Note: Descriptions are shown in the official language in which they were submitted.
CA 02829008 2013-10-01
METHOD OF DEVELOPING SUBSURFACE BARRIERS
TECHNICAL FIELD
The present invention generally relates to enhanced recovery of petroleum
fluids from the
subsurface by steam injection, in which a nearby outcrop or depleted steam
chamber causes loss
of steam from the active process zone or requires reducing the steam pressure
in the active
process zone to minimize water loss. A barrier between the process zone and
the outcrop or
depleted chamber, enables the enhanced recovery process to be more efficient,
more economical,
minimizes water usage and results in increased production of petroleum fluids
from the
subsurface formation.
BACKGROUND OF THE INVENTION
Heavy oil and bitumen oil sands are abundant in reservoirs in many parts of
the world
such as those in Alberta, Canada, Utah and California in the United States,
the Orinoco Belt of
Venezuela, Indonesia, China and Russia. The hydrocarbon reserves of the oil
sand deposit is
extremely large in the trillions of barrels, with recoverable reserves
estimated by current
technology in the 300 billion barrels for Alberta, Canada and a similar
recoverable reserve for
Venezuela. These vast heavy oil (defined as the liquid petroleum resource of
less than 20 API
gravity) deposits are found largely in unconsolidated sandstones, being high
porosity permeable
cohensionless sands with minimal grain to grain cementation. The hydrocarbons
are extracted
from the oils sands either by mining or in situ methods.
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The heavy oil and bitumen in the oil sand deposits have high viscosity at
reservoir
temperatures and pressures. While some distinctions have arisen between tar or
oil sands,
bitumen and heavy oil, these terms will be used interchangeably herein. The
oil sand deposits in
Alberta, Canada extend over many square miles and vary in thickness up to
hundreds of feet
thick. Although some of these deposits lie close to the surface and are
suitable for surface
mining, the majority of the deposits are at depth ranging from a shallow depth
of 150 feet down
to several thousands of feet below ground surface. The oil sands located at
these depths
constitute some of the world's largest presently known petroleum deposits. The
oil sands contain
a viscous hydrocarbon material, commonly referred to as bitumen, in an amount
that ranges up to
15% by weight. Bitumen is effectively immobile at typical reservoir
temperatures. For example
at 15 C, bitumen has a viscosity of ¨1,000,000 centipoise. However at
elevated temperatures the
bitumen viscosity changes considerably to be ¨350 centipoise at 100 C down to
40 centipoise
at 180 C. The oil sand deposits have an inherently high permeability ranging
from ¨1 to 10
Darcy, thus upon heating, the heavy oil becomes mobile and can easily drain
from the deposit.
It is well known that extensive heavy oil reservoirs are found in formations
comprising
unconsolidated, weakly cemented sediments. Unfortunately, the methods
currently used for
extracting the heavy oil from these formations require the injection of steam
under pressure, such
as SAGD (Steam Assisted Gravity Drainage), and as such are difficult and often
uneconomic if
the SAGD well pairs are located in proximity to an outcrop or depleted low
pressure steam
chambers. Even though the formations contain significant quantities of heavy
oil and bitumen,
which is basically immobile at initial reservoir conditions, the pore water
saturation and
permeability of the formation gives rise to reasonably high water mobility.
Lean zones within the
formation only greatly increase the water mobility, thus giving rise to the
need for a barrier to
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provide a more efficient, less environmental impact and more cost effective
recovery system.
Operating a SAGD steam chamber at lower pressure gives rise to higher steam
oil ratios (SORs)
but even more significantly at low steam pressures, the steam may not be able
to penetrate
horizontal shale layers and thus restrict the height of the steam chamber,
giving rise to higher
SORs and a significant impact on production. Such impacts can have a
significant effect on the
overall economics of the SAGD process.
Descriptions of the SAGD process and modifications are described in U.S.
Patent No.
4,344,485 to Butler, and U.S. Patent No. 5,215,146 to Sanchez and thermal
extraction methods in
U.S. Patent No. 4,085,803 to Butler, U.S. Patent No. 4,099,570 to Vandergrifi,
and U.S. Patent
No. 4,116,275 to Butler et al. The SAGD process consists of two horizontal
wells at the bottom
of the hydrocarbon formation, with the injector well located approximately 10-
15 feet vertically
above the producer well. The steam injection pressures exceed the formation
fracturing pressure
in order to establish connection between the two wells and develop a steam
chamber in the oil
sand formation, Similar to CSS (Cyclic Steam Stimulation), the SAGD method has
complications, albeit less severe than CSS, due to the lack of steam flow
control along the long
section of the horizontal well and the difficulty of controlling the growth of
the steam chamber.
Thermal recovery processes using steam require large amounts of energy to
produce the
steam, using either natural gas or heavy fractions of produced synthetic
crude. Burning these
fuels generates significant quantities of greenhouse gases, such as carbon
dioxide. Also, the
steam process uses considerable quantities of water, which even though may be
reprocessed,
involves recycling costs and energy use. With impermeable barriers in place
near outcrops and/or
to isolate active steaming operations from depleted steam chambers, the SAGD
system will be a
less energy intensive oil recovery process and will also minimize water usage.
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Solvents applied to the bitumen soften the bitumen and reduce its viscosity
and provide a
non-thermal mechanism to improve the bitumen mobility. Hydrocarbon solvents
consist of
vaporized light hydrocarbons such as ethane, propane or butane or liquid
solvents such as
pipeline diluents, natural condensate streams or fractions of synthetic
crudes. The diluent can be
added to steam and flashed to a vapor state or be maintained as a liquid at
elevated temperature
and pressure, depending on the particular diluent composition. While in
contact with the
bitumen, the saturated solvent vapor dissolves into the bitumen. This
diffusion process is due to
the partial pressure difference in the saturated solvent vapor and the
bitumen. As a result of the
diffusion of the solvent into the bitumen, the oil in the bitumen becomes
diluted and mobile and
will flow under gravity. The resultant mobile oil may be deasphalted by the
condensed solvent,
leaving the heavy asphaltenes behind within the oil sand pore space with
little loss of inherent
fluid mobility in the oil sands due to the small weight percent (5-15%) of the
asphaltene fraction
to the original oil in place. Deasphalting the oil from the oil sands produces
a high grade quality
product by 30-50 API gravity. If the reservoir temperature is elevated the
diffusion rate of the
solvent into the bitumen is raised considerably being two orders of magnitude
greater at 100 C
compared to ambient reservoir temperatures of ¨15 C.
Solvent assisted recovery of hydrocarbons in continuous and cyclic modes are
described
including the VAPEX process and combinations of steam and solvent plus heat.
