Note: Descriptions are shown in the official language in which they were submitted.
CA 02678347 2009-09-11
SYSTEM AND METHOD FOR ENHANCED OIL RECOVERY FROM COMBUSTION
OVERHEAD GRAVITY DRAINAGE PROCESSES
FIELD OF THE INVENTION
[0001] A pre-ignition heat cycle (PIHC) using cyclic steam injection and steam
flood
techniques is described that improves the recovery of viscous hydrocarbons
from a
subterranean reservoir using an overhead in-situ combustion technique herein
referred
to as combustion overhead gravity drainage (COGD). The PIHC, by developing
horizontal and vertical transmissive zones predispose a viscous oil reservoir
to develop
a conformable combustion chamber. Good conformance of the combustion chamber
enhances recovery factor and improves well operations in the field for in-situ
combustion
applications.
BACKGROUND OF THE INVENTION
[0002] In-situ overhead combustion methods are generally known as an enhanced
recovery technique for the recovery of hydrocarbons from subterranean high
viscosity/low mobility reservoirs. Such reservoirs are known to exist in the
tar sand
formations of Alberta, Canada and in Venezuela, with lesser deposits existing
in the
United States. In-situ overhead combustion methods are referred to in the
literature as
combustion overhead or split stream horizontal processes.
[0003] In-situ overhead combustion techniques typically utilize an array of
vertical air
injection wells and vertical gas vent wells positioned high in the reservoir
with a
horizontal oil production well or drain located lower in the reservoir (See
Kisman & Lau,
JCPT, March 1994, Volume 33. No. 3; Canadian Patent 2096034: Pebdani &
Ostapovitch; U.S. Patent No. 5,211,230). With this technique, the hydrocarbons
in the
reservoir are ignited and an oxygen containing gas is supplied via the
injection wells to
sustain combustion in the reservoir such that the combustion front burns
downwards
towards the horizontal drain. The heat created increases the temperature of
the reservoir
such that various upgrading reactions occur, the viscosity of the hydrocarbons
is
reduced and reservoir water is vaporized to steam. The heated hydrocarbons
having a
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decreased viscosity, and any upgraded oils, then flow by means of gravity to
one or
more horizontal drains located low in the reservoir. Due to the arrangement of
the drains,
injection wells and vent wells, overhead combustion applications are generally
described
as gravity stable as the lighter components inherently separate from the
heavier
components and wherein the heavier components generally flow downward towards
the
drains.
[0004] Overhead combustion techniques typically address the problem of
combustion
front override that may occur with other in-situ combustion techniques by
injecting
oxygen containing gas high in the reservoir to support combustion and
evacuating
melted bitumen and condensed steam from a position low in the reservoir,
thereby
segregating the gas from the bitumen and water. Since the combustion chamber
occupies the top portion of the reservoir and moves downward toward the
horizontal
drain, the combustion gases can be readily directed toward vent wells located
high in the
reservoir on the flank of the reservoir segment as the melted bitumen and
condensed
steam flow downwards under the effect of gravity. The interface between
injected air and
melted bitumen is maintained by the difference in density between the two
substances
and by gravity. In normal COGD operations, gases do not typically reach the
horizontal
drain in large quantities and liquids do not typically flow to the vent wells.
[0005] With in-situ combustion techniques, reaction kinetics are typically
managed by
controlling the volume of air injected into the reservoir via the injection
wells and
controlling the volume of air and combustion gas vented from the reservoir via
the
producing wells. As the evacuation of air and melted bitumen is segregated in
overhead
combustion processes, it is usually easier to manage the reaction kinetics of
an
overhead combustion process as the flux of injected gas can be maintained by
adjusting
the pressure of the reservoir at the injection wells and vent wells without
impacting the
draining of melted oil and condensed water at the horizontal drain. Similarly
conformance of the combustion chamber can be optimized by adjusting pressure
at the
injection and vent wells. As known to those skilled in the art, the symmetry
and/or shape
of the combustion chamber is an important factor in improving the overall
efficiency of
the process. More specifically, in overhead combustion processes, it is
desirable to have
good conformance of the combustion chamber in order to maximize the
displacement of
melted bitumen and minimize cycling of injected gases. If cycling of injected
gas can be
minimized then residence time in the reservoir for combustion gases can be
increased.
