Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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ENHANCED HYDROCARBON RECOVERY BY
STEAM INJECTION OF OIL SAND FORMATIONS
TECHNICAL FIELD
[0001] The present invention generally relates to enhanced recovery of
petroleum fluids from the
subsurface by the injection of steam in the oil sand formation contacting the
viscous heavy oil
and bitumen in situ, and more particularly to a method and apparatus to
extract a particular
fraction of the in situ hydrocarbon reserve by controlling the access to the
in situ bitumen, the
steam and solvent composition, and operating temperatures and pressures of the
in situ process,
resulting in increased production of petroleum fluids from the subsurface
formation as well as
limiting water inflow into the process zone.
BACKGROUND OF THE INVENTION
[0002] 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
cohesionless sands with minimal grain to grain cementation. The hydrocarbons
are extracted
from the oils sands either by mining or in situ methods.
[0003] 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
and 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
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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 -350 centipoise at
100 C down to
-l0 centipoise at 180 C. The oil sand deposits have an inherently high
permeability ranging
from -l to 10 Darcy, thus upon heating, the heavy oil becomes mobile and can
easily drain from
the deposit.
[0004] 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 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.
[0005] 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, stream flood 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
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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.
[0006] Cyclic steam stimulation and steam flood 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 steam flood 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, see 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.
[0007] Descriptions of the SAGD process and modifications are described, see
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.
[0008] A thermal steam extraction process referred to a HASDrive (heated
annulus steam drive)
and modifications thereof are described to heat and hydrogenate the heavy oils
in situ in the
presence of a metal catalyst, see U.S. Patent No. 3,994,340 to Anderson et al,
U.S. Patent No.
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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.
[0009] 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.
[00010] 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 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.
[00011] Direct heating and electrical heating methods for enhanced recovery of
hydrocarbons
from oil sands have been disclosed in combination with steam, hydrogen,
catalysts and/or
solvent injection at temperatures to ensure the petroleum fluids gravity drain
from the formation
and at significantly higher temperatures (300 to 400 range and above) to
pyrolysis the oil
sands. See U.S. Patent No. 2,780,450 to Ljungstrom, U.S. Patent No. 4,597,441
to Ware et al,
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U.S. Patent No. 4,926,941 to Glandt et al, 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, and 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.
[00012] 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.
[00013] 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
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over pressurized conditions are usually imposed to accelerated the steam
chamber development,
followed by a prolonged period of under pressurized 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.
[00014] Hydraulic fracturing of petroleum recovery wells enhances the
extraction of fluids
from low permeable formations due to the high permeability of the induced
fracture and the size
and extent of the fracture. A single hydraulic fracture from a well bore
results in increased yield
of extracted fluids from the formation. Hydraulic fracturing of highly
permeable unconsolidated
formations has enabled higher yield of extracted fluids from the formation and
also reduced the
inflow of formation sediments into the well bore. Typically the well casing is
cemented into the
borehole, and the casing perforated with shots of generally 0.5 inches in
diameter over the depth
interval to be fractured. The formation is hydraulically fractured by
injecting fracture fluid into
the casing, through the perforations and into the formation. The hydraulic
connectivity of the
hydraulic fracture or fractures formed in the formation may be poorly
connected to the well bore
due to restrictions and damage due to the perforations. Creating a hydraulic
fracture in the
formation that is well connected hydraulically to the well bore will increase
the yield from the
well, result in less inflow of formation sediments into the well bore and
result in greater recovery
of the petroleum reserves from the formation.
[00015] Turning now to the prior art, hydraulic fracturing of subsurface earth
formations to
stimulate production of hydrocarbon fluids from subterranean formations has
been carried out in
many parts of the world for over fifty years. The earth is hydraulically
fractured either through
perforations in a cased well bore or in an isolated section of an open bore
hole. The horizontal
and vertical orientation of the hydraulic fracture is controlled by the
compressive stress regime in
the earth and the fabric of the formation. It is well known in the art of rock
mechanics that a
fracture will occur in a plane perpendicular to the direction of the minimum
stress, see U.S.
Patent No. 4,271,696 to Wood. At significant depth, one of the horizontal
stresses is generally at
a minimum, resulting in a vertical fracture formed by the hydraulic fracturing
process. It is also
well known in the art that the azimuth of the vertical fracture is controlled
by the orientation of
the minimum horizontal stress in consolidated sediments and brittle rocks.