See U.S. Patent
No. 4,450,913 to Allen et al, U.S. Patent No. 4,513,819 to Islip et al, U.S.
Patent No. 5,407,009
to Butler et al, U.S. Patent No. 5,607,016 to Butler, U.S. Patent No.
5,899,274 to Frauenfeld et
al, U.S. Patent No. 6,318,464 to Mokrys, U.S. Patent No. 6,769,486 to Lim et
al, and U.S. Patent
No. 6,883,607 to Nenniger et al. The VAPEX process generally consists of two
horizontal wells
in a similar configuration to SAGD; however, there are variations to this
including spaced
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horizontal wells and a combination of horizontal and vertical wells. The
startup phase for the
VAPEX process can be lengthy and take many months to develop a controlled
connection
between the two wells and avoid premature short circuiting between the
injector and producer.
The VAPEX process with horizontal wells has similar issues to CSS and SAGD in
horizontal
wells, due to the lack of solvent flow control along the long horizontal well
bore, which can lead
to non-uniformity of the vapor chamber development and growth along the
horizontal well bore.
The thermal and solvent methods of enhanced oil recovery from oil sands, all
suffer from
a lack of surface area access to the in place bitumen. Thus the reasons for
raising steam pressures
above the fracturing pressure in CSS and during steam chamber development in
SAGD, are to
increase surface area of the steam with the in place bitumen. Similarly the
VAPEX process is
limited by the available surface area to the in place bitumen, because the
diffusion process at this
contact controls the rate of softening of the bitumen. Likewise during steam
chamber growth in
the SAGD process the contact surface area with the in place bitumen is
virtually a constant, thus
limiting the rate of heating of the bitumen. Therefore both methods (heat and
solvent) or a
combination thereof would greatly benefit from a substantial increase in
contact surface area
with the in place bitumen. Hydraulic fracturing of low permeable reservoirs
has been used to
increase the efficiency of such processes and CSS methods involving fracturing
are described in
U.S. Patent No. 3,739,852 to Woods et al, U.S. Patent No. 5,297,626 to Vinegar
et al, and U.S.
Patent No. 5,392,854 to Vinegar et al. Also during initiation of the SAGD
process
overpressurized conditions are usually imposed to accelerate the steam chamber
development,
followed by a prolonged period of underpressurized condition to reduce the
steam to oil ratio.
Electrical resistive heating of oil shale and oil sand formations utilizing a
hydraulic
fracture filled with an electrically conductive material are described in U.S.
Patent No. 3,137,347
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to Parker, involving a horizontal hydraulic fracture filled with conductive
proppant and with the
use of two (2) wells to electrically energizing the fracture and raise the
temperature of the oil
shale to pyrolyze the organic matter and produce hydrocarbon from a third
well, in U.S. Patent
No. 5,620,049 to Gipson et al. with a single well configuration in a
hydrocarbon formation
predominantly a vertical fracture filled with conductive temperature setting
resin coated proppant
and the electric current passes through the conductive proppant to a surface
ground and the
single well is completed to raise the temperature of the oil in-situ to reduce
its viscosity and
produce hydrocarbons from the same well, in U.S. Patent No. 6,148,911 to
Gipson et al. with a
single well configuration in a gas hydrate formation with predominantly a
horizontal fracture
filled with conductive proppant and the electric current passes through the
conductive proppant
to a surface ground, raising the temperature of the formation to release the
methane from the gas
hydrates and the single well is completed for methane production, in U.S.
Patent No. 7,331,385
to Symington et al. in U.S. Patent No. 7,631,691 to Symington et al. and in
Canadian Patent No.
2,738,873 to Symington et al. all with a predominantly vertical fracture
filled with conductive
proppant and the conductive fracture is electrically energized by contact with
at least two (2)
wells or in the case of a single well presumably through the well and surface
ground with the oil
shale raised to a temperature to pyrolyze the organic matter into producible
hydrocarbons, with
the electrically conductive fracture composed of electrically conductive
proppant and non-
electrically conductive non-permeable cement. The single well systems
described above all
suffer from low efficiency and high energy loss due to the current passes
through a significant
distance of the formation from the conductive fracture to the surface ground.
Also the systems
with two or more wellbores do not disclosed how the electrode to conductive
fracture contact
will be other than a point contact resulting in significant energy loss and
overheating at such a
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contact. The above referenced methods describe the use of hydraulic fracturing
in its
conventional sense, and such application of hydraulic fracturing of brittle
rock to form fractures
therein are typically not applicable to ductile formations comprising
unconsolidated, weakly
cemented sediments.
Construction of hydraulic barriers by jet grouting, freezing, sheet piling,
etc are common
in civil and mining applications but are generally not suitable or economic at
depth. Hydraulic
barriers as conformance systems are common in the petroleum field, such as
sodium silicate
grouts, microbial barriers, swelling particles, etc but are intended for
sealing zones around
boreholes and not intended for barriers kilometers in length and for the need
to be continuous.
Microbial barriers suffer from the disadvantage that they require constant
nutrient feeding, but
also are only applicable over modest temperature ranges.
Numerous barriers systems have been described in many patents for application
to the in-
situ retorting of oil shale and tar or oil sands, see U.S. Patent No.
7,032,660 to Vinegar et al.,
U.S. Patent No. 7,077,198 to Vinegar et al., U.S. Patent No. 7,516,787 to
Kaminsky, U.S. Patent
No. 7,527094 to McKinzie et al., U.S. Patent No. 7,546,873 to Kim et al., U.S.
Patent No.
7,647,972 to Kaminsky, U.S. Patent No. 7,703,513 to Vinegar et al. and
Canadian Patent No.
2,663,650 to Kaminsky. The barrier systems described consists of freeze walls
from wells, wax
impregnation, grouting from boreholes and freeze walls using conventional
hydraulic fracturing
to create a fluid flow conduit within the subsurface. Most of the techniques
cited are uneconomic
due to the extensive number of wells required, others especially those
involving hydraulic
fracturing, describe the use of hydraulic fracturing in its conventional
sense, and such application
of hydraulic fracturing of brittle rock to form fractures therein are
typically not applicable to
ductile formations comprising unconsolidated, weakly cemented sediments. In
brittle formations
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= 5 using conventional hydraulic fracturing, the fracture
orientation either vertical or horizontal or
inclined, and if vertical its azimuth is controlled by the in-situ formation
principal stresses, and
as such a continuous vertical barrier along a pre-determined azimuth can not
be constructed by
conventional hydraulic fracturing, and especially not in weakly cemented
formations.
Techniques used in hard, brittle rock to form fractures therein are typically
not applicable
to ductile formations comprising unconsolidated, weakly cemented sediments.