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More specifically, residence time in the hot reservoir can provide for
complete
combustion of flammable gas by-products that would otherwise be produced to
surface
as contaminants. Typical flammable gas by-products of in-situ combustion
include
methane, carbon monoxide and hydrogen sulphide. In addition, it is desirable
to
minimize the cycling of injected gas due to impact of gas cycling on the
operating costs.
[0006] In general, it has been found that developing transmissive pathways
within a
viscous oil reservoir prior to ignition of an overhead combustion process
results in higher
conformance for the combustion chamber, superior well operating conditions and
better
reaction kinetics than when no transmissive pathways are formed pre-ignition.
[0007] Accordingly, there has been a need for methods for predisposing a
viscous oil
reservoir to form a conformable gravity stable combustion chamber using cyclic
steam
injection and steam flood techniques specifically to develop lateral and
vertical hot fluid
transmissive zones.
SUMMARY OF THE INVENTION
[0008] In accordance with the invention, there is provided a method of
preparing a
viscous oil bearing reservoir for in-situ overhead combustion by developing
transmissive
pathways in the reservoir prior to igniting the reservoir, wherein the
reservoir well
network comprises one or more injection wells and one or more vent wells
located in the
top portion of the reservoir and a horizontal drain located in the bottom
portion of the
reservoir, wherein the method comprises the steps of:
injecting steam into one or more injection wells while imposing a pressure
drawdown on the one or more vent wells;
injecting steam into the one or more vent wells while imposing a pressure
drawdown on the one or more injection wells; and,
providing for cyclic reversal of steam injection and a pressure drawdown
between
the one or more vent wells and the one or more injection wells until a lateral
transmissive zone is established in the top portion of the reservoir between
the
one or more injection wells and the one or more vent wells.
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[0009] In a further embodiment, the invention further includes the steps of
circulating
steam into the horizontal drain to increase oil mobility in the region of the
reservoir
around the horizontal drain; and injecting steam into the one or more
injection wells
while shutting in the one or more vent wells and evacuating fluids from said
horizontal
drain until a vertical transmissive zone is established between the one or
more injection
wells and the horizontal drain.
[0010] In further embodiments, the steam is injected at a rate that yields a
circulating
pressure in the reservoir below fracture pressure or, depending on reservoir
conditions,
the steam is injected at a rate that yields a circulating pressure in the
reservoir
exceeding fracture pressure.
[0011] In another embodiment, the conformance of the transmissive zones is
adjusted
by control of injection and drawdown pressures during each step.
[0012] In yet another embodiment, after ignition, the lateral transmissive
zones enable
the combustion chamber to expand laterally through the lateral transmissive
zones.
[0013] In yet another embodiment, the progression of the lateral transmissive
zones is
indirectly monitored from temperature data obtained from one or more
observation wells
in contact with the reservoir and/or from pressure communication data derived
from
pressure readings between the one or more injection wells and the one or more
vent
wells.
[0014] In one embodiment, steam is circulated between a heel tubing string and
a toe
tubing string in the horizontal drain to effect heating of the reservoir.
[0015] In another embodiment, progression of the vertical transmissive zone is
monitored from pressure communication data derived from pressure readings
between
the one or more injection wells and the horizontal well.
[0016] In yet another embodiment, the invention includes the step of
monitoring
temperature data from the reservoir from one or more observation wells
adjacent the
one or more injection wells.
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BRIEF DESCRIPTION OF THE DRAWINGS
[0017] The invention is described with reference to the accompanying figures
in which:
Figure 1 is a perspective schematic view of a typical overhead in-situ
combustion well network as described in the prior art;
Figure 2 is a cross-sectional view of a well network representing a portion of
the
well network shown in Figure 1;
Figure 3 is a section view of a well network having horizontal and vertical
transmissive paths after a pre-ignition heat cycle has been completed in
accordance with the invention;
Figure 4 is a section view of a well network undergoing a pre-ignition heat
cycle
in accordance with a first phase of the invention;
Figure 5 is a section view of a well network undergoing a pre-ignition heat
cycle
in accordance with a second phase of the invention;
Figure 6 is a section view of a well network undergoing a pre-ignition heat
cycle
in accordance with a third phase of the invention.