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[00016] At shallow depths, the horizontal stresses could be less or greater
than the vertical
overburden stress. If the horizontal stresses are less than the vertical
overburden stress, then
vertical fractures will be produced; whereas if the horizontal stresses are
greater than the vertical
overburden stress, then a horizontal fracture will be formed by the hydraulic
fracturing process.
[00017] Hydraulic fracturing generally consists of two types, propped and
unpropped
fracturing. Unpropped fracturing consists of acid fracturing in carbonate
formations and water or
low viscosity water slick fracturing for enhanced gas production in tight
formations. Propped
fracturing of low permeable rock formations enhances the formation
permeability for ease of
extracting petroleum hydrocarbons from the formation. Propped fracturing of
high permeable
formations is for sand control, i.e. to reduce the inflow of sand into the
well bore, by placing a
highly permeable propped fracture in the formation and pumping from the
fracture thus reducing
the pressure gradients and fluid velocities due to draw down of fluids from
the well bore.
Hydraulic fracturing involves the literally breaking or fracturing the rock by
injecting a
specialized fluid into the well bore passing through perforations in the
casing to the geological
formation at pressures sufficient to initiate and/or extend the fracture in
the formation. The
theory of hydraulic fracturing utilizes linear elasticity and brittle failure
theories to explain and
quantify the hydraulic fracturing process. Such theories and models are highly
developed and
generally sufficient for the art of initiating and propagating hydraulic
fractures in brittle materials
such as rock, but are totally inadequate in the understanding and art of
initiating and propagating
hydraulic fractures in ductile materials such as unconsolidated sands and
weakly cemented
formations.
[00018] Hydraulic fracturing has evolved into a highly complex process with
specialized
fluids, equipment and monitoring systems. The fluids used in hydraulic
fracturing vary
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
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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.
[00019] Oil based fracturing fluids are generally based on a gel formed as a
reaction product
of aluminum phosphate ester and a base, typically sodium aluminate. The
reaction of the ester
and base creates a solution that yields high viscosity in diesels or moderate
to high API gravity
hydrocarbons. Gelled hydrocarbons are advantageous in water sensitive oil
producing
formations to avoid formation damage, that would otherwise be caused by water
based fracturing
fluids.
[00020] The method of controlling the azimuth of a vertical hydraulic fracture
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 fracture can be propagated at a pre-
determined azimuth in
unconsolidated or weakly cemented sediments and that multiple orientated
vertical hydraulic
fractures 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 Application No. 11/363,540 and U.S. Patent Application
No. 11/277,308.
The method disclosed that a vertical hydraulic fracture can be propagated at a
pre-determined
azimuth in unconsolidated or weakly cemented sediments and that multiple
orientated vertical
hydraulic fractures 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.
[00021] Accordingly, there is a need for a method and apparatus for enhancing
the extraction
of hydrocarbons from oil sands by direct heating, steam and/or solvent
injection, or a
combination thereof and controlling the subsurface environment, both
temperature and pressure
to optimize the hydrocarbon extraction in terms of produced rate, efficiency,
and produced
product quality, as well as limit water inflow into the process zone.
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SUMMARY OF THE INVENTION
[00022] The present invention is a method and apparatus for enhanced recovery
of petroleum
fluids from the subsurface by injection of steam in contact with the oil sand
formation and the
heavy oil and bitumen in situ. Multiple propped hydraulic fractures are
constructed from the
well bore into the oil sand formation and filled with a highly permeable
proppant. Steam is
injected into the well bore and the propped fractures at or near the ambient
reservoir pressure but
substantially below the reservoir fracturing pressure. The injected steam
flows upwards and
outwards in the propped fractures contacting the oil sands and in situ bitumen
on the vertical
faces of the propped fractures. The steam condenses onto the cool bitumen and
the latent heat of
the steam diffuse into the bitumen from the vertical faces of the propped
fractures. The bitumen
softens and flows by gravity to the well bore, exposing fresh surface of
bitumen for the process
to progressively soften and mobilize the bitumen in a predominantly
circumferential, i.e.
orthogonal to the propped fracture, diffusion direction at a nearly uniform
rate into the oil sand
deposit. To limit upward growth of the process, a light non-condensing gas can
be injected to
remain in the uppermost portions of the propped fractures. The mobile oil may
be deasphalted
by co-injection of a hydrocarbon solvent with the steam, leaving the heavy
asphaltenes behind in
the oil sand pore space with little loss of inherent fluid mobility in the
processed oil sands. The
processed hydrocarbon product with the dissolved solvent is produced from the
formation and
steam along with a hydrocarbon solvent is re-injected into the process zone
and the cycle repeats.