The method of
controlling the azimuth of a vertical hydraulic planar inclusion in formations
of unconsolidated
or weakly cemented soils and sediments by slotting the well bore or installing
a pre-slotted or
weakened casing at a predetermined azimuth has been disclosed. The method
disclosed that a
vertical hydraulic planar inclusion can be propagated at a pre-determined
azimuth in
unconsolidated or weakly cemented sediments and that multiple orientated
vertical hydraulic
planar inclusions at differing azimuths from a single well bore can be
initiated and propagated
for the enhancement of petroleum fluid production from the formation. See U.S.
Patent No.
6,216,783 to Hocking et al., U.S. Patent No. 6,443,227 to Hocking et al., U.S.
Patent No.
6,991,037 to Hocking, U.S. Patent No. 7,404,441 to Hocking, U.S. Patent No.
7,640,975 to
Cavender et al., U.S. Patent No. 7,640,982 to Schultz et al., U.S. Patent No.
7,748,458 to
Hocking, U.S. Patent No. 7,814,978 to Steele et al.,U.S. Patent No. 7,832,477
to Cavender et al.,
U.S. Patent No. 7,866,395 to [locking, U.S. Patent No. 7,950,456 to Cavender
et al., U.S. Patent
No. 8,151,874 to Schultz et al. The method disclosed that a vertical hydraulic
planar inclusion
can be propagated at a pre-determined azimuth in unconsolidated or weakly
cemented sediments
and that multiple orientated vertical hydraulic planar inclusions at differing
azimuths from a
single well bore can be initiated and propagated for the enhancement of
petroleum fluid
production from the formation. It is now known that unconsolidated or weakly
cemented
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sediments behave substantially different from brittle rocks from which most of
the hydraulic
fracturing experience is founded.
The methods disclosed above find especially beneficial application in ductile
rock
formations made up of unconsolidated or weakly cemented sediments, in which it
is typically
very difficult to obtain directional or geometric control over inclusions as
they are being formed.
Weakly cemented sediments are primarily frictional materials since they have
minimal cohesive
strength. An uncemented sand having no inherent cohesive strength (i.e., no
cement bonding
holding the sand grains together) cannot contain a stable crack within its
structure and cannot
undergo brittle fracture. Such materials are categorized as frictional
materials which fail under
shear stress, whereas brittle cohesive materials, such as strong rocks, fail
under normal stress.
The term "cohesion" is used in the art to describe the strength of a material
at zero
effective mean stress. Weakly cemented materials may appear to have some
apparent cohesion
due to suction or negative pore pressures created by capillary attraction in
fine grained sediment,
with the sediment being only partially saturated. These suction pressures hold
the grains together
at low effective stresses and, thus, are often called apparent cohesion.
The suction pressures are not true bonding of the sediment's grains, since the
suction
pressures would dissipate due to complete saturation of the sediment. Apparent
cohesion is
generally such a small component of strength that it cannot be effectively
measured for strong
rocks, and only becomes apparent when testing very weakly cemented sediments.
Geological strong materials, such as relatively strong rock, behave as brittle
materials at
normal petroleum reservoir depths, but at great depth (i.e. at very high
confining stress) or at
highly elevated temperatures, these rocks can behave like ductile frictional
materials.
Unconsolidated sands and weakly cemented formations behave as ductile
frictional materials
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from shallow to deep depths, and the behavior of such materials are
fundamentally different from
rocks that exhibit brittle fracture behavior. Ductile frictional materials
fail under shear stress and
consume energy due to frictional sliding, rotation and displacement.
Conventional hydraulic dilation of weakly cemented sediments is conducted
extensively
on petroleum reservoirs as a means of sand control. The procedure is commonly
referred to as
"Frac-and-Pack." In a typical operation, the casing is perforated over the
formation interval
intended to be fractured and the formation is injected with a treatment fluid
of low gel loading
without proppant, in order to form the desired two winged structure of a
fracture. Then, the
proppant loading in the treatment fluid is increased substantially to yield
tip screen-out of the
fracture. In this manner, the fracture tip does not extend further, and the
fracture and perforations
are backfilled with propp ant.
The process assumes a two winged fracture is formed as in conventional brittle
hydraulic
fracturing. However, such a process has not been duplicated in the laboratory
or in shallow field
trials. In laboratory experiments and shallow field trials what has been
observed is chaotic
geometries of the injected fluid, with many cases evidencing cavity expansion
growth of the
treatment fluid around the well and with deformation or compaction of the host
formation.
Weakly cemented sediments behave like a ductile frictional material in yield
due to the
predominantly frictional behavior and the low cohesion between the grains of
the sediment. Such
materials do not "fracture" and, therefore, there is no inherent fracturing
process in these
materials as compared to conventional hydraulic fracturing of strong brittle
rocks.
Linear elastic fracture mechanics is not generally applicable to the behavior
of weakly
cemented sediments. The knowledge base of propagating viscous planar
inclusions in weakly
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cemented sediments is primarily from recent experience over the past ten years
and much is still
=
not known regarding the process of viscous fluid propagation in these
sediments.
Accordingly, there is a need for a method and apparatus for construction of a
vertical
continuous barrier to isolate the SAGD system from an outcrop or neighboring
depleted low
pressure steam chambers.
15
25
SUMMARY OF THE INVENTION
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= 5
The present invention is a method and apparatus for the construction of
a subsurface
barrier to enable more efficient, more economical and less environmental
impact for the
enhanced recovery of petroleum fluids from the subsurface by steam and/or
solvents typically
using a SAGD recovery system, for the recovery of heavy oil and bitumen in
situ from a oil
sands formation. In one embodiment of this invention, multiple propped
vertical inclusions are
constructed at various azimuths from a first well and propagate into the oil
sand formation and
filled with a proppant. The vertical inclusions are propagated to intersect
and connect with a
second and subsequent wells, on azimuth and depth from the first well.
Additional vertical
inclusions filled with the same proppant are initiated in the first well at
progressively shallower
depths but on azimuth with the lower propped inclusions, such that they
propagate laterally and
vertical into the formation and intersect and coalesce with the lower
inclusions, and intersect the
second and subsequent wells. If the proppant is water or hydrocarbon swellable
rubber beads,
then the beads will swell and fill the void space in the inclusions. If the
proppant is a ceramic
coated with an electrically conductive resin, then electrodes are placed in
the wells, and an
alternating direction current is passed from the well to its neighboring
wells, with the electric
current passing through the proppant contained in all of the inclusions, thus
heating the inclusion
by electrical resistive heating. By electrically resistive heating of the
inclusion, the heat
hardening resin softens and flows to fill the pore space in the inclusions,
with the formation
providing an active horizontal closure stress on the inclusions thus
consolidating the inclusions,
and then the resin hardens to be an impermeable barrier.