Figure 7 is a section view of a well network undergoing a pre-ignition heat
cycle
in accordance with a fourth phase of the invention;
Figure 8 is a completion design of a vent well and injection well;
Figures 9A and 9B are representative simulation model outputs showing
produced volumes for oil, gas and water during combustion operations for a
process using a pre-ignition heat cycle in accordance with one embodiment of
the invention (Figure 9A) as compared to an overhead combustion process as
described in the prior art (Figure 9B); and,
Figure 10 is a simulation model output showing cumulative produced volumes of
bitumen and oil recovery factors expressed as percent using a pre-ignition
heat
cycle in accordance with one embodiment of the invention and compared to an
overhead combustion process as described in the prior art.
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DETAILED DESCRIPTION
Overview
[0018] With reference to the figures, a pre-ignition heat cycle (PIHC) to
prepare a
viscous oil reservoir for a gravity stable overhead in-situ combustion process
is
described.
[0019] Figure 1 shows a well network pattern typically used in gravity-stable
overhead
in-situ combustion processes as described in the prior art. The overburden has
not been
shown for ease of reference. For the purposes of illustration, the reservoir 1
generally
has dimensions of approximately 150 m width, 500 m length and 28 m thickness.
The
well network includes approximately four vertical injection wells 2, six
vertical vent wells
3, a horizontal drain 4 and approximately four vertical observation wells 5.
It is
understood that the techniques described herein can be applied to overhead
combustion
systems having different dimensions and well networks as understood by one
skilled in
the art.
[0020] Figure 2 shows a section view of the well network from Figure 1. The
injection
well 2 and vent wells 3 are drilled and completed in the top section of the
reservoir 1.
The horizontal drain 4 is located in the bottom section of the reservoir and
the
observation well 5 is drilled and completed in the bottom section of the
reservoir.
Reference within this description to the injection well, vent well and
observation well are
understood to include all injection wells, vent wells and observation wells in
the well
network.
[0021] The PIHC prepares the low mobility reservoir for ignition in an in-situ
overhead
combustion process by developing a lateral hot fluid transmissive path 15 in
the top
section of the reservoir and a vertical hot fluid transmissive path 17 from
the top section
of the reservoir to the horizontal drain located in the bottom section of the
reservoir as
shown in Figure 3.
[0022] The purpose of the lateral hot fluid transmissive path is to provide
communication
between the injection wells 2 and vent wells 3. The development of a lateral
hot fluid
transmissive path facilitates the flow of combustion gases between the
injection wells
and vent wells such that the combustion gases do not flow preferentially to
the horizontal
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drain 4. This segregation allows for greater conformance for the combustion
chamber by
drawing the combustion front towards the vent wells 3. Operating conditions
for the
horizontal drain 4 are also improved by the segregation of combustion gas high
in the
reservoir. Specifically, good reservoir conformance of the combustion chamber
enables
the combustion front to mobilize the largest possible quantity of melted
bitumen and
minimize cycling of injected gas.
[0023] The purpose of the vertical hot fluid transmissive path is to provide
communication between the injection well 2 located high in the reservoir and
the
horizontal drain 4 located low in the reservoir to facilitate the flow of
melted bitumen and
condensed steam toward the horizontal drain, by means of gravity, during
combustion
operations. Absent sufficient mobility between the injection well and the
horizontal drain,
a clear evacuation path is not available for melted bitumen. If melted bitumen
cannot
drain away from the combustion chamber, air flux may be insufficient to
sustain
combustion and development and conformance of the combustion chamber will be
poor.
Therefore the ready evacuation of melted bitumen by gravity drainage allows
for the
formation of a conformable combustion chamber such that efficient and
effective
combustion operations can occur.
[0024] The development of the lateral and vertical hot fluid transmissive
paths during the
PIHC involves several steps:
a. Injecting a steam slug 14 into the injection well 2 and imposing a pressure
drawdown on the vent wells 3, as shown in Figure 4;
b. Injecting a steam slug 14 into the vent wells 3 and imposing a pressure
drawdown on the injection well 2 as shown in Figure 5;
c. Cyclic reversal of steam injection and pressure drawdown between the
vent wells 3 and the injection well 2;
d. Circulating steam 16 into the horizontal drain 4 to create mobility around
the horizontal drain as shown in Figure 6; and
e. Injecting a steam slug 14 into the injection well 2 while shutting in the
vent
wells 3, as shown in Figure 7.
