anaerobic and aerobic bacteria that metabolizes
hydrocarbons of C16
or greater; (b) maintaining the viability of at least a portion of the mixture
of bacteria in the
inter-well region so that the mixture of bacteria metabolizes at least a
portion of the
hydrocarbon phase having C16 or greater, to produce a hydrocarbon phase of
decreased
viscosity; and (c) recovering the hydrocarbon phase of decreased viscosity
from the inter-well
region. Optionally, steps (a) to (c) may be repeated. In some embodiments, the
inoculating of
the inter-well region comprises injecting the mixture of bacteria into the
injection well
together with a suitable carrier.
[0021] There is described herein a method of increasing overall fluid mobility
of oil in a
near-wellbore region in an oil sands reservoir, comprising inoculating a well
with an inoculant
solution comprising one or more microorganism that metabolizes hydrocarbon of
C16 or
greater; permitting the inoculant solution to become absorbed into the near-
wellbore region
over a soaking period; and adding additional inoculant solution into the well
to increase
overall fluid mobility of oil. Optionally, the method may include withdrawing
unabsorbed
inoculant solution after the soaking period; and combining the withdrawn
solution with the
additional inoculant solution added into the well to re-circulate in the well.
According to an
exemplary embodiment, the total volume of inoculant solution used in the steps
of inoculating
and adding may be at least about 3X the volume used in the step of
inoculating. An
exemplary soaking period may be from about 2 to about 3 weeks.
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[0022] Other aspects and features will become apparent to those ordinarily
skilled in the art upon
review of the following description of specific embodiments as detailed in the
accompanying
figures, and as described herein.
BRIEF DESCRIPTION OF THE DRAWINGS
[0023] The following figures illustrate embodiments, by way of example only.
[0024] Figure 1 depicts the geometry of a bottom-water system simulation as
described
herein.
[0025] Figure 2 depicts wellhead pressure as a function of time for a bottom-
water simulation
(Sõ----25%) as described herein.
[0026] Figure 3 depicts casing and tubing pressure in the well at 12.5 d
(bottom-water
geometry, Sw=25%) as described herein.
[0027] Figure 4 depicts the geometry of a side-water system simulation as
described herein.
[0028] Figure 5 depicts casing and tubing pressure in the well at 12.5 d (side-
water geometry,
Sw=37%) as described herein.
[0029] Figure 6 depicts casing and tubing pressure in the well at 12.5 d (side-
water geometry,
Sw=37%) as described herein.
[0030] Figure 7 depicts maximum tubing well head pressure as a function of
water saturation
in a transition zone.
CA 02831928 2013-11-01
[0031] Figure 8 depicts the geometry of a generic two well SAGD system
simulation as
described herein.
[0032] Figure 9 depicts the wellhead casing pressure for the two well system
as a function of
time.
[0033] Figure 10 depicts casing and tubing pressure in the injector well at
the end of 12 d as
described herein.
DETAILED DESCRIPTION
[0034] Embodiments of in situ processes for recovering hydrocarbon from oil
sands are
described herein. In particular, processes for increasing fluid mobility by
inoculating a near-
wellbore region in an oil sand reservoir with one or more microorganism are
described. In
alternative embodiments, the processes may for example increase fluid mobility
near both
horizontal and vertical wells, near a single well, and/or between well pairs.
Well pairs may
include both parallel well pairs and cross well pairs. The methodology
described herein may
be used in association with and/or in lieu of thermal recovery methods such as
steam-assisted
gravity drainage (SAGD) or cyclic steam stimulation (CSS), involving well
pairs or a single
well.
[0035] In various aspects, the implementation of microbial processes are
employed so as to
adjust oil and water saturation levels in a reservoir. Oil saturation is the
fraction of the pore
space occupied by oil. Most oil reservoirs also contain some connate water.
Oil saturation is
rarely 100% and usually ranges from 10% to 90% (in what are known as oil/water
"transition
zones"). Water saturation is the fraction of the pore space occupied by water.
Most reservoirs
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are water wet and contain connate water. Water saturation may range from 10%
to 50% for an
oil or gas reservoir and is up to 100% in an aquifer.
[0036] One embodiment involves methods of increasing overall fluid mobility in
an inter-well
region between a first well and a second well of a well pair in an oil sands
reservoir. The
reservoir may be characterized as having a near-wellbore region associated
with at least one
of the wells, at least a portion of the near-wellbore region being within the
inter-well region.
[0037] In selected embodiments, having a well pair wherein the inter-well
distance is X
meters, the near-wellbore region can be defined as the volume of reservoir
occupied within a
radius of X/2 m from the wellbore(s) in question. For example, for a well pair
in which the
wells are 5 m apart, the near-wellbore region may be defined to include up to
a 2.5 m radius
from each of the two wellbores. In some embodiments, the near-wellbore region
includes the
volume defined by a radius of 2-3 m from the well, wherein this 2-3 m radius
is not
necessarily constant (i.e. is variable) along the length of the wellbore. In
general, it will be
appreciated that the near-wellbore region contains the wellbore.
[0038] Selected methods involve: inoculating the near-wellbore region with a
microorganism,
wherein the near-wellbore region comprises a hydrocarbon phase and an aqueous
phase, the
viscosity of the hydrocarbon phase being greater than the viscosity of the
aqueous phase. The
method further involves maintaining conditions in the near-wellbore region so
that the
microorganism metabolizes at least a portion of the hydrocarbon phase so that
saturation of
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the near-wellbore region by the hydrocarbon phase decreases and saturation of
the near-
wellbore region by the aqueous phase increases.
[0039] The near-wellbore region may for example be associated with: (i) an
injector well of
the well pair, (ii) a producer well of the well pair, or (iii) both the
injector well and the
producer well. A single production well may also be associated with the near-
wellbore
regions, such as utilized in Wedge We11TM technology, which employs a
horizontal well in
association with a SAGD operation. The near-wellbore region may also be a
single well, for
example one associated with cyclic steam stimulation (CSS) in which steam is
pumped down
a vertical well to soak or liquefy the bitumen, which is subsequently pumped
to the surface
through the same well. The regions nearby either a single well or associated
wells (for
example, well pairs) are encompassed as the near-wellbore region.
[0040] Methods may involve maintaining propagating conditions in at least a
portion of the
near-wellbore and inter-well regions so that the microorganism propagates
within the inter-
well region between the first well and the second well, the portion of the
inter-well region
comprising a hydrocarbon phase and an aqueous phase, the viscosity of the
hydrocarbon
phase being greater than the viscosity of the aqueous phase.
[0041] As used herein, the term "propagating conditions" includes those
fundamental
chemical and biological factors which are required for maintaining viability
of a
microorganism, such as a bacterium, including the ability to metabolize
hydrocarbons.
Without limitation, "propagating conditions" include the following: an
appropriate nitrogen
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source, an appropriate phosphorous source, and an appropriate carbon source,
which can
include but is not limited to the hydrocarbon in the oil sands reservoir.
Without limitation,
"propagating conditions" further includes the following an appropriate oxygen
source; for
example, an aerobic bacterium would require an appropriate oxygen source.
Without
limitation, "propagating conditions" further includes: an appropriate moisture
level, an
appropriate pH, and an appropriate temperature. In the case of bacterial
microorganisms,
"propagating conditions" may further include trace metals or salts such as
magnesium or
sulfur. The foregoing examples are provided as examples only and are not meant
to limit the
foregoing.
[0042] The method may further involve maintaining propagating conditions in
the inter-well
region so that the microorganisms metabolizes at least a portion of the
hydrocarbon phase so
that saturation of the inter-well region by the hydrocarbon phase decreases
and saturation of
the inter-well region by the aqueous phase increases.
