Note: Descriptions are shown in the official language in which they were submitted.
CA 02841520 2014-01-31
SYSTEM AND METHOD FOR RECOVERY OF BITUMEN FROM
FRACTURED CARBONATE RESERVOIRS
Inventors: Daniel Yang, Moslem Hosseininejad, Stephen Brand, Neil Edmunds,
Darcy
Riva, Wei Wei
Owner: LARICINA ENERGY LTD.
TECHNICAL FIELD
The present disclosure is generally related to a system and method for
recovering
hydrocarbons (e.g. heavy oil, bitumen) from subterranean fractured carbonate
reservoirs.
More specifically, the present disclosure relates to a system and method
consisting of a
combination of cycling injection and production from the same downhole well
within a
reservoir to recover bitumen, and subsequent continuous injection via a second
adjacent
well while producing bitumen from the first well.
BACKGROUND
It is well known that reserves of non-renewable resources continue to decline
and
that those remaining, such as bitumen contained in carbonate formations, are
difficult to
recover. As a result, significant research and development into improved
methods of
bitumen recovery are being conducted.
In Alberta, Canada, an estimated 80 billion cubic meters of bitumen are
contained in carbonate reservoirs. One such reservoir, the Upper Devonian
Grosmont
Formation of northeastern Alberta, is a dolomite carbonate reservoir with
heterogeneous
porosity and permeability estimated to contain over 64 billion cubic meters of
oil. The
bitumen contained in the Grosmont Formation is not producible by conventional
methods
due to the high viscosity of the bitumen, and the complex nature of the
formation
geology. Carbonate reservoirs, however, have fractures and vugs that can form
an
extensive network of pathways for gravity drainage of the bitumen.
In oil sands reservoirs, bitumen has been traditionally recovered by surface
mining or in situ recovery processes. In situ recovery processes increase
bitumen
mobility through heat or dilution, and most commonly use steam (e.g. steam
assisted
gravity drainage (SAGD), cyclic steam stimulation (CSS), and steam flooding).
Other in
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situ processes use a combination of steam and solvent (e.g. Expanding Solvent
SAGD
(ES-SAGD), Liquid Addition to Steam to Enhance Recovery (LASER)). Research on
pure solvent processes (e.g. Vapor Extraction Process (VAPEX) and N-Solv) is
being
conducted. Forms of electrical heating are also under development (e.g.
Electro-Thermal
Dynamic Stripping Process (ET-DSP)) and some include solvent (e.g. Enhanced
Solvent
Extraction Incorporating Electromagnetic Heating (ESEIEH)).
The use of SAGD and CSS has been in the Grosmont Formation since the 1970s.
These attempts were unsuccessful and the industry instead focused on the
commercialization of SAGD in unconsolidated sandstone where the geology tended
to be
more consistent than that of the fractured carbonate reservoirs. For example,
one attribute
of traditional SAGD, is the requirement that the injection wells be
approximately 5 ¨ 7m
directly above the production wells. It is well known that in sandstone
applications, the
vertical proximity of the injection and production wells is required to
effectively establish
thermal communication between the wells. SAGD wells are operated with a liquid
saturated layer above the producer by controlling the temperature of the
producer in what
is referred to as steam trap controlled production. However, the vertical
spacing between
injection and production wells used in SAGD is likely inoperable in fractured
carbonate
reservoirs where steam from the injection well readily passes through
fractures directly to
the production well making it impossible to maintain the sub-cool temperature
required
for oil production.
Cyclic steam stimulation (or "huff and puff') process requires the injection
of
steam, a period of soak time and followed by production. CSS inherently has a
lower
recovery factor than SAGD because efficiency of the process declines with each
cycle,
which makes it uneconomical to operate much beyond 20% recovery of the
original oil in
place. In fractured carbonate reservoir, CSS is not feasible because the
fracture network
prevents pressure build up thus inhibiting the soak period. Hence, a recovery
mechanism
that depends on geo-mechanical effects is not achievable in fractured
carbonate
reservoirs.
A commercially viable system and method to recover bitumen from fractured
carbonate formations is needed. Such a method may comprise a combination of
cyclic
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and continuous recovery methods, whereby the cyclic operation may be
practical,
effective and necessary in an early phase in order to condition the reservoir
for a second
phase of continuous production.
SUMMARY
A system and method for recovering bitumen from fractured carbonate reservoirs
is provided, said reservoir having at least a first and at least a second
downhole well
vertically spaced from one another, the system and method consisting of the
combination
of:
a first cyclic phase involving the injection of a first well injectant through
the at
least one first well, ceasing injection of the first injectant and producing
bitumen
through the first well, and continuing this cycling phase until bitumen
adjacent the
at least one second well is mobilized, and
a second continuous phase involving the injection of a second injectant
through
the at least one second well and continuing to produce bitumen from the at
least
one first well.