In another embodiment multiple propped vertical inclusions are constructed at
various
azimuths from a first well and propagate into the oil sand formation and
filled with a proppant.
Vertical inclusions filled with the same proppant are constructed from a
second and subsequent
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wells, on azimuth and depth to intersect and coalesce with the inclusions from
the first well.
Additional vertical inclusions filled with the same proppant are initiated in
the first well at
progressively shallower depths but on azimuth with the lower propped
inclusions, such that they
propagate laterally and vertical into the formation and intersect and coalesce
with the lower
inclusions. Additional vertical inclusions filled with the same proppant are
initiated in the second
and subsequent wells at progressively shallower depths but on azimuth with the
lower propped
inclusions, such that they propagate laterally and vertical into the formation
and intersect and
coalesce both with the lower inclusion and the inclusions from the first well.
If the proppant is
water or hydrocarbon swellable rubber beads, then the beads will swell and
fill the void space in
the inclusions. If the proppant is a ceramic coated with an electrically
conductive resin, then
electrodes are placed in the wells, and an alternating direction current is
passed from the well to
its neighboring wells, with the electric current passing through the proppant
contained in all of
the inclusions, thus heating the inclusion by electrical resistive heating. By
electrically resistive
heating of the inclusion, the heat hardening resin softens and flows to fill
the pore space in the
inclusions, with the formation providing an active horizontal closure stress
on the inclusions thus
consolidating the inclusions, and then the resin hardens to be an impermeable
barrier.
In an alternate embodiment, the proppant is a sand or ceramic beads, and low
temperature
high salinity water is circulated throughout the inclusions and freezes the
pore water in the
formation, thus creating a freeze wall or barrier. While in another
embodiment, the proppant is a
sand, and a low viscosity grout is injected into the inclusions and fills the
voids of the inclusions,
and included in the grout is a time delay setting agent. Alternatively, the
low viscosity grout is
electrically conductive, and by passing an alternating electric current
through the inclusions
filled with the grout, heats and thus hardens and sets the grout.
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= 5 Although the present invention contemplates the formation of
vertical propped inclusions
which generally extend laterally away from a vertical or near vertical well
penetrating an earth
formation and in a generally vertical plane, those skilled in the art will
recognize that the
invention may be carried out in earth formations wherein the fractures and the
well bores can
extend in directions other than vertical.
Other objects, features and advantages of the present invention will become
apparent
upon reviewing the following description of the preferred embodiments of the
invention, when
taken in conjunction with the drawings and the claims.
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BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a schematic isometric view of a multiple well system and associated
method
embodying principles of the present invention, using injection and relief
wells;
FIG. 2 is a schematic isometric view of a multiple well system and associated
method
embodying principles of the present invention, using only injection wells;
FIG. 3 is a schematic isometric view of the multiple well system with a lower
inclusion
propagating towards a neighboring relief well;
FIG. 4 is a schematic isometric view of the multiple well system with a
completed lower
inclusion intersecting a neighboring relief well;
FIG. 5 is a schematic isometric view of the multiple well system completed
with a lower
inclusion, and an upper inclusion propagating towards a neighboring relief
well;
FIG. 6 is a schematic isometric view of the multiple well system with
completed lower
and upper inclusions intersecting a neighboring relief well;
FIG. 7 is a schematic isometric view of the multiple well system with a lower
inclusion
propagating towards a neighboring injection well;
FIG. 8 is a schematic isometric view of the multiple well system with a
completed lower
inclusion, and a lower inclusion propagating from the neighboring injection
well towards it;
FIG. 9 is a schematic isometric view of the multiple well system with a
completed lower
inclusion, and an upper inclusion propagating towards a neighboring injection
well;
FIG. 10 is a schematic isometric view of the multiple well system with
completed lower
and upper inclusions.
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DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT
Several embodiments of the present invention are described below and
illustrated in the
accompanying drawings. The present invention is a method and apparatus for the
construction
of a subsurface barrier to enable more efficient, more economical and less
environmental impact
for the enhanced recovery of petroleum fluids from the subsurface by steam
and/or solvents
typically using a SAGD recovery system, for the recovery of heavy oil and
bitumen in situ from
a oil sands formation. Multiple propped vertical inclusions at various
azimuths are constructed
from multiple wells into the oil sand formation and filled with a proppant. If
the proppant is
water or hydrocarbon swellable rubber beads, then the beads will swells and
fill the void space in
the inclusions. If the proppant is a ceramic coated with an electrically
conductive resin, then
electrodes are placed in the wells, and an alternating current passes through
the electrically
conductive proppant contained in the inclusions, thus heating the inclusion by
electrical resistive
heating. By electrically resistive heating of the inclusion, the heat
hardening resin softens and
floWs to fill the pore space in the inclusions, with the formation providing
an active horizontal
closure stress on the inclusions thus consolidating the inclusions, and then
the resin hardens to
result in an impermeable barrier. If the inclusions are only filled with
viscous fluid containing no
proppant, then provided the injected fluid hasn't set or hardened until after
neighboring
inclusions are injected, by the use of a time delay agent incorporated into
the injected fluid, then
upon setting of the fluid a substantially continuous barrier will result.
It is well known that extensive heavy oil reservoirs are found in formations
comprising
unconsolidated, weakly cemented sediments. Unfortunately, the methods
currently used for
extracting the heavy oil from these formations require the injection of steam
under pressure, such
as SAGD, and as such are difficult and often uneconomic if the SAGD well pairs
are located in
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proximity to an outcrop or depleted low pressure steam chambers. Even though
the formations
contain significant quantities of heavy oil and bitumen, that is basically
immobile at initial
reservoir conditions, the pore water saturation and permeability of the
formation gives rise to
reasonably high water mobility. Lean zones within the formation only greatly
increase the water
mobility, thus giving rise to the need for a barrier to provide a more
efficient, less environmental
impact and more cost effective recovery system. Operating a SAGD steam chamber
at lower
pressure gives rise to higher steam oil ratios (SORs) but even more
significantly at low steam
pressures, the steam may not be able to penetrate horizontal shale layers and
thus restrict the
height of the steam chamber, giving rise to higher SORs and a significant
impact on production.
Such impacts can have a significant effect on the overall economics of the
SAGD process. Thus
there is a need for a vertical continuous barrier to isolate the SAGD system
from an outcrop or
neighboring depleted low pressure steam chambers. In certain circumstances the
barrier will not
be exposed to high temperatures if remote from operating SAGD wells, however
if the barrier is
close to active or depleted steam chambers, the barrier will be require to
perform at elevated
temperatures.
