Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
CA 02829272 2013-10-01
INCLUSION PROPAGATION BY CASING EXPANSION GIVING RISE TO
FORMATION DILATION AND EXTENSION
TECHNICAL FIELD
The present invention generally relates to enhanced recovery of petroleum
fluids from the
subsurface by initiating and propagating vertical permeable inclusions in a
plane substantially
orthogonal to the borehole axis. These inclusions containing proppant are thus
highly permeable
and enhance drainage of heavy oil from the formation, and also by steam
injection into these
planes, enhance oil recovery by heating the oil sand formation, the heavy oil
and bitumen, which
will drain under gravity and be produced. Multiple propped vertical inclusions
are constructed at
various locations along a substantially horizontal wellbore by dilation of the
formation in the
plane of the intended inclusion by radial expansion and axial extension of the
formation. This
dilated and extensional plane within the formation provides a preferential
pathway for injected
fluid to propagate in the 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
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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.
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 -4,000,000 centipoise. However at
elevated temperatures the
bitumen viscosity changes considerably to be ¨350 centipoise at 100 C down to
¨10 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.
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
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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 between 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 3 -5 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.
In situ methods of hydrocarbon extraction from the oil sands consist of cold
production,
in which the less viscous petroleum fluids are extracted from vertical and
horizontal wells with
sand exclusion screens, CHOPS (cold heavy oil production system) cold
production with sand
extraction from vertical and horizontal wells with large diameter perforations
thus encouraging
sand to flow into the well bore, CSS (cyclic steam stimulation) a huff and
puff cyclic steam
injection system with gravity drainage of heated petroleum fluids using
vertical and horizontal
wells, steamflood using injector wells for steam injection and producer wells
on 5 and 9 point
layout for vertical wells and combinations of vertical and horizontal wells,
SAGD (steam
assisted gravity drainage) steam injection and gravity production of heated
hydrocarbons using
two horizontal wells, VAPEX (vapor assisted petroleum extraction) solvent
vapor injection and
gravity production of diluted hydrocarbons using horizontal wells, and
combinations of these
methods.
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Cyclic steam stimulation and steamfiood hydrocarbon enhanced recovery methods
have
been utilized worldwide, beginning in 1956 with the discovery of CSS, huff and
puff or steam-
soak in Mene Grande field in Venezuela and for steamflood in the early 1960s
in the Kern River
field in California. These steam assisted hydrocarbon recovery methods
including a combination
of steam and solvent are described in U.S. Patent No. 3,739,852 to Woods et
al, U.S. Patent No.
4,280,559 to Best, U.S. Patent No. 4,519,454 to McMillen, U.S. Patent No.
4,697,642 to Vogel,
and U.S. Patent No. 6,708,759 to Leaute et al. The CSS process raises the
steam injection
pressure above the formation fracturing pressure to create fractures within
the formation and
enhance the surface area access of the steam to the bitumen. Successive steam
injection cycles
reenter earlier created fractures and thus the process becomes less efficient
over time. CSS is
generally practiced in vertical wells, but systems are operational in
horizontal wells, but have
complications due to localized fracturing and steam entry and the lack of
steam flow control
along the long length of the horizontal well bore.
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 Vandergrift,
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, 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.
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A thermal steam extraction process referred to a HASDrive (heated =lulus steam
drive)
and modifications thereof heat and hydrogenate the heavy oils insitu in the
presence of a metal
catalyst. See U.S. Patent No. 3,994,340 to Anderson et al., U.S. Patent No.
4,696,345 to Hsueh,
U.S. Patent No. 4,706,751 to Gondouin,U.S. Patent No. 5,054,551 to Duerksen,
and U.S. Patent
No. 5,145,003 to Duerksen. It is disclosed that at elevated temperature and
pressure the injection
of hydrogen or a combination of hydrogen and carbon monoxide to the heavy oil
in situ in the
presence of a metal catalyst will hydrogenate and thermal crack at least a
portion of the
petroleum in the formation.