The first and second well may be positioned substantially vertical to one
another,
with the at least one first well being substantially below the at least one
second well. In
one embodiment, the at least one first well may be positioned at or near a
lower zone of
the reservoir, while the at least one second well may be positioned at or near
an upper
zone of the reservoir.
Cycling of the first phase may continue the mobilization of bitumen in the
fractures of the reservoir expands to or near the at least one second well. It
is desirable
that the second continuous or substantially continuous phase of the present
system and
method may establish stable gravity drainage of bitumen from the reservoir
matrix. To
maintain a fluid a density difference between fractures and matrix.
First and second injectants may be heat-carrying fluids having a lower density
relative to the bitumen in the reservoir. First and second injectants may be
capable of
transfering heat to the reservoir, thereby changing the properties of the
carbonate rock
formation and/or fluids therewithin, and may be, for example, steam, steam and
solvent,
steam and non-condensable gas, solvent, non-condensable gas, or a combination
thereof.
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In one embodiment, a method for recovering bitumen from fractured carbonate
reservoirs, said reservoir having at least a first and a second downhole well
vertically
spaced from one another is provided, the method comprising:
a) injecting a first injectant into the reservoir through the at least one
first well,
b) ceasing injection of the first injectant and producing bitumen through the
at
least one first well,
c) cycling steps a and b, until the bitumen adjacent the at least one second
well is
mobilized,
d) injecting a second injectant into the reservoir through the at least one
second
well, and
e) continuing to produce bitumen via the at least one first well.
In another embodiment, a system for recovering bitumen from a fractured
carbonate reservoir is provided, the system consisting of at least one first
well for
injecting first well injectant into the reservoir and producing bitumen from
the reservoir,
at least one second well, positioned substantially above the at least one
first well, capable
of injecting a second injectant into the reservoir, wherein the at least one
first well and at
least one second well are at least 25 meters apart from one another.
DESCRIPTION OF THE DRAWINGS
Figure 1 shows a schematic illustration of one embodiment of the present
system and
method in a fractured carbonate reservoir having steam (S), water (W), and
mobile
bitumen (B) in matrix (M), during an injection stage of the first cyclic phase
(Fig. 1A),
the production stage of the first cyclic phase (Fig. 1B), and the
injection/production stage
of the second phase (Fig. 1C); and
Figure 2 shows a side view schematic of one embodiment of the present system
and
method showing a well pair positioned within the upper and lower zones of the
same
reservoir;
Figure 3 shows a side view schematic of one embodiment of the present system
and
method showing a well pair positioned in upper and lower zones of adjacent
reservoirs;
Figure 4 shows a cross-sectional schematic of the well pair shown in Fig. 2;
CA 02841520 2014-01-31
Figure 5 shows a cross-sectional schematic showing a well pair being offset
wherein first
bottom wells 10 are in fluid communication with second top well 20;
Figure 6 shows a cross-sectional schematic of the well pairs showing in Fig.
3;
Figure 7 shows a cross-section schematic of a well pair being offset wherein
first bottom
5 well 10 is in fluid communication with second top wells 20 positioned in an
adjacent
reservoir; and
Figure 8 shows a cross-section schematic of a well configuration comprising at
least one
first well 10, at least one second well 20, and at least one third well 30;
Figure 9 shows a graph plotting the viscosity of bitumen relative to the
temperature of the
bitumen;
Figure 10 shows a schematic of gravity drainage through the reservoir towards
at least
one bottom production well 10; and
Figure 11 shows the flow of bitumen B where flow barriers are encountered and
bitumen
B drains in and out of the M (A), and into the fracture network (B).
DESCRIPTION OF THE EMBODIMENTS
The present system and method relate to bitumen recovery from fractured
carbonate reservoirs, said reservoir having at least two downhole wells that
are vertically
separated from one another, and preferably positioned substantially above and
below one
another. More specifically, the present system and method generally relate to
the
combination of two phases, namely, a first cyclic phase to achieve
mobilization of
bitumen in the reservoir, consisting of cycling the injection of a heat-
carrying fluid into
the reservoir and production of bitumen from at least one first downhole well
until
bitumen is mobilized between the first well and at least one second well
adjacent thereto,
and a second continuous phase consisting of the injection of a heat-carrying,
lower
density fluid via the second well while continuously producing bitumen from
the first
well. In one embodiment, the first well may be positioned substantially lower
or below
the second well, but any reference to the wells as top, bottom, upper or
lower, are for
description purposes only and are not intended to limit or narrow the scope of
the present
system and method.