Representatively illustrated in FIG. 1 is a well system 10 and associated
method which
embody principles of the present invention. The system 10 is particularly
useful for constructing
a barrier in a heavy oil or bitumen oil sand formation 14. The formation 14
may comprise
unconsolidated and/or weakly cemented sediments for which conventional
fracturing operations
are not well suited. The term "heavy oil" is used herein to indicate
relatively high viscosity and
high density hydrocarbons, such as bitumen. Heavy oil is typically not
recoverable in its natural
state (e.g., without heating or diluting) via wells, and may be either mined
or recovered via wells
through use of steam and solvent injection, in situ combustion, etc. Gas-free
heavy oil generally
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has a viscosity of greater than 100 centipoise and a density of less than 20
degrees API gravity
(greater than about 900 kilograms/cubic meter).
As depicted in FIG. 1, a central vertical well has been drilled into the
formation 14 and
the well casing 11 has been cemented in the formation 14, and neighboring
vertical wells have
been drilled into the formation and the well casings 16 have been cemented
into the formation
14. The term "casing" is used herein to indicate a protective lining for a
wellbore. Any type of
protective lining may be used, including those known to persons skilled in the
art as liner, casing,
tubing, etc. Casing may be segmented or continuous, jointed or unjointed,
conductive or non-
conductive made of any material (such as steel, aluminum, polymers, composite
materials, etc.),
and may be expanded or unexpanded, etc.
The central well casing string 11 has expansion devices 12 interconnected
therein. The
neighboring relief wells casing string 16 has an open section 15
interconnected therein. The open
section 15 could be a perforated section of the casing, a screen, slotted
liner, etc providing
hydraulic connection between the neighboring well and the formation 14. The
open section 15 of
the well is maintained at a lOwer pressure and independently of the injected
fluid 22 pressure.
The expansion devices 12 operate to expand the casing string 11 radially
outward and thereby
dilate the formation 14 proximate the devices, in order to initiate forming of
generally vertical
and planar inclusions 18, 19 extending outwardly from the wellbore at various
azimuths. Suitable
expansion devices for use in the well system 10 are described in U.S. Patent
Nos. 6,216,783,
6,330,914, 6,443,227, 6,991,037, 7,404,441, 7,640,975, 7,640,982, 7,748,458,
7,814,978,
7,832,477, 7,866,395, 7,950,456 and 8,151,874. The entire disclosures of these
prior patents are
incorporated herein by this reference. Other expansion devices may be used in
the well system
10 in keeping with the principles of the invention.
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Once the devices 12 are operated to expand the casing string 11 radially
outward, fluid 22
is forced into the dilated formation 14 to propagate the inclusions 18, 19
into the formation. It is
not necessary for the inclusions 18, 19 to be formed simultaneously. Shown in
FIG. 1 is a two
(2) wing inclusion well system 10, with two (2) inclusions 18, 19 formed at
differing depths. The
well system 10 does not necessarily need to consist of two (2) inclusions at
differing depths, but
could consist of a single height inclusion, also the two (2) wings need not be
on the same plane
or azimuth, but could vary in azimuth, even to the point of constructing a
closed barrier system
in plan. The choice of the number of inclusions constructed, their geometry,
etc will depend on
the application, outcrop geometry and orientation, depleted steam chamber
geometry, formation
type and/or economic benefit.
Typically, the lower inclusions 18 are constructed first, with each wing of
the inclusions
18, 19 injected independently of the others. As the inclusions 18, 19 are
propagated into the
formation 14, the open section 15 of the on azimuth neighboring relief well
acts as a pore
pressure sink and thus attracts and accelerates the lateral propagation of the
inclusion 18, 19, so
as to intersect with the neighboring relief well, and thus stop the lateral
propagation of the
inclusion. The formation 14, pore space may contain a significant portion of
immobile heavy oil
or bitumen generally up to a maximum oil saturation of 90%; however, even at
these very high
oil saturations of 90%, i.e. very low water saturation of 10%, the mobility of
the formation pore
water is quite high, due to its viscosity and the formation permeability. The
open section 15
allows mobile formation pore fluids and the injected fluid 22 to enter the
relief well at the open
section 15 at a reduced pressure, with the open section 15 being at a lower
and independent of
the injected fluid 22 pressure. Upon the inclusions reaching the open section
15, its lateral tip
propagation will stop. The well system 10 is shown with inclusions 18, 19
constructed at only
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two depths, this well system 10 is cited as only one example of the invention,
since there could
be alternate forms of the invention containing numerous of upper inclusions
constructed at
progressively shallower depths, depending on the formation thickness and the
presence of lean
zones, the distribution of hydrocarbons within the formation 14, and/or
economic benefit.
The injected fluid 22 carries the proppant to the extremes of the inclusions
18, 19. Upon
propagation of the inclusions 18, 19 to their required lateral and vertical
extent, the thickness of
the inclusions 18, 19 may need to be increased by utilizing the process of tip
screen out. The tip
screen out process involves modifying the proppant loading and/or inject fluid
22 properties to
achieve a proppant bridge at the inclusion tips. The injected fluid 22 is
further injected after tip
screen out, but rather then extending the inclusion laterally or vertically,
the injected fluid 22
widens, i.e. thickens, and fills the inclusion from the inclusion tips back to
the well bore.
The behavioral characteristics of the injected viscous fluid 22 are preferably
controlled to
ensure the propagating viscous inclusions maintain their azimuth
directionality, such that the
viscosity of the injected fluid 22 and its volumetric rate are controlled
within certain limits
depending on the formation 14, the specific gravity and size distribution of
the proppant 20. For
example, the viscosity of the injected fluid 22 is preferably greater than
approximately 100
centipoise. However, if foamed fluid is used, a greater range of viscosity and
injection rate may
be permitted while still maintaining directional and geometric control over
the inclusions. The
viscosity and volumetric rate of the injected fluid 22 needs to be sufficient
to transport the
proppant 20 to the extremities of the inclusions. The size distribution of the
proppant 20 needs to
be matched with that of the formation 14. Typical size distribution of the
proppant would range
from #12 to #20 U.S. Mesh for oil sand formations, with an ideal proppant
being sand, ceramic
beads, water or hydrocarbon swellable rubber beads, or ceramic beads coated
with a electrically
20
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conductive resin, of which one particularly suitable conductive resin
comprises phenol
formaldehyde containing fine graphite particles. Such a resin is heat
hardenable at temperatures
of around 60 C or higher, thus capable of mechanically binding the proppant
together 21 and
filling the voids in the proppant packed inclusions to yield impermeable
inclusions.