[0043] The method may further involve a cycling process involving a subsequent
step of
injecting or circulating a heated fluid within one or both of the first or
second well in fluid
communication with the near-wellbore region, so as to mobilize fluids within
the near-
wellbore region; and then, repeating the steps of inoculating the near-
wellbore region and
maintaining conditions in the near-wellbore region so that the microorganism
metabolizes a
further portion of the hydrocarbon phase. The cycling process may be repeated
one or more
times. The heated cycling fluid may be steam. The heated cycling fluid may be
water. The
heated cycling fluid may be or may contain a solvent or a surfactant.
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[0044] The method may be carried out so that saturation of the near-wellbore
region by the
aqueous phase increases to about 25% or greater, for example up to and
including about 3 to 5
% above the irreducible water saturation. An exemplary range may be from about
25% to
about 37%. The method may be carried out so that saturation of the inter-well
region by the
aqueous phase increases to about 25% or greater, for example up to and
including about 3 to 5
% above the irreducible water saturation. An exemplary range may be from about
25% to
about 37%. The method may be carried out so that fluid communication is
achieved between
the first and second wells.
[0045] The method may further involve injecting a fluid into or circulating a
fluid in: (i) the
first well; (ii) the second well; or (iii) both the first well and the second
well to achieve fluid
communication between the first and second wells. The fluid may be any one or
more of the
following: steam, water, a solvent, or a surfactant.
[0046] The method may further involve determining a first saturation level of
the aqueous
phase in the near-wellbore region prior to inoculating the near-wellbore
region. The method
may further involve determining a first saturation level of the aqueous phase
in the inter-well
region prior to inoculating the near-wellbore region. The method may further
involve
determining a second saturation level of the aqueous phase in the near-
wellbore region
following inoculation of the near-wellbore region. The method may further
involve
determining a second saturation level of the aqueous phase in the inter-well
region following
inoculation of the near-wellbore region. The method may further involve
determining a first
CA 02831928 2013-11-01
mobility level of the aqueous phase in the near-wellbore region prior to
inoculating the near-
wellbore region. The method may further involve determining a first mobility
level of the
aqueous phase in the inter-well region prior to inoculating the near-wellbore
region. The
method may further involve determining a second mobility level of the aqueous
phase in the
near-wellbore region following inoculation of the near-wellbore region. The
method may
further involve determining a second mobility level of the aqueous phase in
the inter-well
region following inoculation of the near-wellbore region.
[0047] The method described herein may further involve a step of injecting a
heated fluid into
or circulating a heated fluid in the first or second well or both prior to the
step of inoculating.
The wells in the well pair described herein may each have a section that
extends substantially
in a horizontal direction, the substantially horizontal sections of the wells
being oriented in a
range from being substantially parallel to substantially perpendicular, and
wherein fluid
communication may be established between the substantially horizontal
sections. The
substantially horizontal sections of the wells may be vertically spaced apart.
Alternatively, the
wells in the well pair described herein may each have a section that extends
substantially in a
vertical direction, the substantially vertical sections of the wells being
substantially parallel,
and wherein fluid communication may be established between the substantially
vertical
sections. The substantially vertical sections of the wells may be horizontally
spaced apart. The
distance between the substantially horizontal or vertical sections of the
wells may for example
be about 3 meters. In some embodiments, the first well may for example be an
injection well
completed for a steam-assisted gravity drainage process and the second well
may be a
production well completed for a steam-assisted gravity drainage process.
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[0048] As used herein, the term "light ends" means a fraction of hydrocarbons
from oil sands
oil having about 20 carbons or fewer, and the term "heavy ends" means a
fraction of
hydrocarbons from oil sands oil having made up of hydrocarbons having about 20
carbons or
more.
[0049] The method described herein may further involve a step of injecting a
heated fluid into
or circulating a heated fluid in one or both of the first or second well prior
to the step of
inoculating. The wells in the well pair described herein may each have a
section that extends
substantially in a horizontal direction, the substantially horizontal sections
of the wells being
substantially parallel, and wherein fluid communication may be established
between the
substantially horizontal sections. The substantially horizontal sections of
the wells may be
vertically spaced apart. The distance between the substantially horizontal
sections of the wells
is about 3 meters, wherein the first well may be an injection well completed
for a steam-
assisted gravity drainage process and the second well may be a production well
completed for
a steam-assisted gravity drainage process.
[0050] It would be understood by a person of skill in the art that where fluid
mobility is
increased between well pairs, as determining the spacing of these well pairs
is well known in
the art. Typically, well pairs may be spaced about 3 to 8m apart.
Alternatively, well pairs
may be spaced about 3-7m apart, 3-6m apart, 3-5m apart, 3-4m apart, or about
3m apart.
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[0051] Similarly, any range of values given herein is intended to specifically
include any
intermediate value or sub-range within the given range, and all such
intermediate values and
sub-ranges are individually and specifically disclosed. For example, inter-
well distances in a
SAGD well pair are typically on the order of 5 m, however, this distance may
vary, for
example over a range of from about 3 to about 8 m, and the recital herein of a
range from 3 to
8 m is accordingly understood to include any intermediate value or sub-range
within 3 to 8 m.
[0052] Microorganisms. The one or more microorganism described herein may be a
bacterium or mixture of bacteria. The bacteria may, for example, be a mixture
of anaerobic
and aerobic bacteria capable of metabolizing hydrocarbon heavy ends of C16 or
greater, or of
C20 or greater. The mixture may be one that is similar to or the same as the
mixture used in
the lab testing phase described herein: BC-10 BacteriaTM (BioConcepts Inc. of
Kemah, TX)
optionally together with a catalyst or activator such as DHCSOTM, DHC-S5OTM,
DHC29TM,
DHA9TM, all available from BioConcepts, Inc. (Kemah, TX) which are selected
for the
ability to metabolize C16 and larger hydrocarbon materials existing in oil.
The mixture of
bacteria digest the hydrocarbon, thereby reducing the length of the molecule
and producing
by-products which can act as surfactants. This process lightens the heavy
ends.
[0053] Optionally, one or more other additional strains of bacteria may be
used be in
inoculation step to metabolize the light ends of the hydrocarbon phase (in
addition to
metabolizing the heavy ends). Specifically, such additional strains of
bacteria would be ones
capable of metabolizing a hydrocarbon fraction having hydrocarbon molecules of
20 carbons
or fewer. However, the ability to metabolize heavy ends (or in some
embodiments, the
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preferential use of heavy ends as substrate) carries the advantage that the
recovered oil
becomes lighter and of a higher quality for later use. Typically,
microorganisms capable of
metabolizing light ends are used in recovery or remediation following
downstream
processing, for example in remediation of tailings ponds where heavy ends are
unlikely to be
located. An inoculant microorganism that would metabolize light ends would
have the effect
of, on balance, increasing the ratio of heavy to light ends, and may not have
the observed
effect on API and density.
[0054] An exemplary mixture, having 12 strains of anaerobic and anaerobic
bacteria have the
ability to metabolize carbon chains from about C16 to about C58. The inoculant
bacterial
mixture has a life span of approximately 6 to 8 weeks. Without being limited
to theory, the
products formed in the bacterial digestion process not only possess reduced
reduce
hydrocarbon chain length but also may act as surfactants and solvents, helping
to mobilize the
oil.
[0055] Microbial Products. The microbial culture will produce smaller/lighter
hydrocarbons
from longer (C20 and greater) heavy ends, thus, resulting in an increased
overall fluid
mobility. Other microbial byproducts may act as surfactants that can
advantageously help to
mobilize oil adhered to the formation within the near-wellbore region.