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Having regard to Fig. 1, in a first embodiment, the first cyclic phase of the
present
system and method may comprise the steps of:
a) injecting a first well injectant into the reservoir via at least one first
well 10
(Fig. 1A),
b) ceasing injection and producing bitumen through the same well 10 (Fig. 1B),
and
c) cycling steps a and b.
The first cyclic phase of the present system and method may be continued until
the mobilization of bitumen in the fracture system expands towards at least
one second
well 20 adjacent to bottom well 10. The first cyclic phase of the present
system and
method may use both the bottom well 10 and the top well 20. The second
continuous
phase would comprise the same steps as the first embodiment.
The second continuous phase of the present system and method may comprise the
steps of:
d) injecting a top well injectant into the reservoir via the top well 20, and
e) producing bitumen via the bottom well 10 (Fig. 1C).
Second well injectant can be continuously injected via the top well 20, and
the
injection rate of said top well injectant can be modified or varied to, for
example,
maintain steam trap controlled production. The composition of the top well
injectant
and/or concentration of additives, if any, can be varied as would be known by
a person
skilled in the art.
Having regard to Figures 2 and 3, first and second wells 10, 20 can be
positioned
within the same reservoir, or reservoirs adjacent to, and in communication
with, one
another (e.g. adjacent reservoirs may be separated by a layer of marl, (L)).
For example,
in the Upper Devonian Grosmont Formation of northeastern Alberta, first and
second
wells 10, 20 could both be positioned within Grosmont C (Fig. 2). However, if
the
Grosmont C and Grosmont D are separated by a layer (L), but still in
communication,
then well 10 could be placed in a lower zone, or Grosmont C, and well 20 could
be
placed in an upper zone, or Grosmont D, which together could be considered the
reservoir (Fig. 3). It is understood that the location or depth (from the
surface) of the
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well placement within the reservoir can vary, particularly depending upon the
overall size
and characteristics of the reservoir.
First bottom well 10 can be a horizontal or deviated well, and can be a
combination of injection and production well. Injection of the bottom well
injectant via
first well 10 can occur until a desired temperature and pressure within the
reservoir unit is
reached that enables bitumen mobility, and then ceased to produce bitumen
located in the
reservoir unit through the same well 10. Second top well 20 can be a vertical,
horizontal
or deviated well, and can be a combination of injection and production well.
It is understood that the distance between first and second wells 10, 20 need
not
be limited and may depend upon the thickness and/or geological heterogeneity
of the
reservoir and the viscosity of the bitumen (e.g. the spacing could be greater
where the
bitumen has lower viscosity and/or the reservoir unit is thicker). In one
embodiment, first
and second wells 10, 20 may be spaced more than 25 meters apart (e.g.
vertically).
Preferably, the first and second wells 10, 20 are spaced between approximately
15 to 25
meters.
Having regard to Figs. 4 and 6, first well 10 can be positioned substantially
above
second well 20. Alternatively, first well 10 may be horizontally offset from
second well
(Figs. 5, and 7). When second well 20 is offset from first well 10, second
well 20
provide support for two horizontally spaced first wells 10 (Fig. 5).
20 Having
regard to Fig. 8, it is contemplated that second well 20 may provide heat
to at least one third wells 30, positioned within the same reservoir or in a
reservoir
adjacent thereto, whereby third wells 30 are generally positioned above second
wells 20.
This arrangement of wells allows for heat transfer and production to occur at
third wells
30.
First and second well injectants can comprise an injectant that may be capable
of
changing the properties of the rock properties as well as the fluids
therewithin. First
bottom well injectant, injected via first well 10 during the first phase of
the present
system and method, may have a lower density fluid (relative to bitumen) that
is capable
of carrying heat and/or a diluent such as steam, steam and solvent, steam and
non-
condensable gas, non-condensable gas, solvent, or a combination thereof. A
surfactant or
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other chemical, such as an acid, may be added to the injectant such that the
fluid
properties (of the injectant or bitumen) or rock properties may be modified.
While no limitation in scope or interpretation of the present system and
method is
intended, it is contemplated that, in operation, the first bottom well
injectant injected may
travel preferentially through high permeability fractures in the reservoir,
thereby
conductively heating the reservoir and mobilizing the bitumen therein. For
example, the
bitumen may have a mobility of at least 50mD/cP. For example, Figs. 9 shows
that at the
initial reservoir of temperature approximately 10 C, the viscosity of the
bitumen is
approximately 10,000,000 cP and that raising the temperature of the bitumen to
80 C will
reduce the viscosity to approximately 1,000 cP, increasing bitumen mobility by
a factor
of 10,000.