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Forming a Lateral Transmissive Pathway
[0025] The first phases of the PIHC are designed to form a lateral hot fluid
transmissive
path linking the injection well 2 and the vent wells 3 in the top of the
reservoir 1 such that
the lateral hot fluid transmissive path has saturations and temperatures that
are
conducive to the flow of combustion gases. As known to those skilled in the
art, the
quantity of steam required to form the desired saturations and temperatures
will be
determined on a case by case basis from field data records. For example, if
the top of
the reservoir is 100 % water saturated and has good porosity/permeability then
combustion gas may flow within the reservoir without preheating and
specifically forming
a hot fluid transmissive zone. Alternatively, if the top of the reservoir is
100% bitumen
saturated with poor porosity/permeability then the lateral transmissive path
may not be
successfully formed by steam injection. In most cases, steam heating will be
required to
enable efficient flow of combustion gases to the vent wells.
[0026] In the first phase of the pre-ignition heat cycle, as shown in Figure
4, steam slugs
14 are continually injected into the reservoir via the injection well 2 until
the pressure in
the reservoir becomes prohibitive (i.e. approaching fracture pressures). That
is,
generally maximum pressures will be utilized to accelerate the distribution of
steam
without damaging the formation. As steam is injected, the vent wells 3 are
subject to a
pressure drawdown in order to maximize the pressure differential across the
reservoir.
During this stage, reservoir fluids, including condensed steam and melted
bitumen may
be withdrawn from the vent wells during this period of steam injection. No
fluids are
recovered from the horizontal drain 4 in this phase.
[0027] In the second phase of the PIHC, as shown in Figure 5, the process is
continued
by reversing the flow and injecting steam slugs 14 into the vent wells 3 while
imposing a
pressure drawdown on the injection wells 2. Warm reservoir fluids are
withdrawn from
the injection wells. Steam slugs are injected at a rate such that the pressure
in the
reservoir does not exceed hydraulic fracture pressure.
[0028] As the PIHC continues, a cyclic steam injection/pressure drawdown
process is
maintained between the injection wells and the vent wells in accordance with
good
engineering/field practice. As steam is injected in the injection well, a
pressure
drawdown is imposed on the vent well, and vice versa in cyclical fashion until
pressure
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communication is observed between the injection wells 2 and vent wells 3. Once
pressure communication is observed, the development of the lateral hot fluid
transmissive zone 15 in the top section of the reservoir is complete, as shown
in Figure
6.
[0029] As noted above, the amount of steam and time required to develop the
hot fluid
transmissive zone 15 is variable. Primarily, the amount of steam and time
required will
depend on reservoir quality and fluid saturation where the presence or absence
of
mobile water in the reservoir may provide a zone of naturally enhanced or
decreased
mobility in the top section of the reservoir which may minimize or maximize
the amount
of steam injection required to effect pressure communication.
[0030] Naturally enhanced mobility in reservoirs is commonly observed in the
Athabasca
Oil Sands region in Alberta, Canada and other fluvial estuarine depositional
systems.
Based on simulation analysis and geological modelling, a total steam injection
of
between 45,000 m3 and 106,000 m3 (cold water equivalent volumes) of 100 %
quality
steam at 5200 kPa may be required and/or utilized for applications in the
Athabasca Oil
Sands region when the horizontal separation between injection well and vent
well is in
the range of 75m and the reservoir depth is approximately 275 meters. In this
situation,
the time required to effect pressure communication may be in the order of 6-26
months.
Forming a Vertical Transmissive Path
[0031] As the development of the lateral hot fluid transmissive zone 15 is
nearing
completion, the development of the vertical hot fluid transmissive zone 17
commences.
The steam cycling phase that develops the lateral hot fluid transmissive zone
also
initiates the development of the vertical hot fluid transmissive zone via
conduction and
convection processes.
[0032] In the development of the vertical hot fluid transmissive zone, a steam
circulation
process 16, as shown in Figure 6, is commenced to increase the mobility of the
bitumen
around the drain. Specifically, steam is circulated into a toe tubing string
within the
horizontal drain 4 and returned to surface through the heel tubing string of
the horizontal
drain so as to heat the formation in the region around the drain. Typically, a
circulation
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period of 1-2 months is needed to warm the region around the horizontal drain
4. Ideally,
temperatures are monitored by a thermocoupie string within the horizontal well
and
circulation is continued until a sustained well temperature of 150-200 C is
achieved.