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. Therefore a less energy intensive oil
recovery process is
desirable.
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
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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 3 -5 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 is
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
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.
Direct heating and electrical heating methods for enhanced recovery of
hydrocarbons
from oil sands and oil shales have been disclosed in combination with steam,
hydrogen, catalysts
and/or solvent injection at temperatures to ensure the petroleum fluids
gravity drain from the
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formation and at significantly higher temperatures (3000 to 400 range and
above) to pyrolysis
the oil shales. See U.S. Patent No. 2,780,450 to Ljungstreim, U.S. Patent No.
4,597,441 to Ware
et a!, U.S. Patent No. 4,926,941 to Glandt et al,U U.S. Patent No. 5,046,559
to Glandt,U.S. Patent
No. 5,060,726 to Glandt et al, U.S. Patent No. 5,297,626 to Vinegar et al,
U.S. Patent No.
5,392,854 to Vinegar et al, U.S. Patent No. 6,722,431 to Karanikas et al. In
situ combustion
processes have also been disclosed see U.S. Patent No. 5,211,230 to Ostapovich
et al, U.S.
Patent No. 5,339,897 to Leaute, U.S. Patent No. 5,413,224 to Laali, and U.S.
Patent No.
5,954,946 to Klazinga et al.
In situ processes involving downhole heaters are described in U.S. Patent No.
2,634,961
to LjungstrOm, U.S. Patent No. 2,732,195 to Ljungstrom, U.S. Patent No.
2,780,450 to
LjungstrOm. Electrical heaters are described for heating viscous oils in the
forms of downhole
heaters and electrical heating of tubing and/or casing, see U.S. Patent No.
2,548,360 to Germain,
U.S. Patent No. 4,716,960 to Eastlund et al, U.S. Patent No. 5,060,287 to Van
Egmond, U.S.
Patent No. 5,065,818 to Van Egmond,U.S. Patent No. 6,023,554 to Vinegar and
U.S. Patent No.
6,360,819 to Vinegar. Flameless downhole combustor heaters are described, see
U.S. Patent No.
5,255,742 to Mikus, U.S. Patent No. 5,404,952 to Vinegar et al, U.S. Patent
No. 5,862,858 to
Wellington et al, and U.S. Patent No. 5,899,269 to Wellington et al. Surface
fired heaters or
surface burners may be used to heat a heat transferring fluid pumped downhole
to heat the
formation as described in U.S. Patent No. 6,056,057 to Vinegar et al and U.S.
Patent No.
6,079,499 to Mikus et al.
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
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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.
Maintaining reservoir pressure during heating of the oil sands has the
significant benefit of
minimizing water inflow to the heated zone and to the well bore.
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
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
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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
contact.
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 have not produced entirely
satisfactory results.
Heavy oil is not very mobile in these formations, and so it would be desirable
to be able to form
increased permeability planes in the formations and by injecting steam or
solvents into these
planes and/or by direct electrical resistive heating of the plane, heating the
formation and thus
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increase the mobility of the heavy oil in the formation and by drainage
through the permeable
planes to the wellbore for production up the well.
However, 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 Hocking, 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
sediments behave substantially different from brittle rocks from which most of
the hydraulic
fracturing experience is founded. The above methods cited, disclose a method
to create a planar
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inclusion that is parallel to the borehole axis, and these methods do not
disclose how such an
inclusion can be initiated and propagated orthogonal to the borehole axis.
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 proppant.