After successful mobility of the bitumen in the first cyclic phase of the
present
system and method, injection of second well injectant via the second top well
20 is
commenced resulting in fluid with lower density than bitumen in the fracture
network,
thereby enabling stable gravity drainage through the reservoir and continuous
production
from the bottom well 10 (Fig. 10). In addition, the top well injectant will
maintain and
distribute heat in through the fracture network. It is contemplated that
various effects
such as solution gas drive effect, connate water vaporization, thermal
expansion, and
spontaneous imbibition, if wettability alteration occurs, will also contribute
to the
bitumen production.
Density differences between injectant in the fractures F and bitumen in the
matrix
M can result in gravity drainage, whereby the bitumen drains downwards in the
matrix M
(due to gravity) until it encounters a flow barrier at which time it may
diverge into a
fracture. The flow barrier can be a geological feature, a lean zone or cold
bitumen. When
multiple flow barriers are encountered, the bitumen B may drain out of the
matrix M at
the first barrier and back into the matrix M below (replacing previously-
drained
bitumen), as depicted in Fig.11(A). Alternatively, the bitumen B may drain
simultaneously into the fracture network, as depicted Fig. 11(B). Drainage
rates of the
bitumen B may further depend upon vertical matrix permeability and oil
viscosity. The
drainage rate is independent of the height of the drainage column, fracture
spacing and/or
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fracture permeability. Drainage rates may be impacted upon and sensitive to
capillary
pressure characteristics, which in turn may be a function of the interfacial
tension
between the bitumen and water.
Elevated reservoir temperatures may create a "solution gas drive" which is
caused
by light components in the bitumen (e.g. methane), which are initially
dissolved as a
liquid, to escape the bitumen and form a separate gas phase. The gas may
accumulate in
the pores of the matrix, and require room to expand, until all the bubbles
connect and
become mobile (i.e. it is understood that the gas would leave the pore if a
driving force is
present). In order to make space for the expanding gas, the bitumen trapped in
the matrix
is driven out of the matrix and into the fractures.
Further, a skilled person would know and understand that, because the pores of
the matrix can contain connate water that will evaporate on heating, an
internal steam
drive from the matrix itself may synergistically drive bitumen from the
matrix.
It is further understood that the desired reservoir temperature may be
sufficient to
result in the thermal expansion of the reservoir formation, thereby further
increasing
reservoir pressure and causing bitumen to be pushed out of the matrix and into
the
fractures, where it can easily move towards the well 10.
Fractured carbonate reservoirs are known to initially be oil-wet. A person
skilled
in the art would know that, at elevated temperature, wettability changes from
oil-wet to
water-wet resulting in a change in capillary pressure and spontaneous
imbibition of water
into the pores, forcing bitumen into the fracture network where it can easily
move
towards the well 10.
A person skilled in the art would know that a pressure gradient between the
higher
pressure at top well 20 and the pressure at bottom well 10 will drive (or
"draw-down")
the bitumen from the reservoir and towards the bottom well 10. Where fluids
are
continuously flowing to the lower-pressure bottom well 10, a fluid column will
develop
in the vicinity of the bottom well 10, and a positive "draw-down" pressure can
be
maintained.
In another embodiment, the second continuous phase of the present system and
method may be optionally varied to cycle the pressure in the injectant filled
fractures by,
CA 02841520 2014-01-31
for example, maintaining steam trap controlled production while varying the
injection
rate or production rate. For instance, injection via top well 20 may only
occur half of the
time, but at double the rate that would be required to maintain an average
cycle pressure,
while continually producing from bottom well 10. A modified second continuous
phase
5
involving pressure cycling may be beneficial in a fractured carbonate
formation by
possibly generating bubbles of expanding gas and injectant that would drive
bitumen
from finer pores and into fractures. This process could further be utilized to
maintain and
control the cumulative injectant/oil ratio, and also steam allocations among
wells in the
reservoir.
10 The
present system and method may be managed and optimized by varying the
timing and length of the cycles of the first phase, the injection rate and
volume and/or
composition of both top and bottom injectants, the distance and spatial
relationship
between the top and bottom wells, and the timing of the transition between the
first and
second phases.
Although a few embodiments have been shown and described, it will be
appreciated by those skilled in the art that various changes and modifications
can be
made to these embodiments without changing or departing from their scope,
intent or
functionality. The terms and expressions used in the preceding specification
have been
used herein as terms of description and not of limitation, and there is no
intention in the
use of such terms and expressions of excluding equivalents of the features
shown and
described or portions thereof, it being recognized that the invention is
defined and limited
only by the claims that follow.