[0033] After the steam circulation process is complete, the next phase of the
PIHC is
initiated. As shown in Figure 7, a steam slug 14 is injected to the injection
well 2 while
the vent wells 3 are shut-in. In the preferred embodiment, a steam slug of
approximately
6000 m3 (cold water equivalent) 100 % quality steam at 4000 kPa is used. Warm
reservoir fluids, including melted bitumen and condensed steam, drain into and
are
recovered from the horizontal drain 4 during this phase. Steam injection
continues until
good pressure communication is established between the injection well and the
horizontal drain. Pressure communication is monitored at each well by
detecting
significant pressure changes and/or responses at respective wells. Injection
pressures
are generally substantially below fracture pressure during this phase due to
the
increased mobility within the reservoir from the existence of the horizontal
transmissive
pathway and the preheating of the region between the injection wells 2 and the
horizontal drain 4.
[0034] Once good pressure communication exists between the injection well and
the
horizontal drain, a vertical hot fluid transmissive zone 17, as shown in
Figure 3, is
present linking the injection wells 2 and the horizontal drain 4. The vertical
hot fluid
transmissive zone has saturations and temperatures that are conducive to the
flow of
melted bitumen and condensed steam toward the horizontal drain by gravity
drainage.
[0035] Once the lateral hot fluid transmissive zone 15 and the vertical hot
fluid
transmissive zone 17 are developed, the PIHC is complete and the reservoir 1
is ready
for ignition.
[0036] During PIHC and after ignition, the observation wells utilize data from
thermocouples cemented within the observation wells. The thermocouples
generally
allow for indirect measurement of the growth of the transmissive zones in the
reservoir,
the temperature in the overburden as well as progression of the combustion
front after
ignition. The data obtained from the thermocouples allows the operator to
adjust the
pressures at the injection and vent wells to control the growth of the
transmissive zones.
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[0037] In further embodiments, the steam injected into the vent wells, and
injection wells
during the PIHC process may be injected at such a rate that the injection
pressure
exceeds hydraulic fracture pressure. This may be necessary to develop the
lateral hot
fluid transmissive pathways in a timely fashion in certain reservoirs.
[0038] Furthermore, while from a practical perspective it is preferred that
the lateral
transmissive pathways are established prior to the vertical pathways, the
order of
establishing the pathways could potentially be reversed.
[0039] More specifically, from an efficiency perspective, it is more important
to develop
the lateral pathways first as the development of lateral pathways will in
effect partially
and simultaneously develop the vertical pathways, such that the requirements
for the
active formation of the vertical pathways would be reduced. That is, the
position of the
injection well over the horizontal drain together with conduction and
convection effects
will cause the partial development of the vertical pathways as steam is
injected into the
injection wells during the creation of the lateral pathways.
Design of Facilities and Equipment
[0040] Referring to Figure 8, a completion design for the injection wells and
the vent
wells is shown. The completion design includes a casing string 20 set into the
top of the
reservoir and cemented in place; a cementing diverter tool 21 located in the
casing
string 20 to facilitate the cementing of the casing string; a tubing string 22
set into a pay
section of the reservoir; a coil tubing string 23 set inside the tubing string
22; a thermal
packer 24 set in the casing string 20 to isolate the casing annulus 25 (the
space
between the casing string 20 and the tubing string 22); a perforated joint 26
located
below the thermal packer 24; base pipe wire wrap screen 27 for sand control
over the
liner 28 that comprises the bottom of the casing string 20; and a stab-in plug
29 to
isolate the coil tubing string 23 from the tubing string 22. Liquids below the
thermal
packer 24 may be lifted by gas or steam lift through the coil tubing string
22. Typical
dimensions of the completion design components in the preferred embodiment of
the
invention are shown in Table 1.
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Table 1-Typical dimensions of the completion design components for the
injection
wells and vent wells
Reference Completion Design Components Typical Dimensions
Numeral
20 Casing String 177.8 mm
22 Tubing String 88.9 mm
23 Coiled Tubing String 60.3 mm
24 Thermal Packer 177.8 mm
26 Perforated Joint 114.3 mm tubing
29 Stab-in Plug 88.9 mm x 60.3 mm
[0041] The principal objectives served by the completion design are:
a) good communication of the vent well or injection well with the reservoir
section;
b) sand control for high temperature cycling operations;
c) isolation of the casing annulus 25 from hot corrosive fluids; and
d) capacity to lift liquids from below the thermal packer 24 using gas
injection in
the coil tubing string 23.