Depending of the type of proppant used and the method of filling the voids in
the
inclusions, the next steps in the method will differ. If the proppant is water
or hydrocarbon
swellable rubber beads, then the beads will swell and fill the void space in
the inclusions. If the
proppant is a ceramic coated with an electrically conductive resin, then
electrodes are placed in
the wells, and an alternating direction current is passed between the well to
its neighboring wells,
with the electric current passing through the proppant contained in all of the
inclusions, thus
heating the inclusion by electrical resistive heating. By electrically
resistive heating of the
inclusion, the heat hardening resin softens and flows to fill the pore space
in the inclusions, with
the formation providing an active horizontal closure stress on the inclusions
thus consolidating
the inclusions, and then the resin hardens to be an impermeable barrier.
If the proppant is a sand or ceramic beads, and a low temperature barrier is
acceptable,
then low temperature high salinity water is circulated throughout the
inclusions and freezes the
fresher pore water in the formation, thus creating a freeze wall or barrier.
However, if methane
gas is present in the formation, and gas hydrates form in the inclusion pore
fluid then the
inclusions would freeze and either temporarily or completely stop the
recirculation process. In
such a case, a freeze barrier would not be appropriate, since the prime
benefit of the freeze
barrier as described is its thickness, due to the large frozen zone in the
formation either side of
the inclusions. As an alternate to a freeze barrier, with sand or ceramic bead
proppant, a low
viscosity grout is injected into the inclusions and fills the voids of the
inclusions, and included in
21
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the grout is a time delay setting agent. Alternatively, the low viscosity
grout is electrically
conductive, and by passing an alternating electric current through the
inclusions filled with the
grout, heats and thus hardens and sets the grout.
The selected range of temperatures that the barrier will be subjected to,
depends on its
distance from active or depleted steam chambers, the time that the barriers
needs to function, the
steam pressure of active steaming operations, and the temperatures of the
depleted steam
chambers. The barriers need to be placed either before active steaming
operations have begun, or
sufficient distance away to be at substantially initial reservoir stress and
pore pressure state, since
active thermal stresses and large pore pressure gradients can impact the
control of the azimuthal
orientation of the propagating inclusions. For a barrier in close proximity to
proposed SAGD
well pairs, the temperatures it may experience are from 150 C for low
pressure to 275 C for
high pressure steaming operations.
The operating pressure of the process for circulating low temperature coolant,
such as
high saline water, or the injection of low viscosity grout, would be close to
ambient reservoir
conditions, due to the proppant packed inclusions having a permeability at
least two orders of
magnitude greater than the formation, thus allowing circulation or injection
to be conducted
close to ambient reservoir conditions.
As depicted in FIG. 2, an alternate configure of the well system 10 is shown
with all
wells being vertical injection wells, drilled into the formation 14 and the
well casing 11 has been
cemented in the formation 14, and neighboring vertical wells have been drilled
into the
formation, and the well casings 11 have been cemented into the formation 14.
In this
configuration, typically the multiple propped vertical inclusions 18 are
constructed at various
azimuths first from the central well and propagate into the oil sand
formation, filled with a
22
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proppant, and injection of the propagating fluid 22 is stopped when the
inclusion is
approximately midway between the central well and its neighboring injection
well. The fluid in
the lowermost inclusion 18 loses its viscosity over time due to breakers
placed in the injected
fluid 22. Common breakers consist of enzymes, catalyzed oxidizers, and organic
acids. The
formation 14, pore space may contain a significant portion of immobile heavy
oil or bitumen
generally up to a maximum oil saturation of 90%; however, even at these very
high oil
saturations of 90%, i.e. very low water saturation of 10%, the mobility of the
formation pore
water is quite high, due to its viscosity and the formation permeability. Thus
during propagation
of the opposing inclusion 18' from the neighboring well, the inclusion 18 pore
fluid's viscosity is
low due to the action of the breaker, then inclusion 18 acts a large pore
pressure sink, due to size,
relative permeability to the formation, mobility of its fluids and the
formation's pore fluids, and
hydraulic connection to the central well, resulting in the intersect and
coalescence of 18' and 18
irrespective of slight discrepancies in their azimuthal orientations.
Additional vertical inclusions
19 filled with the same proppant are initiated in the central well at
progressively shallower
depths but on azimuth with the lower propped inclusions, such that they
propagate laterally and
vertical into the formation and intersect and coalesce with the lower
inclusions, since these lower
inclusions 18, 18' act as pore pressure sinks due to their low inclusion pore
fluid viscosity from
the action of the breakers in the injected fluid 22. Injection of the
inclusions 19 are stopped,
when the inclusion 19 is approximately midway between the central and
neighboring well, and
similarly inclusions 19' are formed to intersect and coalesce with inclusions
18, 18' and 19,
creating a continuous and coalesced inclusions both vertically and laterally.
The formation 14 could be comprised of relatively hard and brittle rock, but
the system
10 and method find especially beneficial application in ductile rock
formations made up of
23
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unconsolidated or weakly cemented sediments, in which it is typically very
difficult to obtain
directional or geometric control over inclusions as they are being formed.
However, the present disclosure provides information to enable those skilled
in the art of
hydraulic fracturing, soil and rock mechanics to practice a method and system
10 to initiate and
control the propagation of a viscous fluid in weakly cemented sediments, and
importantly for the
propagating inclusion to intersect and coalesce with earlier placed permeable
inclusions and thus
form a continuous planar inclusion on a particular azimuth from within a
single well or between
multiple wells.
The system and associated method are applicable to formations of weakly
cemented
sediments with low cohesive strength compared to the vertical overburden
stress prevailing at the
depth of interest. Low cohesive strength is defined herein as no greater than
3 MegaPasca (MPa)
plus 0.4 times the mean effective stress (p') in MPa at the depth of
propagation.
c < 3MPa+ 0.4p1 (1)
where c is cohesive strength in MPa and p' is mean effective stress in the
formation.
Examples of such weakly cemented sediments are sand and sandstone formations,
mudstones, shales, and siltstones, all of which have inherent low cohesive
strength. Critical state
soil mechanics assists in defining when a material is behaving as a cohesive
material capable of
brittle fracture or when it behaves predominantly as a ductile frictional
material.
Weakly cemented sediments are also characterized as having a soft skeleton
structure at
low effective mean stress due to the lack of cohesive bonding between the
grains. On the other
hand, hard strong stiff rocks will not substantially decrease in volume under
an increment of load
due to an increase in mean stress.
24
SGR/10069006 1
CA 02829008 2013-10-01
In the art of poroelasticity, the Skempton B parameter is a measure of a
sediment's
characteristic stiffness compared to the fluid contained within the sediment's
pores. The
Skempton B parameter is a measure of the rise in pore pressure in the material
for an incremental
rise in mean stress under undrained conditions.