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 enhancing the
extraction of
hydrocarbons from oil sands by constructing vertical planar permeable
inclusions with planes
that are orthogonal to the borehole axis and are thus of greater assistance in
enhancing recovery
methods such as SAGD. The SAGD system with such inclusions installed would not
require a
steam circulation period to hydraulically connect the injector and producer
wells, since startup in
SAGD mode with the permeable inclusions would be immediate. Also these
inclusions would
penetrate horizontal shale layers, which otherwise may be a barrier to upward
steam chamber
growth and limit SAGD production and impair its performance. The vertical
permeable
inclusions extending through such shale layers would greatly enhance SAGD
performance. The
immediate drainage and increase in effective drainage height due to the
yertical permeable
inclusions will also enhance the productivity and lower the SOR of the SAGD
system.
SUMMARY OF THE INVENTION
The present invention is a method and apparatus for enhanced recovery of
petroleum
fluids from the subsurface by initiating and propagating vertical permeable
inclusions in a plane
substantially orthogonal to the borehole axis. These inclusions containing
proppant are thus
highly permeable and enhance drainage of heavy oil from the formation, and
also by steam
injection into these planes, enhance oil recovery by heating the oil sand
formation, the heavy oil
and bitumen, which will drain under gravity and be produced. In one embodiment
of this
invention, multiple propped vertical inclusions are constructed at various
locations along a
substantially horizontal wellbore by dilation of the formation in the plane of
the intended
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inclusion by radial expansion and axial extension of the formation by an
expanding packer
system that expands both radially and axially. In another embodiment of the
invention, the
expansion device is part of a casing string or liner and is in contact with
the formation by a
swellable elastomer, or by a cement or polymer based grout. The expansion
device is expanded
by an inflatable packer and the device expands both radially outward and
extensionally in the
axial direction, giving rise to a dilated extensional plane in the formation
which is substantially
orthogonal to the well bore axis. Injected fluid propagates preferentially in
this dilated and
extensional plane within the formation. The vertical inclusions are propagated
to intersect and
connect with neighboring horizontal wells to eliminate the non-productive
startup phase of
SAGD. Also the inclusion could be filled with an electrically conductive
proppant and fibers and
by placing an alternating current through the inclusions heat the inclusions
by electrical resistive
heating and thus heat the oil sand formation.
Although the present invention contemplates the formation of vertical propped
inclusions
which generally extend laterally away from a substantially near horizontal
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 inclusions and
the well bores can
extend in directions other than horizontal, and/or that the well bore axis
could vary in orientation
and depth along its length.
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 horizontal well system and
associated method
embodying principles of the present invention;
FIG. 2 is a schematic isometric view of a dual expanding packer system, that
expands
both radially and axially;
FIG. 3 is a schematic isometric view of the casing expansion device with
weakening slots
and latches to limit the extent of opening and inhibit closure;
FIG. 4 is a schematic isometric view of the casing expansion device expanded
by an
inflatable packer.
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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 involves a method and apparatus
for enhanced
recovery of petroleum fluids from the subsurface by construction of propped
vertical inclusions
in the oil sand formation from a substantially horizontal wellbore for
enhancing drainage of
heavy oil from the formation and/or to provide a means of injecting steam,
thus heating the oil
sand formation and the heavy oil and bitumen in situ, and at much reduced
viscosity the
hydrocarbon flow by gravity drainage to the well and are produced to surface.
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 have not produced entirely
satisfactory results.
Heavy oil is not very mobile in these formations, and so it would be desirable
to be able to form
highly permeable planes in the formations and by injecting steam or solvents
into the permeable
planes, heating the formation and in-situ hydrocarbons and thus increase the
mobility of the
heavy oil in the formation and by gravity drainage through the permeable
planes to the wellbore
for production up the well.
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
permeable planes 18 in a 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
16
CA 02829272 2013-10-01
use of steam and solvent injection, in situ combustion, etc. Gas-free heavy
oil generally 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 substantially horizontal well has been drilled into
the formation
14 and the well casing 11 has been cemented in 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 horizontal well casing string 11 has expansion devices 12 interconnected
therein.