Further, gases such as
H2 and methane which may be produced as a result of microbial metabolism of
heavy ends
may also contribute to overall fluid mobility by decreasing the viscosity and
density of the oil
in the near wellbore region. An increase in API, (as a parameter indicative of
increased fluid
mobility) is an exemplary parameter that can be used to evaluate the outcome
of the method.
19
CA 02831928 2013-11-01
[0056] Before, After and In Lieu of Other Thermal Processes. The inoculation
with the
bacterial mixture and subsequent increase in overall fluid mobility may act to
precondition a
reservoir prior to conducting thermal recovery processes, such as steam-
assisted gravity
drainage (SAGD) or cyclic steam stimulation (CSS), so as to accelerate start-
up of a well.
Optionally, a well that has completed the economic production using a thermal
recovery
process, such as SAGD or CSS, may be further exposed to the process described
herein, so
that inoculation after the thermal recovery process can result in further
production of residual
hydrocarbon remaining in the near wellbore region, such as the inter-well
region when a well
pair is utilized in SAGD. By utilizing the instant process when other thermal
processes, such
as SAGD or CSS, become less economical (due, in part, to the cost of steam
production)
recovery from a well after the final cycle of SAGD is completed (or
"blowdown") or after
CSS is completed, recovery can be enhanced.
[0057] Further, the method described herein can result in such an increase in
fluid mobility
(and reduction in viscosity) that the method may be employed in place of a
thermal recovery
method such as SAGD or CSS, in wells that would otherwise be suitable for
production
through a thermal recovery process. The economics of production may be a
parameter used
to evaluate the efficiency of using the current method in lieu of other
thermal processes, such
as SAGD or CSS. In secondary pay zones which may have been conductively
heated, but
which still may require some additional fluid mobility to enhance recovery,
the method
described herein may be utilized with a secondary pay well to enhance the
fluid mobility.
[0058] Circulation and Re-inoculation. Circulation or re-circulation of an
inoculant
solution may occur in certain embodiments provided herein. Advantageously,
circulation
CA 02831928 2013-11-01
may allow better colonization of the near-wellbore region, and/or increased
exposure of the
one or more microorganism to the available substrate. Once the microorganism
has exhausted
substrate supply in its immediate vicinity, a circulation of the inoculant
solution helps to re-
position microbes and encourages colonization in near-wellbore regions that
may have be
inaccessible at the initial inoculation. In order to circulate or re-circulate
microorganisms,
inoculant solution may be recovered or withdrawn from a well, such as the
first or second
well, for example by means of a pump. All or any portion of the initial
microorganisms may
be recovered, and subsequently re-injected into the near-wellbore region.
Subsequent cycles
of withdrawal/recovery and re-inoculation/insertion may be undertaken. Fresh
inoculant
solution and/or new microorganisms may be included at any stage in the
circulation or re-
circulation to the near-wellbore region.
[0059] Such circulation and re-circulation steps permit the one or more
microorganism to
mobilize and gain increased exposure to substrate (heavy ends) within the near
wellbore
region. Optionally, circulation and re-circulation of inoculant solutions may
comprise
delivery of a subsequent fresh solution of inoculant in place of the solution
withdrawn, in
situations where a change is deemed necessary. Further, the removal, or
suctioning out, of
original inoculant solution so as to circulate existing inoculant is also
envisioned in certain
embodiments, with or without fresh inoculant.
[0060] As a further alternative embodiment, additional microorganisms (and
fresh inoculant
solution) may be inoculated into the near-wellbore regions without withdrawal
or removal of
the initial inoculant, so as to increase pressure within the desired region of
an oil sands
reservoir. Such a re-inoculation step may be a one-time-only occurrence, or
may occur
periodically. In this embodiment, the surface to microorganism contact may
increase by
21
CA 02831928 2013-11-01
causing enhanced penetration of the near wellbore region. Inoculant solution
may be
withdrawn in small amounts and re-injected in the same or greater amounts
through a pulsed
timing. Such an embodiment can cause mixing of existing colonized
microorganisms with
fresh inoculant within the near-wellbore region. By pumping subsequent
inoculant into a
near-wellbore region, the previously injected microorganism solution is
effectively pressured
further into the oil sands reservoir, so as to further penetrate the region
and access additional
heavy end hydrocarbon substrate.
[0061] Pumping or re-inoculation can occur periodically, for example, once
daily, once every
second day, once per week, or by-weekly, as needed. The periodicity with which
pumping/pulsing or re-inoculation is undertaken can be determined based on a
leveling-off of
the observed change in a fluid mobility parameter, such as viscosity or API,
in a given near-
wellbore region. Some reservoirs may benefit from more frequent periods if the
change in
fluid mobility occurs rapidly but then subsequent changes level off quickly.
[0062] An exemplary circulation volume of inoculant solution may be about 3X
or more the
volume of the standard horizontal section of the well. Thus, a section having
a volume of 12
m3 would soak in a total volume per treatment from 36-40 m3 in such an
embodiment.
[0063] The recirculation can be adjusted depending on whether the expected
injectivity is
reached or not. For example, it may be that both production and injector wells
are inoculated
(or either one or other of the producer or the injector well). When injecting
one well, the first
injection of 12-20 m3 of inoculant could be permitted a 2-3 week soaking
period. Optionally,
after the initial soaking period, additional fluid may be pumped into the well
so that a total
approximately 3-fold (fluid volume of up to about 36-40 m3) could be injected
so as to
squeeze the fluid into the near-wellbore regions. Such an option could be
conducted by
22
CA 02831928 2013-11-01
applying higher pressure into the reservoir with N2 gas in order to move the
injected fluids
further in, to permit soaking in. A subsequent soaking period of 2 to 3 weeks
may be
utilized. If the expected injectivity is not yet reached, the inoculant fluid
may optionally be
withdrawn and recirculated.
[0064] For situations in which the injector and producer wells are both
inoculated, an
exemplary injection of 12 m3 (based on volume of a standard horizontal section
of a well) is
provided to each well and permitted a soaking period, for example of 2-3
weeks. Following
this, additional fluid may be added to squeeze the fluid and thus the
microorganisms further
into the reservoir. Optionally with N2 gas may be used. The total inoculant
volume may be,
for example about 40 m3 in total. Following this addition of fluid, a
subsequent soaking
period may ensue. Recirculation of the fluid may optionally be undertaken if
the desired
injectivity is not reached.
[0065] The initial injection and/or subsequent injections may occur by
injecting into both
injector and producer wells, or by selecting either the producer well or
injector well.
Regardless of the strategy selected, an exemplary target volume of about 3X a
horizontal well
section may be used.
[0066] In some embodiments, fluid remaining in a wellbore after the soaking
period may be
removed, for example by aspiration or pumping, and is subsequently then
pumping back in to
re-circulate, so as to permit better movement into and colonization of the
wellbore. Further,
such re-circulation may be conducted concomitantly with the addition of
additional volumes
of inoculant, for example to achieve a 3X fluid volume, which in some
instances may be a 36-
40 m3 volume of fluid per treatment. The fluid remaining in the wellbore after
the soaking
23
CA 02831928 2013-11-01
period can be either be recirculated or not. The desired or expected
injectivity can be
observed to inform the desirability of this option.
[0067] Time Periods. After an appropriate period of time for the microbe or
microbe mixture
to contact and colonize a near-wellbore region, which may for example be an
inter-well
region, for example a period of about 5 days or more, such as about 10 days or
more, 2 weeks
or more, or 3 weeks or more, a highly saturated hydrocarbon phase will become
less viscous,
and less saturated due to the metabolism of the mixed microbial culture.
[0068] In an optional embodiment, following an initial soaking period of from
about 2 to
about 3 weeks, an additional volume of inoculant may be added to the near-
wellbore region
in order to increase pressure, and effectively squeeze the inoculant and
attendant
microorganisms further into the oil sands reservoir. In this way, additional
contact is made
between hydrocarbon substrate and the microorganisms.