In stiff rocks, the rock skeleton takes on the increment of mean stress and
thus the pore
pressure does not rise, i.e., corresponding to a Skempton B parameter value of
at or about 0. But
in a soft soil, the soil skeleton deforms easily under the increment of mean
stress and, thus, the
increment of mean stress is supported by the pore fluid under undrained
conditions
(corresponding to a Skempton B parameter of at or about 1).
The following equations illustrate the relationships between these parameters
in equations
denoted as (2) as follows:
Au = &Sp
B = (Ku ¨ K)I(aKõ) (2)
a =1¨(K I K,)
where Liu is the increment of pore pressure, B the Skempton B parameter, Ap
the increment of
mean stress, Kt, is the undrained formation bulk modulus, K the drained
formation bulk modulus,
a is the Biot-Willis poroelastic parameter, and K, is the bulk modulus of the
formation grains. In
the system and associated method, the bulk modulus K of the formation for
inclusion
propagation is preferably less than approximately 5 GPa.
For use of the system 10 and method in weakly cemented sediments, preferably
the
Skempton B parameter is as follows with p' in MPa:
B> 0.95 exp(-0.04p') + 0.008p' (3)
The system and associated method are applicable to formations of weakly
cemented sediments
(such as tight gas sands, mudstones and shales) where large entensive propped
vertical
25
SGR/10069006.1
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permeable drainage planes are desired to intersect thin sand lenses and
provide drainage paths for
greater gas production from the formations. In weakly cemented formations
containing heavy oil
(viscosity>100 centipoise) or bitumen (extremely high viscosity>100,000
centipoise), generally
known as oil sands, propped vertical permeable drainage planes provide
drainage paths for cold
production from these formations, and access for steam, solvents, oils, and
heat to increase the
mobility of the petroleum hydrocarbons and thus aid in the extraction of the
hydrocarbons from
the formation. In highly permeable weak sand formations, permeable drainage
planes of large
lateral length result in lower clrawdown of the pressure in the reservoir,
which reduces the fluid
gradients acting towards the wellbore, resulting in less drag on fines in the
formation, resulting in
reduced flow of formation fines into the wellbore.
Proppant is carried by the injected fluid, resulting in a highly permeable
planar inclusion.
Such proppants are typically clean sand or specialized manufactured particles
(generally ceramic
in composition), and depending on the size composition, closure stress and
proppant type, the
permeability of the fracture can be controlled. Water or hydrocarbon swellable
rubber beads can
swell to twice their initial volume over time, due to their osmotic uptake of
water or
hydrocarbon. These beads are capable of acting as a barrier even at elevated
temperatures.
Electrically conductive proppant can consist of ceramics with electrically
conductive resin, with
a suitable conductive resin comprises phenol formaldehyde containing fine
graphite particles.
The permeability of the propped inclusions 18 will typically be orders of
magnitude greater than
the formation 14 permeability, generally at least by two orders of magnitude.
As regards the
electrical conductivity of the propped inclusions 18, the electrical
conductivity needs to be
greater than the formation 14 electrical conductivity, but not too great
whereas electric energy is
lost by excessive short- circuiting between the electrodes, but an optimum
value to achieve
26
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CA 02829008 2013-10-01
optimum, efficient and economical resistive heating of the inclusions 18 and
the proppant 20,
resulting in the resin completely filling the inclusions' voids 21.
The injected fluid 22 varies depending on the application and can be water,
oil or multi-
phased based gels. Aqueous based fracturing fluids consist of a polymeric
gelling agent such as
solvatable (or hydratable) polysaccharide, e.g. galactomannan gums,
glycomannan gums and
cellulose derivatives. The purpose of the hydratable polysaccharides is to
thicken the aqueous
solution and thus act as viscosifiers, i.e. increase the viscosity by 100
times or more over the base
aqueous solution. A cross-linking agent can be added which further increases
the viscosity of the
solution. The borate ion has been used extensively as a cross-linking agent
for hydrated guar
gums and other galactomannans. See U.S. Patent No. 3,059,909 to Wise. Other
suitable cross-
linking agents are chromium, iron, aluminum, and zirconium (see U.S. Patent
No. 3,301,723 to
Chrisp) and titanium (see U.S. Patent No. 3,888,312 to Tiner et al.). A
breaker is added to the
solution to controllably degrade the viscous fracturing fluid. Common breakers
are enzymes and
catalyzed oxidizer breaker systems, with weak organic acids sometimes used.
An enlarged scale isometric view of the system 10 is representatively
illustrated in FIG.
3, This view depicts the system 10 during the propagation of only one of the
lowermost
inclusions 18, to provide a clearer description of the process used to
construct the system 10. The
viscous fluid propagation process in these sediments involves the unloading of
the formation 14
in the vicinity of the tips 23, 24, 25 of the propagating viscous fluid 22,
causing dilation of the
formation 14, which generates pore pressure gradients towards this dilating
zone. As the
formation 14 dilates at the tips 23, 24, 25 of the advancing viscous fluid 22,
the pore pressure
decreases dramatically at the tips, resulting in increased pore pressure
gradients surrounding the
tips.
27
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The pore pressure gradients at the tips 23, 24, 25 of the inclusion 18 result
in the
liquefaction, cavitation (degassing) or fluidization of the formation 14
immediately surrounding
the tips. That is, the formation 14 in the dilating zone about the tips 23,
24, 25 acts like a fluid
since its strength, fabric and in situ stresses have been destroyed by the
fluidizing process, and
this fluidized zone in the formation immediately ahead of the viscous fluid 22
propagating tips
23, 24, 25 is a planar path of least resistance for the viscous fluid to
propagate further. In at least
this manner, the system 10 and associated method provide for directional and
geometric control
over the advancing inclusions 18.
The behavioral characteristics of the injected viscous fluid 22 are preferably
controlled to
ensure the propagating viscous fluid does not overrun the fluidized zone and
lead to a loss of
control of the propagating process. Thus, the viscosity of the fluid 22 and
the volumetric rate of
injection of the fluid should be controlled to ensure that the conditions
described above persist
while the inclusions 18 are being propagated through the formation 14. The
propagation rate of
the inclusion 18 due to the injected fluid 22, varies depending on direction,
in general due to
gravitation effects, the lateral tip 23 propagation rate is generally much
greater than the upward
tip 24 propagation rate and the downward tip 25 propagation rate. However,
these tips 23, 24, 25
propagation rates can change due to heterogeneities in the formation 14, pore
pressure gradients
especially associated with pore pressure sinks, and stress, stiffness and
strength contrasts in the
formation 14.