The expansion device 12 operates to expand the casing string 11 radially
outward and axially in
extension and thereby dilate the formation 14 proximate the device, in order
to initiate forming
of generally vertical and planar inclusion 18 extending outwardly from the
wellbore in a plane
substantially orthogonal to the well axis. Suitable expansion devices for use
in the well system
10 for initiating and propagating inclusions on planes parallel to the well
axis 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. The current
invention differs from
the earlier cited disclosures, in that the expansion devices expands both
radially outward and also
in extension axially, to develop a dilated extensional zone in the formation
substantially
orthogonal to the welthore axis. Other expansion devices may be used in the
well system 10 in
keeping with the principles of the invention.
17
CA 02829272 2013-10-01
Once the device 12 is operated to expand the casing string 11 radially outward
and
extensionally axially, fluid 22 is injected into the dilated formation 14 to
propagate the inclusions
18 into the formation. It is not necessary for the inclusions 18 to be formed
simultaneously.
Shown in FIG. 1 are three (3) inclusions 18 in the well system 10, positioned
at differing
locations along the well. The well system 10 does not necessarily need to
consist of three (3)
inclusions at the same depth orientated at the same azimuth, but could consist
of numerous
vertical planar inclusions at various azimuths at the same depth as would be
the case if the well
was curved in plan, with such choice of the number of inclusions constructed
depending on the
application, formation type and/or economic benefit. Also there is only one
inclusion shown at
each distinct position along the well; whereas that inclusion could intersect
and coalesce with an
inclusion on the same azimuth from a neighboring well.
Typically, the inclusions 18 located furthest from the well head are
constructed first, with
each inclusion 18 injected independently as progressed up the well. As the
inclusions 18 are
propagated into the formation 14, the inclusions 18 may intersect and coalesce
with previous
installed inclusions on similar azimuths from nearby well. These earlier
placed inclusions acts as
a pore pressure sink and thus attract and accelerate the propagation of the
inclusion 18, so as to
intersect with the nearby earlier installed 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 well system 10 is shown with inclusions 18 constructed at
only a single depth,
this well system 10 is cited as only one example of the invention, since there
could be alternate
forms of the invention containing numerous number of inclusions constructed at
progressively
18
CA 02829272 2013-10-01
shallower depths from shallow wells, depending on the formation thickness, 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. Upon
propagation of the inclusions 18 to their required lateral and vertical
extent, the thickness of the
inclusions 18 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, proppant 20 specific gravity and size
distribution. 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 need 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, to ensure formation fines do not migrate into the
propped pack inclusion
during hydrocarbon production. 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 or
ceramic beads.
Ceramic beads coated with a resin such as phenol formaldehyde, being heat
hardenable, is
19
CA 02829272 2013-10-01
capable of mechanically binding the proppant together 21 in the presence of
steam without loss
of permeability of the propped inclusion.
As depicted in FIG. 2, is one configuration of the well system 10, with the
expansion
device 12 consisting of two (2) inflatable packers 15 lowered into an open
wellbore on a tubing
string 13. The inflatable packers are expanded radially outward to contact the
formation 14, then
expanded further radially outwards but also pushed axially apart 15', to place
the formation in a
dilation and extensional state in a plane orthogonal to the well axis.
Injected fluids 22 are
injected into the formation and propagate preferentially in this dilated and
extensional plane
created by the expansion device 12 and thus form the inclusion 18.
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
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 wealdy
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.
CA 02829272 2013-10-01
c < 3A1Pa+ 0.4p' (I)
where c is cohesive strength in MPa and p' is mean effective stress in the
formation.
Examples of siich 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.