[0069] Inoculant Composition. Microorganism may be delivered within microbial
culture,
together with an appropriate carrier fluid that is water-based. The carrier
fluid is one that does
not impede microorganism viability, and which contains an appropriate balance
of salts and/or
nutrients as would be understood by a skilled person. Additional components
can be included
in the inoculant composition. For example, solvents may be added. Components
which may
be desirable to include within the well can be included in the inoculant
composition. For
example, downhole activators, downhole catalysts, solvents, surfactants, or
buffers may be
included in the inoculant composition. These components may assist in the
delivery and
colonization of the one or more microorganism; may help contribute (even in a
minor way), to
24
CA 02831928 2013-11-01
an increase in the water saturation (aqueous phase increase) of the near
wellbore region
thereby further facilitating the later mobility of steam through the formation
when SAGD is
subsequently undertaken, but need not play a specific role in effecting
overall fluid mobility.
Provided an additive to the inoculant composition does not greatly impede the
overall increase
in fluid mobility in a near-wellbore region, or kill the vast majority of the
microorganisms, it
may be included in the composition.
[0070] Exemplary quantities of solvent, when present (such as an organic
solvent), relative to
the mixture of microorganisms may be from about 5% to about 60% solvent. For
example,
from about 10% solvent to 50% solvent may be used. In some embodiments, 20%
solvent or
30% solvent may be employed.
[0071] Accelerated Start-up. An advantage realized in certain embodiments
provided herein
is that time to start-up of a well for production can be reduced, thus
accelerating start-up of a
well for later SAGD production. For example, a typical start-up time with
steam alone may
be 3 months, while embodiments of the method described herein may accomplish
start-up of a
well into production in 4 to 6 weeks. Accelerated start-up time is desirable
to more
economically extract entrained oil from oil sand in the near-wellbore region.
Steam will
impact the viability of the microorganisms colonized in the near-wellbore
region. Thus once
SAGD begins, the impact on fluid mobility attributable to the microorganisms
is lessened
over time. The conversion of heavy ends to lighter (shorter) hydrocarbons due
to metabolism
by the microorganisms will have an initial effect in SAGD, in that fluid
mobility of the oil
produced will be enhanced.
CA 02831928 2013-11-01
[0072] Inoculation after SAGD or other Recovery Process is Completed. Steam-
related oil
recovery processes will result in a reduction of most, if not all, of the
colonized
microorganisms within a near-wellbore region. However, once the final cycle of
a recovery
process, such as SAGD cycle or CSS, is completed, a further inoculation could
be employed
to re-colonize the region and recover residual hydrocarbon.
[0073] During the "blowdown" period of SAGD, bitumen production continues with
operations maintained under the same control scheme employed in conventional
SAGD
operations. Bitumen production rates decline over time as the growth rate of
the steam front
slows under gas injection. Production operations may continue until bitumen
production
declines to an uneconomic rate, at which time approximately 65% of the
producible oil is
projected to have been removed. Microbial inoculation according to the method
described
herein can be used at this stage to help with the mobility of the remaining
oil, as thereby
considerably decrease oil viscosity to an additional extent (and maximize
recovery) at the
point when steam and gas injection become uneconomic.
[0074] Embodiments in which a near-wellbore region is inoculated after the
final SAGD
cycle with the one or more microorganisms, can serve to maximize recovery of
some of the
remaining oil in an oil sands reservoir, when the use of steam becomes
uneconomical. The
near-wellbore region into which an inoculant solution is provided, after
conventional SAGD
production, has both a hydrocarbon phase and an aqueous phase, although much
of the
hydrocarbon has already been removed in SAGD. The viscosity of the hydrocarbon
phase is
nevertheless greater than the viscosity of the aqueous phase, and thus the
method of
increasing overall fluid mobility, as described herein, can assist in further
hydrocarbon
removal.
26
CA 02831928 2013-11-01
[0075] In certain SAGD operations, horizontal wells pairs may be drilled with
one well
disposed above the other. Multiple well pairs may be drilled from a single
well pad, and over
time, a pocket of unrecovered bitumen may forms in the space between two well
pairs.
Optionally Wedge We11TM technology allows access the wedge of bitumen via a
single
horizontal well drilled between two SAGD well pairs and pumping the oil to the
surface
through this additional well. The process described herein may be used before,
after, or in
lieu of Wedge WellTm technology.
[0076] Conditions under which Microorganisms are Maintained. Maintaining
favorable
conditions in the near-wellbore region allows the one or more microorganism to
remain
viable, and/or to propagate. The conditions permit the microorganism to
survive and colonize
in the near-wellbore region, and to metabolize the heavy ends as an energetic
substrate. Such
conditions may pertain to temperature, the presence of additives or solvent in
an inoculant
solution (or separately added to a reservoir), substrate within an inoculant,
and other
parameters.
[0077] Well bore conditions pertaining to start-up in a SAGD operation permit
the one or
more microorganism to remain viable in the near-wellbore region. Non-aqueous
solvents may
be included in the inoculant solution, or added separately to the near-
wellbore regions, in
modest amounts that do not affect microorganism viability. For example, a
hydrocarbon
solvent such as ethane, propane, or butane or larger alkanes (and mixtures of
these) may be
included. Aromatic solvents, such as xylene, benzene, toluene, phenol, or
mixtures of these
may be employed, as described in Canadian Patent No. 2,698,898.
27
CA 02831928 2013-11-01
[0078] Inoculant is added under conditions that are sub-fracturing conditions
(pressure or
injection rate or both), and at an ambient temperature that permits survival
of the
microorganisms. Under colder seasonal climate conditions, care can be taken to
ensure that
the microorganism inoculant solution is not frozen, but is maintained for
injection at a
temperature that reasonably permits viability to be maintained. No heating is
required for
inoculation of the near-wellbore region, provided the inoculant is protected
from excessively
cold ambient climate temperatures prior to inoculating.
[0079] Gas may be included in the conditions of the near-wellbore region, such
as air,
oxygen, and nitrogen, provided the gas does not exclude the level of oxygen
necessary for
survival of aerobic bacteria.
[0080] The conditions may be designed to permit the inoculated microorganism
to soak into
the near-wellbore region for a period of time so as to displace, colonize, and
interact with
(metabolize) substrate within the near-wellbore region. A typical candidate
oil sands
reservoir may be one in which the bitumen or heavy oil density is about 15
API or heavier,
such as 12 API or heavier. An exemplary gravity of 8-10 API may be found in
the oil sands
reservoir within which the near-wellbore regions is located.
[0081] SAGD Start-Up and Optional Conditions. By way of comparison, standard
conditions
for SAGD (steam) start-up (not involving the inoculating and colonization by
microorganisms, as described herein) may involve well pairs into which steam
is injected in
an amount of about 200 ton/day, with an injector bottom-hole pressure (BHP) of
about 5 MPa,
and a producer BHP of about 4.8 MPa, which is well below a typical fracture
pressure. The
startup stage of SAGD establishes communication between injection and
production wells.
28
CA 02831928 2013-11-01
An average start-up time for SAGD start-up may be about 90 days, and the
amount of steam
utilized for start-up may be in the range of about 20,000 m3. Initial
reservoir conditions
typically show negligible fluid mobility due to high oil viscosity and lack of
water saturated
zones in the inter-well region. SAGD start-up using steam can be supplemented,
accelerated
or replaced with the method described herein in which fluid mobility is
increased using
microorganism inoculation and colonization of the inter-well region.
[0082] Further optional conditions which may be employed in start-up, either
before or after
inoculation are described in Canadian Patent Application No. 2,757,125.