During propagation of the inclusion 18, the pore pressure in the overall
formation 14 will
rise due to the injection of the fluid 22. As the inclusion 18 propagates, the
open section 15 of the
neighboring relief well acts as a pore pressure sink and mobile formation pore
fluids and injected
fluid 22 flows towards 15 as shown by 29. The open section 15 thus attracts
and accelerates the
28
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CA 02829008 2013-10-01
lateral tip 23 propagation rate of the inclusion 18. The inclusion 18 grows
laterally towards the
open section 15, and upon reaching the relief well, the inclusion lateral tip
propagation stops.
Referring further to an enlarged scale isometric view of the system 10 is
representatively
illustrated in FIG. 4. The inclusion 18 has intersected the neighboring relief
and its lateral
propagation has stopped. By shutting in the neighboring relief well, the
inclusion 18 can be
thickened if desired by the process of tip screen-out.
Referring further to an enlarged scale isometric view of the system 10 is
representatively
illustrated in FIG. 5. This view depicts the system 10 during the propagation
of only one of the
uppermost inclusions 19, to provide a clearer description of the process used
to construct the
system 10. The lowermost inclusion 18 has been constructed to its final
dimension, and the fluid
within the inclusion 18 has lost its viscosity due to breakers placed in the
injected fluid 22.
Common breakers consist of enzymes, catalyzed oxidizers, and organic acids.
The formation 14,
pore space may contain a significant portion of immobile heavy oil or bitumen
generally up to a
maximum oil saturation of 90%; however, even at these very high oil
saturations of 90%, i.e.
very low water saturation of 10%, the mobility of the formation pore water is
quite high, due to
its viscosity and the formation permeability. Thus during propagation of the
uppermost inclusion
19, and provided the lowermost inclusion pore fluid's viscosity is low due to
the action of the
breaker, then the lowermost inclusion 18 acts a large pore pressure sink, due
to size, relative
permeability to the formation, mobility of its and the formation's pore
fluids, as does the open
section 15 in the neighboring relief well.
During propagation of the uppermost inclusion 19, the pore pressure in the
overall
formation will rise due to the injection of the fluid 22. The lowermost
inclusion 18 will act as a
pore pressure sink and thus attract and accelerate the downward propagating
tip 28, and ensure
29
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that the propagating uppermost inclusion 19 intersects and coalesces with the
lowermost
inclusion 18, even if there are slight discrepancies in their respective
azimuthal orientations.
Upon coalescence of the downward propagating tip 28 with the lowermost
inclusion 18, the tip
28 will stop propagating in the area of coalescence due to leakoff of the
injected fluid 22 to the
highly permeable pore pressure sink, inclusion 18. As the inclusion 19 further
propagates, the
open section 15 of the on azimuth neighboring relief well acts as a pore
pressure sink and mobile
formation pore fluids and injected fluid 22 flows towards 15 as shown by 29.
The open section
thus attracts and accelerates the lateral tip 26 propagation rate of the
inclusion 19. The
inclusion 19 grows laterally towards the open section 15, and upon reaching
the relief well, the
inclusion lateral tip propagation stops. At completion of the injection of
fluid 22 in inclusions 19,
15 the system 10 configuration will contain continuous vertical
coalescence of inclusions 18 with its
respective on azimuth inclusions 19.
Referring further to an enlarged scale isometric view of the system 10 is
representatively
illustrated in FIG. 6. The inclusion 19 has intersected and coalesced with the
lower inclusion 18,
and intersected the neighboring relief and thus its lateral propagation has
stopped. By shutting in
the neighboring relief well, the inclusion 19 can be thickened if desired by
the process of tip
screen-out.
Referring further to an enlarged scale isometric view of the system 10 is
representatively
illustrated in FIG. 7 in an 'alternate configuration. In this alternate
configuration, the neighboring
well is an injection well and not a relief well as shown earlier in FIG. 3.
The neighboring
injection well casing string 11 has expansion devices 12 interconnected
therein. The lower
inclusion 18 is propagating into the formation and the injection fluid 22 flow
rate is stopped
when the inclusion is approximately midway between the central well and the
neighboring
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injection well. The inclusion 18 can be thickened at this stage by the process
of tip screen-out if
desired.
Referring further to an enlarged scale isometric view of the system 10 is
representatively
illustrated in FIG. 8. This view depicts the system 10 during the propagation
of the lowermost
inclusion 18' from the neighboring injection well. The lowermost inclusion 18
has been
constructed to its final dimension, and the fluid within the inclusion 18 has
lost its viscosity due
to breakers placed in the injected fluid 22. Common breakers consist of
enzymes, catalyzed
oxidizers, and organic acids. The formation 14, pore space may contain a
significant portion of
immobile heavy oil or bitumen generally up to a maximum oil saturation of 90%;
however, even
at these very high oil saturations of 90%, i.e. very low water saturation of
10%, the mobility of
the formation pore water is quite high, due to its viscosity and the formation
permeability. Thus
during propagation of the lowermost inclusion 18', and provided the lowermost
inclusion pore
fluid's viscosity is low due to the action of the breaker, then the lowermost
inclusion 18 acts a
large pore pressure sink, due to size, relative permeability to the formation,
mobility of its and
the formation's pore fluids, resulting in the intersect and coalescence of 18'
and 18 irrespective
of slight discrepancies in their azimuthal orientations.
Referring further to an enlarged scale isometric view of the system 10 is
representatively
illustrated in FIG. 9. This view depicts the system 10 during the propagation
of only one of the
uppermost inclusions 19, to provide a clearer description of the process used
to construct the
system 10. The lowermost inclusions 18 and 18' have been constructed to their
final dimensions,
and the fluid within the inclusions 18 and 18' have lost its viscosity due to
breakers placed in the
injected fluid 22. Thus during propagation of the uppermost inclusion 19, and
provided the
lowermost inclusions pore fluid's viscosity is low due to the action of the
breaker, then the
31
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lowermost inclusions 18 and 18' acts as large pore pressure sinks, due to
size, relative
permeability to the formation, mobility of its and the formation's pore
fluids. Thus inclusion 19
intersects and coalesces with inclusions 18 and 18'. The injected fluid 22
flow rate is stopped
once the inclusion 19 is approximately midway between the central well and the
neighboring
injection well.
Referring further to an enlarged scale isometric view of the system 10 is
representatively
illustrated in FIG. 10. This view depicts the system 10 for the completion of
all inclusions, 18,
18', 19, 19' showing the coalescence of the inclusions both vertically and
laterally.
Finally, it will be understood that the preferred embodiment has been
disclosed by way of
example, and that other modifications may occur to those skilled in the art
without departing
from the scope and spirit of the appended claims.
32
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