[0042] The completion design for the injection wells and vent wells are
simple, with the
option to produce reservoir fluids during the PIHC cycle made available using
gas lift.
[0043] The surface facilities required for the PIHC cycle are consistent with
current
cyclic steam operations that can provide for multiphase flow to and from
injection wells
and vent wells.
[0044] To simplify operations, the horizontal drain is usually only equipped
for
production of reservoir fluids.
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Simulation Models
[0045] In the preferred embodiment, the PIHC process is used to exploit a zone
of
naturally enhanced mobility such as is observed in the top of the reservoir
section in the
Athabasca Oil Sands Region and other fluvial estuarine depositional systems. A
zone of
enhanced mobility high in the reservoir is commonly observed due to:
= a fining upward depositional sequence that allows for higher observed water
saturations providing for the presence of mobile water;
= a charge history that provides for the presence of mobile water high in the
reservoir;
and,
= an oil viscosity gradient that varies in order of magnitude from the bottom
of the
reservoir to the top of the reservoir.
[0046] The PIHC process has been numerically simulated to verify the physical
principles of the PIHC and to evaluate the improvements relative to the prior
art. In order
to forecast production performance, a three dimensional (3-D) simulation was
prepared
to model the PIHC and subsequent in-situ combustion exploitation process. A
geological
model representative of an actual bitumen reservoir section based on full
diameter core,
well log and seismic data was used as the base earth model for the simulation
(the Earth
Model). The reservoir section modelled is characteristic of a well developed,
bitumen
saturated McMurray sand in the Athabasca Oil Sands Region. The Earth Model
included
the presence of silt 6nd shale partings and inclined heterolithic strata
characteristic of
fluvio-estuarine depositional systems.
[0047] In the model the horizontal drain was positioned approximately 9 m
above the
base of the McMurray sand to avoid a shale parting that would serve as a
baffle to
vertical fluid movement in the reservoir. Bitumen saturated sands below the
horizontal
drain did not contribute to the reservoir exploitation cycle. All other
dimensions of the
model were consistent with the reservoir exploitation section shown in Table
2,
Reservoir and Bitumen Properties used in the Simulation Model .
[0048] A commercial simulator (CMG STARS, Computer Modelling Group, Calgary,
Alberta) was used as a plafform for numerical modelling. CMG STARS simulation
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CA 02678347 2009-09-11
routines handle many aspects of thermal and compositional reservoir modelling
including: thermal, k value composition, chemical reactions, geo-mechanics,
and
combustion reaction kinetics.
[0049] The reservoir rock properties and bitumen properties used in the
reservoir
simulation are summarized in Table 2 as follows:
Table 2-Reservoir and Bitumen Properties used in the Simulation Model
Reservoir Property Units Value
Pay thickness m 29
Porosity % 30
Oil Saturation % 62.5
Gas Saturation % 0
Solution GOR m /m 4
Horizontal Permeability mD 3747
Vertical Permeability mD 2630
Reservoir Temperature C 8
Reservoir Pressure kPa 2500
Rock Compressibility 1/kPa 1e-6
Petroleum Initially-in-place 10 m 378.1
Conductivity j/m.d.C 6.6e5
Heat Capacity j/m C 1e6
Oil Properties
Density Kg/m 1012
Viscosity at 20 C max cp 1,103,304
Viscosity at 20 C min cp 306,300
Heat Capacity j/gmole.C 1190
Combustion Enthalpy @ 25 C j/gmole 483,460
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[0050] Wells were controlled during simulation modelling using the constraints
described
in Table 3.
Table 3-Well constraints used in the Simulation Model
Constraint Units Value
Steam injection pressure (max) kPa 5200
Air injection pressure (max) kPa 4000
Production pressure (min) kPa 125
Horizontal drain oxygen rate (max) m/day(sc) 2500
Vent well gas oxygen rate (min) m3 /day(sc) 2500
[0051] Operation of the model using the parameters described above provided a
prediction of production performance of the PIHC and the COGD process over
time.
Generalized relative permeability curves published in the literature were used
for oil
water systems and gas liquid systems. Gas liquid systems were adjusted as a
function
of temperature to reduce gas relative permeability in the vicinity of high
temperature fluid
fronts. This adjustment was treated as a sensitivity in partial pattern 3-D
models that
were investigated prior to running a full pattern exploitation model.