Methods for steam-
related oil recovery from an oil sand reservoir are described in this
document. As well, the
document teaches conditions under which fluid communication may be established
between a
well pair in an oil-sand reservoir having a dilatable inter-well region. Steam
or water may be
circulated within one or both wells of a well pair, to apply sufficient
pressure to dilate the oil
sands in the inter-well region. In this way, steam or water dilation may be
employed to
enhance fluid communication between the well pair. Such a method may be
employed in
concert with the method described herein for increasing overall fluid
mobility.
[0083] An Embodiment, In Practice. Exemplary procedures which may be used in
the field
for SAGD wells may include the following details. It is to be understood that
the procedure
need not be limited to these exemplary embodiments.
[0084] Treatment with one or more microorganism, as described herein, may
occur by
placing an inoculant solution containing the microorganism into placed in one
or both of the
injector or producer SAGD wells. Varying durations of time may be employed to
allow for
29
CA 02831928 2013-11-01
the solution to soak into the formation and decrease bitumen viscosity. The
optimal time
required for soaking in may depend on characteristics of the oil sands
reservoir in the region.
[0085] A mixture of microorganisms may be used, such as the 12 strain mixture,
noted above,
containing aerobic and anaerobic bacteria that have been selected to degrade
the heavy ends
(C16 hydrocarbons or greater) of the bitumen. In some embodiments, although
not wishing to
be limited by theory, the microorganisms may produce byproducts that act as
bio-surfactants
and solvents. Gases may also be produced. The bacteria can colonize a portion
of, or the
entire near-wellbore region, while metabolizing the heavy ends of hydrocarbon
as food
source. The bacterial culture can stay viable for is 6-8 weeks. Strains that
can last for shorter
or longer periods of time may be employed. The microorganisms may optionally
be designed
not to reproduce, or to have reduced viability following a set period of, for
example 6 -8
weeks.
[0086] To prepare the wells for the SAGD stage, and achieve communication
where there is
lack of injectivity, the inoculant solution can be pumped into both the
injector and producer
wells, or only into one of the injector or the producer well. If it is decided
to inoculate both
injector and producer wells, an exemplary amount of about 12 m3 of fluid may
be included in
each well. If it is decided to inoculate only one well, an initial volume 20
m3 can be pumped
into the well.
[0087] After a soaking period of 2-3 weeks, the microbial solution may be
recirculated in
order to induce the microorganisms to keep moving and colonizing along the
wellbore.
Optionally, additional volumes of inoculant solution can be injected into the
wellbore in order
to squeeze the rest of the microorganisms further into the reservoir. The
additional volume
would then be permitted a further soaking of about 2-3 more weeks. Estimated
total volumes
CA 02831928 2013-11-01
to be injected in this example would be about 36-40 m3, or 2X to 3X the
initial volume of
inoculant solution.
[0088] Wells may be tested for communication utilizing steam injection into
the injector well.
If communication is achieved between well pairs, normal SAGD operations may
then
commence. As microorganisms typically die in temperatures higher than 95 C,
the start of
SAGD ends the role of the inoculant microorganisms. However, subsequent re-
inoculation
cycles may occur.
[0089] In the event that communication is not achieved, an alternative, such
as dilation or
steam circulation start up methodologies may also be considered.
EXAMPLES
[0090] Example 1: Simulation Single Well.
[0091] Overview of Example 1.
[0092] Two sets of simulations were performed to illustrate the effect of
water saturation on
start-up steam mobility Steam injection was simulated through the producer and
no injector
was simulated. A homogeneous model with live oil (15% wt methane) was used in
the
simulation. The producer completion was modelled after a standard SAGD well. A
steam
injection rate of 240 t/d was maintained until a cumulative injection volume
of 3000 t was
achieved (12.5 d).
[0093] In the first set of simulations, bottom-water was used to provide the
reservoir with a
mechanism for water displacement. The minimum water saturation for which a
flow rate of
31
CA 02831928 2013-11-01
240 t/d could be sustained was Sw=25%. Maximum wellhead pressures for the
system at the
limiting water saturation were approximately 5422 kPag in the casing and 6400
kPag in the
tubing. The tubing pressure at the wellhead corresponds to the maximum
allowable wellhead
pressure. Maximum down-hole pressure in both the tubing and casing were near
6400 kPag
suggesting that at a saturation of S=25% a large pressure gradient must exist
in order to push
steam from the well, through the transition zone and into the bottom-water. It
should be
noted that this maximum steam pressure need only be maintained for a short
time (roughly 1
d) until the mobility of the water in the reservoir improves.
[0094] In the second set of simulations, a water-rich zone at equal elevation
to the pay zone
was used to provide a mechanism for water displacement. The minimum water
saturation for
which a flow rate of 240 t/d could be sustained was Sw=37%. Wellhead pressures
for the
system (at transition zone Sw=37%) reached a maximum of 5500 kPag and 6400
kPag for the
casing and tubing, respectively. Down-hole pressure was approximately 4500
kPag in the
casing and 4800-4700 kPag in the tubing.
[0095] In both simulations, the minimum water saturation was the saturation at
which the
wellhead pressure reached the constraint of 6400 kPag (or 6500 kPag absolute).
The higher
minimum water saturation for the second set of simulations (with mobile water
located at
equal elevation to the reservoir) is due to the shorter and wider transition
zone.
[0096] Details of Experimental Example 1. An objective of this Example was to
determine
the lowest possible water saturation which allows for steam injectivity of 240
t/d per well pair
32
CA 02831928 2013-11-01
and a cumulative steam injection of 3000 t during well start-up. Two
geometries were
considered in this Example. The first consisted of a homogeneous live-oil
reservoir with
bottom-water. The second consisted of an identical reservoir, but with the
bottom-water
replaced by an infinitely large water-rich region at the same depth as the pay
zone.
[0097] In both simulations, the reservoir dynamics as well as the wellbore
dynamics in the
horizontal and build sections were simulated. A summary of the reservoir
properties and
conditions is listed in Table 1 below. The wellbore was modelled using a
standard
completion approach to SAGD in an oil sands reservoir.
Table 1
Reservoir Properties
Property Value Units
Initial Temperature 12 C
Initial Pressure 3000 kPa
Methane in Oil 15 Mol %
Ka (x/y/z) 4/4/2 Darcies
Initial Oil Saturation 80
Initial Water Saturation 20
Porosity 0.35
Width/Length/Height 50/732/20
33
CA 02831928 2013-11-01
[0098] Simulation details are as follows: casing, tubing and ports were all
included in the
simulation. The Bubble tube was not included in the simulation as it has
minimal effect of the
flow dynamics. The port was simulated using a compressible port model. Heat
loss around
the reservoir and build section was simulated using a shale property model. It
should be noted
that half-geometry models were used for the reservoir. As a result, the
simulation stopped
when (3000/2 =) 1500 t were injected. Also, the in-simulation rate of
injection was half of the
240 t/d specified for this problem.
[0099] The infinitely-large water region was simulated using a water-rich
region (Sw=100%)
containing several production sources. The pressure of these production
sources was kept at
3000 kPa. This allowed mobile fluids at pressures greater than 3000 kPa to be
removed from
the system.
[00100] Two geometries were considered in Example 1. A geometry for the bottom
water
simulations and a geometry for the side-water simulations.
[00101] Bottom-Water Simulations. The first set of simulations was proposed
for the geometry
illustrated in Figure 1 herein. Under this geometry, a homogeneous rectangular
reservoir of
live oil was bounded on three sides by a shale heat-loss grid and underneath
by bottom-water
(S,=100%). In addition the bottom 2 m of the reservoir contained a transition
zone with
50%>Sõ>20%. The producer well (which was operated as a steam injection well)
was placed
in the middle of the transition zone (i.e., 1 m above the bottom-water).