In the art of poro elasticity, the Skempton B parameter is a measure of a
sediments
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 13 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 = BAp
B = (Ki, ¨ K)I(aKõ) (2)
a =1¨(K I K.,)
21
CA 02829272 2013-10-01
where Au is the increment of pore pressure, B the Skempton B parameter, Lip
the increment of
mean stress, Ku is the undrained formation bulk modulus, K the drained
formation bulk modulus,
a is the Blot-Willis poroelastic parameter, and Ks 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') 0.008p1 (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
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 drawdown of the pressure in the reservoir,
which reduces the fluid
gradients acting towards the wellbore resulting in less drag on fines in the
formation and
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
22
CA 02829272 2013-10-01
permeability of the fracture can be controlled. Either type of proppant could
be resin coating to
provide for bounding between proppant particles 21 at elevated temperatures
and also to reduce
the steam dissolution of the particle over time. 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.
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 another embodiment of the system 10, consisting of an
expansion device 12
that is connected to the casing string 11 and the casing 11 is either cemented
in the wellbore or
the expansion device 12 is coated with a swellable elastomer, swellable in the
presence of water
or hydrocarbons or swellable on the application of heat. Such swellable
elastomers are
commonly used for the production of hydrocarbons for a variety of well
completion systems. By
23
CA 02829272 2013-10-01
either means the expansion device 12 is in contact with the formation 14. The
expansion device
12 could be constructed from a variety of materials, but a yieldable metal,
such as steel is
considered a preferred choice. The expansion device 12 has slots cut through
its thickness in the
axial direction as axial slots 31 and in the circumferential direction as
circumferential slots 32.
The slots 31, 32 are either machined, or cut by laser or watetjet, are narrow
in width in the range
of 0.040" to 0.080" and approximately 1" to 1-1/2" in length, depending on the
diameter of the
expansion device 12 and the intended application. The slots 31, 32 could be
cut through the
entire thickness of the expansion device 12, or only partial cut through the
depth of the
expansion device wall thickness.
The slots 31, 32 shown consist of three (3) rows of slots offset from each
other both along
and orthogonal to the slot orientation, but could be different multiples of
slots depending on the
opening amount required. The axial slots 31 are shown as four (4) sets of
slots 31 being
orientated 90 apart. Depending on the casing diameter and application the
axial slots 31 could
consists of any number of sets of slots, e.g. three (3) sets 120 apart or six
(6) sets 60 apart.
Likewise the circumferential slots 32 are shown as three (3) sets of slots,
whereas there could be
any number of sets of circumferential slots 32, from one (1) set and upwards
depending on the
required opening, casing diameter and application. Straps, latches and braces
33, 34, 35, are
welded to the expansion device 12 and restrict the amount of opening of the
slots 31, 32 and
upon their opening inhibit closure. The straps, latches or braces could be
strips of strain
hardening material, such as stainless steel, that provides for all the slots
to open evenly and
inhibit closure of the slots, due to the stainless steel high strain before
failure and its strain
hardening properties. Alternate latches have been cited earlier in the
incorporated references and
24
CA 02829272 2013-10-01
consist of latches that lock in place upon a certain amount of opening,
inhibit further opening and
hold the slot locked in the open position and inhibit closure of the slots.
An enlarged scale isometric view of the system 10 is representatively
illustrated in FIG.
4. This view depicts the expansion device 12 of the system 10, consisting of a
casing string 11
grouted into the formation 14 by cement or in contact with the formation by a
swellable
elastomer. A packer 15 connected to tubing 13 is lowered into the well and the
packer 15 is set in
proximity to the expansion device 12. The packer 15 is inflated to give rise
to yielding of the
slots 31, 32 and activation of the straps, latches and braces 33, 34, 35, so
that the expansion
device 12 expands radially outward due to the axial slots 31 but also extends
axially
extensionally due to the circumferential slots 32. The radial expansion and
axial extension of the
expansion device 12 develops a zone in the formation 14 substantially
orthogonal to the wellbore
axis in a dilated and extensional state for the preferential propagation of
injected fluids 22 to
propagate in the formation to form the inclusions 18.
The pore pressure gradients at the tips 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 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 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
CA 02829272 2013-10-01
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 propagation rate is generally much
greater than the upward tip
propagation rate and the downward tip propagation rate. However, these tips
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.
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.
26