[0052] In the model, ignition and air injection commenced in the 26th month,
after
injection of 106,000 m3 of steam. Steam injection for the purpose of
developing the
lateral hot fluid transmissive zone was injected into the top 3 meters of the
reservoir
section where reservoir conditions would permit. No optimization was
undertaken with
regard to PIHC steam volumes and the simulation volumes are viewed as maximum
volumes.
[0053] As a base assumption, water saturations below 40% were deemed to be
immobile in the simulation model. Should water saturations at the 25%-30%
range
prove to be mobile in the reservoir then steam injection can be accelerated
and required
injection volumes reduced. The range of injected steam volumes for the PIHC is
expected to be 45,000 m3 to 106,000 m3 for a typical reservoir.
[0054] At termination of the PIHC, air injection commenced at a maximum rate
of 200
103m3/day (sc).
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[0055] Referring to Figures 9A and 9B, simulation model outputs are presented
for
volumes of bitumen, water and gas expressed as rate time, produced from the
horizontal
drain, during combustion operations. Figure 9A shows the results of a
simulation in
accordance with the invention (base case) whereas Figure 9B shows the results
of a
simulation in accordance with the prior art (alternate case). The base case
realization
employs the pre-ignition heat cycle as described in the preferred embodiment.
Oil rate,
gas rate, gas rate oxygen, water rates and well bottom hole pressure for the
horizontal
drain are recorded for the base case. Figure 9B presents an alternative
realization that
employs a pre-ignition heat cycle as described in the prior art by Kisman and
Lau,
AOSTRA, (CA 2096034). More specifically, the Kisman process is described as
cycling
steam from the injection wells to the horizontal drain to form an initial hot
fluid
transmissive chamber prior to ignition of a combustion overhead process. Oil
rate, gas
rate, gas rate oxygen, water rates and well bottom hole pressure for the
horizontal drain
are recorded for the alternate model. All other input variables are maintained
to provide
a meaningful comparison between the base model and the alternate model.
[0056] As shown, about 12 months after initiation of combustion, oxygen is
detected in
the horizontal drain in both the base model and the alternate model. Oxygen is
detected
in small quantities at vent wells immediately after the initiation of
combustion in both the
base model and alternate model.
[0057] As shown in both Figures 9A and 9B, oil production from combustion
operations
commences shortly after ignition and rises to a maximum rate of 130 m3/day
from the
horizontal drain in both the base model and alternate model. In addition, a
period of
oxygen breakthrough is observed in both the base model and alternate model
commencing in mid year 2012. Back pressure in the horizontal drain is
increased as a
result of the oxygen breakthrough and fluid off-take is reduced resulting in a
decline in
bitumen production in both the base model and alternate model. In year 2013
oxygen
rates begin to stabilize in the base model and bitumen production is restored
to 130
m3/day as horizontal drain back pressure is reduced. In the alternate model,
oxygen
breakthrough continues to impose higher back pressure at the horizontal drain
and
bitumen production is not restored to initial rates. The observed variance in
production
performance after year 2013 is attributed to the lateral transmissive path
developed in
the base model using the pre-ignition heat cycle as described in the preferred
embodiment. That is, the absence of the lateral fluid transmissive path in the
alternate
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CA 02678347 2009-09-11
model has retarded the lateral development of the combustion chamber resulting
in
poorer production performance and increased cycling of injected gas.
[0058] Figure 10 shows the results of simulations in which cumulative volumes
of
bitumen and bitumen recovery factor expressed as percentage are shown for the
base
model and alternate model. The base model recovers 244,100 m3 of bitumen in 10
years
representing 65% recovery of the petroleum-initially-in-place. The alternate
model
recovers 146,000 m3 of bitumen in 10 years representing 39% recovery of the
petroleum-initially-in-place. The higher recovery factor observed in the base
model is
attributed to the enhanced lateral conformance of the combustion chamber
developed as
a result of the pre-ignition heat cycle, as described in the preferred
embodiment. The
absence of the lateral fluid transmissive path in the alternate model has
retarded the
lateral development of the combustion chamber resulting in poorer recovery
performance and increased cycling of injected gas.
[0059] Relative to the pre-ignition heat cycle described in this application
the process
outlined in the prior art recovers only 39% of the petroleum-initially-in-
place. The
incremental recovery factor secured by the PIHC is evidence of improved
bitumen
exploitation using overhead combustion gravity drainage processes.
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