34
CA 02831928 2013-11-01
[00102] The simulations were run until a cumulative injection mass of 3000 t
(1500 t in-
simulation due to half-geometry) was achieved. The injection rate was 240 t/d
(120 t/d in-
simulation due to half-geometry). At a water saturation of 25% it was found
that an injection
rate of 240 t/d was sustainable. However, at a water saturation of 22%, it was
found that the
injection rate of 240 t/d was not sustainable. As a result, the predicted
minimum water
saturation is between 25% and 22%. A value of 25% is reported in this work
because it is the
lowest value for which a rate of 240 t/d was successfully sustained.
[00103] In order to inject 3000 t of steam at 240 t/d the simulation had to be
run for at least
12.5 d. Wellhead pressure as a function of time for the first 12.5 d of
simulation is shown in
Figure 1. As shown in Figure 2, the maximum injection pressure was attained
early in the
simulation (after roughly 1 d). As the simulation progressed, the wellhead
pressure decreased
considerably. This is likely due to the effect of steam in improving the
mobility of water in
the reservoir. Specifically, it is likely that the increased mobility is due
to viscosity reduction
associated with temperature rise due to steam penetration and condensation in
the reservoir.
[00104] Casing and tubing pressure for the bottom-water system, after 12.5 d,
as a function of
distance from surface is shown in Figure 2 herein. As can be seen from Figure
3, the
pressures in the horizontal section of the well are in-line with typical
operating pressures.
This suggests that once a high rate of steam injection is obtained it can be
maintained.
[00105]Side-Water Simulations. A second set of simulations was proposed for a
side-water
system geometry illustrated in Figure 4 herein. Under this geometry, a
homogeneous
CA 02831928 2013-11-01
rectangular reservoir of live oil was bounded on four sides by a shale heat-
loss grid and to the
side by mobile water (Sw=100%). As with the geometry described in the bottom-
water
section above, the bottom 2 m of the reservoir contained a transition zone
with 50%>Sw>20%.
The producer well (which was operated as a steam injection well) was placed in
the middle of
the transition zone (i.e., 1 m above the bottom-water).
The distance of transition zone
between the side-water and the producer was 49.5 m.
[00106] The simulations were run until a cumulative injection mass of 3000 t
(1500 t in-
simulation due to half-geometry) was achieved. The injection rate was 240 t/d
(120 t/d in-
simulation due to half-geometry). At a water saturation of 37% it was found
that an injection
rate of 240 t/d was sustainable. However, at a water saturation of 35%, it was
found that the
injection rate of 240 t/d was not sustainable. As a result, the predicted
minimum water
saturation is between 35% and 37%. A value of 37% is reported in this work
because it is the
lowest value for which a rate of 240 t/d was successfully sustained.
[00107] In order to inject 3000 t of steam at 240 t/d the simulation had to be
run for at least
12.5 d. Wellhead pressure as a function of time for the first 12.5 d of
simulation is shown in
Figure 3 herein. As shown in Figure 5, the pressure dynamics for the side-
water system are
qualitatively different than the dynamics for the bottom-water system. In the
side-water
system the wellhead pressure starts low and builds up over time. While the
rate of 240 t/d can
be sustained, it is at the price of ever increasing wellhead pressure; as
such, it is less likely
that this injection rate can be maintained past 12.5 d. Unlike the bottom-
water system, the
dynamic whereby steam increases water mobility and allows for flow at lower
pressures is not
36
CA 02831928 2013-11-01
present. This may be due to the long path the injection fluid must take in
order to reach the
mobile water and the associated heat.
[00108] Casing and tubing pressure, for the side-water system, after 12.5 d,
as a function of
distance from surface is shown in Figure 6. As can be seen from Figure 6, the
entire
horizontal well section is nearly at the maximum wellhead pressure. This
suggests that the
flow in this system is hindered (and is limited) by the distance and cross-
sectional area of
transition zone channel to the mobile water.
[00109]From the simulations of the bottom- and side-water systems it appears
that at the
minimum water saturation, the system is constrained by the wellhead pressure.
It is useful,
therefore to examine the relationship between wellhead pressure and water
saturation. To do
this, both geometries were simulated using S, values of 50, 45 40 and 37%. The
bottom-
water system was additionally simulated at S, values of 35, 30, and 25%. The
maximum
tubing wellhead pressure for each simulation as a function of water saturation
is shown in
Figure 5 herein.
[00110]As can be seen from Figure 7, the geometry of the bottom-water
simulation
(characterized by a wider and shorter transition zone) implies that, at a
given saturation, less
pressure is required to drive a fixed amount of steam into the reservoir. The
proximity of
mobile water is therefore critical in determining the minimum water saturation
at which steam
can be injected into the reservoir.
37
CA 02831928 2013-11-01
[00111] Conclusions for Example I. The two foregoing simulations were
performed in order
to exemplify the effect of water saturation on the ability of a reservoir to
accept steam at a rate
of 240 t/d. The first set of simulations corresponded to a system geometry
with bottom-water
and a 2 m transition zone with 1 m between the well and the bottom-water. For
this set of
simulations, the simulation data results reasonably predict that one can
inject steam for
transition zone water saturations as low as 25%. This saturation corresponded
to the
constraint well head pressure of 6400 kPag. The second set of simulations
corresponded to a
geometry with side-water and a 2 m (width) x 50 m (length) transition zone
with the well
being positioned 49.5 m from the mobile water. For this set of simulations,
the simulation
data results reasonably predict that steam can be injected for transition zone
water saturations
as low as 37%. This saturation corresponds to the constraint well head
pressure of 6400
kPag.
[00112] Example 2: Simulation Two Well System.
[00113] Overview of Example 2. A single set of simulations were performed to
illustrate the
effect of water saturation on start-up steam mobility for a generic well pair.
Steam injection
was simulated from an injector to a producer well. A homogenous model with
live oil (15%
wt methane) was used in this simulation. The injector and producer completions
were
modelled after a standard SAGD well pair. The injection wellhead pressure was
maintained
at 8000 kPa. A maximum pressure differential of 7000kPa was maintained between
the
injector and producer wells.
38
CA 02831928 2013-11-01
[00114]A water saturation of Sw = 25% was found to allow steam to be injected
into the
injector at a sustained rate of at least 240 t/d after about 13 days. The
maximum well head
pressure at this water saturation was approximately 8000 kPag. It should be
noted that the
maximum steam pressure differential of 7000kPa need only be maintained for 18
days until
the mobility of the fluid in the reservoir improves.
[00115]Details of the Experimental Example 2. An objective of this Example was
to
illustrate that a saturation of Sw = 25% was sufficient to allow for a steam
injectivity of 240
t/d per well pair in a relatively short period of time (around about 12 days).
[00116]In these well pair simulations, the reservoir dynamics as well as the
well bore
dynamics were simulated. A summary of reservoir properties and conditions is
provided in
Table 1 above. The well bores were modelled using a standard completion
approach in a
SAGD well pair.
[00117] Simulation details are as follows: casing, tubing and ports were all
included in the
simulation. The Bubble tube was not included in the simulation as it has
minimal effect on
the flow dynamics. The port was simulated using a compressible port model.
Heat loss
around the reservoir and injector build section was simulated using a shale
property model.
The simulation was run for 40 days. It should be noted that this is longer
than the time
necessary to achieve a rate of 240t/d of steam injection.
39
CA 02831928 2013-11-01
[00118] The geometry for the two-well simulations is shown in Figure 8 herein.
Under this
geometry, the homogeneous rectangular reservoir of live oil was bounded on
four sides (top,
bottom, heel, and toe) by shale heat loss grids. The area to the left and
right of the reservoir
was not connected to a heat loss grid in order to allow for half symmetry. The
reservoir was
modelled with a 20m pay thickness and was 732m in length. A typical inter-well
spacing of
100m was assumed. The producer was placed at the bottom of the pay zone. The
injector
was placed, using a typical inter-well spacing of 5m, above the producer.
[00119] Tubing (or injection) wellhead pressure was maintained at 8000 kPa for
this
simulation. Casing wellhead pressure as a function of time for all 40 days of
simulation is
illustrated in Figure 9. As shown in Figure 9, there is little drop in the
casing wellhead
pressure from 2 to 20 days. As the simulation progressed past about 20 days,
the casing
wellhead pressure decreased considerably. This is likely due to the increased
mobility of
fluids in the reservoir related to steam injection. Specifically, it is likely
that the increased
mobility is due to viscosity reduction associated with temperature rise
related to steam
penetration and condensation in the reservoir.
[00120] Casing and tubing pressure for the two-well system, after 40 days as a
function of
distance along the horizontal section of the well for both the injector and
producer are shown
in Figure 10 herein. As can be seen from Figure 10, the pressure in the
horizontal section of
the casing is in line with typical operating pressures. This suggests that
once a high rate of
steam injection is obtained, it can be maintained.
CA 02831928 2013-11-01
[00121] Conclusions for Example 2. The foregoing simulations were performed in
order to
exemplify the effect of water saturation on the time taken to establish
communication between
a well pair. This set of simulations corresponds to a system geometry as
illustrated in Figure
7 and having the properties shown in Table 1. For this set of simulations the
simulation data
reasonably predicts, that if the initial inter-well water saturation is Sw =
25%, one can
establish inter well communication with a saturated steam injection rate of
240t/d at 8000kPa
well head pressure after the end of 12 days.
[00122] Example 3: Lab testing.
[00123] Overview of Example 3.
[00124] Static tests were conducted in the lab in order to verify the
effectiveness of a bacterial
culture in increasing the mobility of fluid in the reservoir. Tests were
conducted using a
mixture of bacteria capable of metabolizing heavy ends of C20 or greater from
a hydrocarbon
phase. In this example mobility parameters of the resulting fluids were
studied in a lab scale
reservoir.
[00125] Details of the Experimental Example 3. Two tests were conducted in the
lab in order
to verify the effectiveness of a mixed bacterial culture in upon the mobility
of fluids in a
laboratory reservoir.
[00126] Two samples of 200g reservoir sand that was highly saturated with oil
were used and
completed with 700 ml of a bacterial solution at different concentrations in
two different
containers. This solution contained an aqueous bacterial mixture (70%) and
organic solvents
41
CA 02831928 2013-11-01
(30%). The bacterial mixture contained a microbial mixture of BC-10 BacteriaTM
(BioConcepts, Inc., Kemah, TX), a mixture of 12 strains of anaerobic and
aerobic bacteria,
having the ability to metabolize heavy ends, or hydrocarbons of C16 or
greater.
[00127] In a separate test, a sample with 400g of reservoir sand and 400 ml of
bacterial
solution having the same composition as above, was tested in order to evaluate
the
sand/microbial solution relationship to estimate the volume of solution that
will be required to
inoculate the well.
[00128] The tests were conducted at room temperature. Wells were inoculated
with the
bacterial mixture, and maintained at room temperature under conditions
adequate for viability
and propagation of the bacteria. After 24 to 48 hours of exposure, the oil
started to separate
and mobilize from the sand, and sit on top of the samples. After a two week
soaking period,
most of the oil in the sand became mobilized.
[00129] The total oil recovered from the samples was measured. For this test,
the total oil
recovered was quantified and compared to the original volume of oil in the
original sand.
[00130] Table 2 shows the initial sample properties and properties of the oil
observed in one
of the 200g test samples. The designation of crude oils based on density may
be evaluated
with API (American Petroleum Institute) gravity, a common measure of the
density of liquid
petroleum, measured in degrees.
42
CA 02831928 2013-11-01
Table 2
Sample Properties and Initial Oil Properties
Property Value Units
Temperature 18 (room conditions) C
Initial Oil Content 90
Initial Water Content 10
Porosity 0.35
API 8-10 Degrees
Viscosity 122,333 cP
Density 1.0076 g/cc
Oil volume in sample 27.19 ml
Sample volume 200
Microbial solution volume 700 ml
[00131]Results for Example 3. After two weeks of a soaking period, the 200g
samples were
analyzed in the lab in order to measure the recovered oil new properties and
evaluate its
effectiveness. It was observed that most of the oil mobilized to the top of
the sample. The
amount of oil recovered was quantified and the sand was tested using Dean-
Stark method to
measure the remaining oil fraction in the sample. Results were then compared
to the original
volume of oil in the original sand in order to evaluate the properties of the
recovered oil and
evaluate effectiveness.
43
CA 02831928 2013-11-01
[00132] The 400g samples were analyzed after a 23 day soaking period. Oil also
mobilized on
top of the jars, and the properties of the recovered were evaluated following
the methodology
noted above for comparison with the original properties and volume of oil in
the original
sample.
[00133] The properties of the sample following lab scale microbial treatment
of the 200g
samples show that, at room temperature (18 C), initial oil content was 90%,
while initial
water content was 10%. Porosity was 0.35%. After microbial treatment API was
about 27
degrees, viscosity was greatly reduced to about 1.7-1.9 cP, and density showed
a change to
the level of from about 0.887-0.890 g/cc. 14 g of total oil was recovered from
one of the
samples after 2 weeks of soaking. Additional data is shown in the tables
below.
[00134] The results confirm that the microbial treatment using a mixture of
bacteria capable of
metabolizing heavy ends, resulted in a marked decrease in viscosity relative
to the starting
value of the solution. This dramatically impacted the mobility of the oil,
increasing API from
8-10 to 27, and decreasing viscosity from about 122,300 cP to about 1.7-1.9
cP.
[00135] Notably, the two week laboratory scale process using the 200g jars
with 700m1 of
bacterial solution, the total recovered oil was 44-49% of the original sample.
This was a
satisfactory result. As this was a static test, it is noted that the remaining
oil in the sand could
be mobile in the sand pores. The viscosity of the oil decreased from about
122,333 cP to about
1.7-1.9 cP, and the quality of the oil increased from 8-10 API to 27 API under
room
temperature conditions.
44
CA 02831928 2013-11-01
[00136] In the tests employing the 400g sample mixed with 400 ml of microbial
solution, the
total recovered oil was about 21-40%. This test incorporates the assumption
that there is
mobile oil in the sand pores. The viscosity of the oil decreased from about
122,333 cP to
about 5.4 cP, and the quality increased from 8-10 API to 21.8 API under room
temperature
conditions.
[00137] A comparison of the parameters indicative of or pertaining to overall
fluid mobility
before and after treatment of oil sand for the 200g samples illustrates good
efficacy. The oil
content was reduced while the water content of the sample increased from about
10% to about
12%. Increased water saturation increases the mobility of fluid in the
vicinity. Viscosity was
greatly reduced from 122,333 to 1.7 cPs in one of the samples. The density
change was also
remarkable, starting at about 1002 g/cc in the original sample, and resulting
in 0.877 g/cc
following a 2 week microbial treatment. The API also increased from about 8-10
to about 27,
indicative of a lightening of the oil, and an increase in fluid mobility
attributable to a
reduction in heavy ends following microorganism metabolism. Of the 27.19 mL of
oil in one
of the samples, about 14 mL of this was recovered. Further data is provided in
the tables
below.
[00138] Table 3 and Table 4 provide data pertaining to sample characteristics
for both the
200g samples and the 400 g samples as well as a control (uninoculated) sample.
CA 02831928 2013-11-01
. ..
Table 3
Density and Viscosity of Isolated Oil Fraction
Bacteria:Sample Density
Sample (g:mL)
Volume (mL) Density (15 C)
API (15.6 C)
kg/m3
DPS Pre-treated 200:700 220 890.5
27.3
200 Solution A
DPS Pre-treated 200:700 240 887
27.9
200 Solution B
200 Control 201:0 n/a n/a
n/a
400 Control 404:0 n/a n/a
n/a
400 Treatment A 400:400 120 924.4
21.5
400 Treatment B 400:400 120 922.5
21.8
Bacteria:Sample Kinematic Viscosity
Sample (g:mL)
20 C (cSt) 30 C (cSt)
40 C (cSt)
DPS Pre-treated 200:700 2.163 1.827
1.574
200 Solution A
DPS Pre-treated 200:700 1.944 1.651
1.425
200 Solution B
200 Control 201:0 n/a n/a
n/a
400 Control 404:0 n/a n/a
n/a
400 Treatment A 400:400 9.665 7.272
5.666
400 Treatment B 400:400 8.622 6.55
5.144
Bacteria:Sample Dynamic Viscosity
Sample (g:mL)
20 C (cP) 30 C (cP)
40 C (cP)
DPS Pre-treated 200:700 1.919 1.607
1.372
200 Solution A
DPS Pre-treated 200:700 1.717 1.445
1.237
200 Solution B
200 Control 201:0 n/a n/a n/a
400 Control 404:0 n/a n/a n/a
400 Treatment A 400:400 8.899 6.644
5.135
400 Treatment B 400:400 7.923 5.97
4.651
46
CA 02831928 2013-11-01
Table 4
Composition of Isolated Sand Fraction
Bacteria:Sample Mass
Sample (g:mL)
Sample Mass Dean-Stark Dean-Stark
Tested (g) Solids (g) Water (g)
DPS Pre-treated 200:700 159.2 127.6 19.3
200 Solution A
DPS Pre-treated 200:700 148.6 116.8 18.3
200 Solution B
200 Control 201:0 200.6 170.6 2.6
400 Control 404:0 404.9 339.3 3.8
400 Treatment A 400:400 462.2 355.2 72.9
400 Treatment B 400:400 456.8 351 61
Bacteria:Sample Dean-Stark Fractions
Sample (g:mL)
Solids (Wt. %) Water (Wt. %) Oil (Wt. %) by
difference
DPS Pre-treated 200:700 80.20% 12.10% 7.70%
200 Solution A
DPS Pre-treated 200:700 78.60% 12.30% 9.10%
200 Solution B
200 Control 201:0 85.00% 1.30% 13.70%
400 Control 404:0 83.80% 0.90% 15.30%
400 Treatment A 400:400 76.80% 15.80% 7.40%
400 Treatment B 400:400 76.80% 13.40% 9.80%
Bacteria:Sample Recovery
Sample (g:mL)
Estimated Oil Oil Recovered
Remaining in (mL) RF%
Sand (mL)
DPS Pre-treated 200:700
200 Solution A 13.81 13.38 49
47
CA 02831928 2013-11-01
DPS Pre-treated 200:700
200 Solution B 15.22 11.97 44
200 Control 201:0 27.19 n/a n/a
400 Control 404:0 61.33 n/a n/a
400 Treatment A 400:400
36.89 24.45 40
400 Treatment B 400:400
48.56 12.77 21
[00139] The following tables provide a side-by side comparison of results for
the 200 g sample
(Table 5) and the 400 g samples (Table 6). Notably, the two weeks laboratory
scale process
resulted in recovery of about 49% of the oil.
Table 5
Comparison Table before and After Treatment (200g sample)
Property Original Sample Sample After Microbial
(Pre-treatment) Treatment
(*2 weeks)
Oil 90% (So estimated) ¨7% *Estimated percentage
of oil in the isolated sand
fraction
Water 10% (Initial Sw) ¨12%*Estimated percentage
of water in in the isolated
sand fraction
Oil Viscosity 122,333 cP 1.7 cP
Oil Density 1,0076 g/cc 0.887 g/cc
Oil API 8-10 27
Total oil recovered from 27.19 ml 12-13 ml (44-49%
sample Recovered from sample oil)
Table 6
Side-by Side Comparison Table Before and After Treatment (400g samples)
Property Original Sample Sample
After Microbial
48
CA 02831928 2013-11-01
(Pre-treatment) Treatment
(*2 weeks)
Oil 90% (So estimated) 9.80% *Estimated
percentage
of oil in the isolated sand
fraction
Water 10% (Initial Sw) 13.40%*Estimated percentage
of water in in the isolated sand
fraction
Oil Viscosity 122,333 cP 5.9 cP
Oil Density 1,0076 g/cc 0.922 g/cc
Oil API 8-10 22
Total oil recovered from 61.33 ml 13-24 ml (21-40%
sample Recovered from sample oil)
[00140] Results of both tests establish the favorable impact that inoculation
with
microorganisms has on fluid mobility parameters. An exemplary field treatment
with a
microbial solution may employ a volume of the solution that is about 3-fold or
more of the
estimated volume for a standard horizontal section of the well. An exemplary
estimated
volume of 800 m of horizontal well section would be about 12 m3, and thus a
volume of three
times this would be about 36-40 m3.
[00141] Positive results from this microbial enhanced start-up illustrate that
the method
described herein for increasing overall fluid mobility in a near-wellbore
region in an oil sands
reservoir has the potential to optimize the recovery of oil from a reservoir
in the same manner
as can be realized using stream-based or solvent-based processes. Benefits of
solvent
utilization may include reduced emissions intensity, reduced water handling
intensity, and
reduced fuel gas consumption intensity (with "intensity" referring to per
barrel of oil
produced). Further, it is beneficial to have optional technologies to
supplement or augment
existing technologies used field recovery from oil sand, as such technologies
can act be
49
CA 02831928 2013-11-01
accessed when economic, environmental, or climate conditions render certain
options less
economical.
[00142] Conclusions for Example 3. The method described herein was effective
at increasing
overall fluid mobility in a laboratory scale version of a near-wellbore region
in an oil sands
reservoir. Oil phase (hydrocarbon phase) saturation decreased, while water
saturation
(aqueous phase) increased. Viscosity was greatly reduced, thereby increasing
the flowability
of the oil. The increase in API demonstrates that the heavy ends of the oil
were metabolized,
resulting in a lighter gravity. A commensurate change in density was observed.
The recovery
observed for this lab scale example serves to illustrate that this method may
offer an
alternative to SAGD, or may be used for wells after SAGD is completed, in an
effort to
recover residual oil when SAGD becomes less economical.
[00143] While specific embodiments have been described and illustrated, such
embodiments
should be considered illustrative only and not as limiting the invention as
construed in
accordance with the accompanying claims. Other features and advantages will be
apparent
from the following description, drawings and claims.
[00144] It will be understood that any singular form is intended to include
plurals herein. For
example, the word "a", "an" or "the" is intended to mean "one or more" or "at
least one."
Plural forms may also include a singular form unless the context clearly
indicates otherwise.
CA 02831928 2013-11-01
[00145] It will be further understood that the term "comprise", including any
variation thereof,
is intended to be open-ended and means "include, but not limited to," unless
otherwise
specifically indicated to the contrary.
[00146] When a list of items is given herein with an "or" before the last
item, any one of the
listed items or any suitable combination of two or more of the listed items
may be selected
and used. For any list of possible elements or features provided in this
specification, any sub-
list falling within the given list is also intended.
[00147] The above described embodiments are intended to be illustrative only
and in no way
are to be construed as being limiting. The described embodiments are
susceptible to many
modifications of form, arrangement of parts, details and order of operation.
All such
modification are encompassed herein.
51