[00023] The processes active at the contact of the inject steam and solvent
with the bitumen in
the oil sand are predominantly diffusive, being driven by partial pressure and
temperature
gradients, resulting in the diffusion of hydrocarbon solvent and heat into the
bitumen. Upon
softening of the bitumen, the oil will become mobile and flow under gravity
and exposed contact
with fresh bitumen in situ for an every larger expanding zone of mobile oil in
the native oil sand
formation. The mobile oil flows by gravity with the dissolved solvent back to
the well bore and
pumped to the surface.
[00024] The hydrocarbon solvent would preferably be one of ethane, propane, or
butane or a
mixture thereof, and be mixed with a non-condensing diluent gas being either
methane, nitrogen,
carbon dioxide, natural gas, or a mixture thereof, to ensure that the selected
composition of the
injected gas is such that: 1) the solvent mixture has a dew point that
substantially corresponds
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with the operating process temperature and pressure in situ, 2) the solvent
mixture is
substantially more soluble in the bitumen than the diluent gas, 3) the solvent
mixture is liquefied
but vaporizable in the process zone, and 4) solvent mixture has a vapor/liquid
envelop that
encompasses the process operating temperatures and pressures. The solvent and
diluent gas are
injected with the steam into the well bore and the process zone, with the
solvent primarily as a
vapor state contacting and diffusing into the bitumen. By selecting the
appropriate solvent,
diluent gas, and steam mixture, the process can operate close to ambient
reservoir pressures, so
that water inflow into the process zone can be minimized. The selected range
of temperatures
and pressures to operate the process will depend on reservoir depth, ambient
conditions, quality
of the in place heavy oil and bitumen, composition of the solvent, diluent gas
and steam mixture,
and the presence of nearby water bodies. At such elevated temperatures, the
diffusion rate of the
solvent diffusing into the bitumen is significantly greater than at reservoir
ambient temperatures.
[00025] As the steam solvent mixture is injected and contacts the in situ
bitumen, the steam
condenses onto the cool bitumen and thus heats the bitumen by conduction. As
the gas mixture
contacts the bitumen, the oil becomes diluted with solvent and heated by the
steam, softens and
flows by gravity to the well bore. The flowing oil contains dissolved solvent.
The produced
product of oil and dissolved solvent is pumped to the surface where the
solvent can be recycled
for further injection.
[00026] Although the present invention contemplates the formation of fractures
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.
[00027] Therefore, the present invention provides a method and apparatus for
enhanced
recovery of petroleum fluids from the subsurface by steam and vaporized
solvents placed in the
oil sand formation contacting the viscous heavy oil and bitumen in situ, and
more particularly to
a method and apparatus to extract a particular fraction of the in situ
hydrocarbon reserve by
controlling the access to the in situ bitumen, the steam solvent composition,
and operating
temperatures and pressures of the in situ process, resulting in increased
production of petroleum
fluids from the subsurface formation as well as limiting water inflow into the
process zone.
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[00028] 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.
BRIEF DESCRIPTION OF THE DRAWINGS
[00029] FIG. 1 is a horizontal cross-section view of a well casing having dual
fracture winged
initiation sections prior to initiation of multiple azimuth controlled
vertical fractures.
[00030] FIG. 2 is a cross-sectional side elevation view of a well casing
having dual fracture
winged initiation sections prior to initiation of multiple azimuth controlled
vertical fractures.
[00031] FIG. 3 is an isometric view of a well casing having dual propped
fractures with
downhole steam, solvent, and diluent gas injection for a cyclic pulsed
pressure steam injection
system.
[00032] FIG. 4 is a horizontal cross-sectional side elevation view of a well
casing and propped
fracture showing flow of the injected gas and oil with progressive growth of
the mobile oil zone.
[00033] FIG. 5 is an isometric view of a well casing having dual propped
fractures with
downhole steam, solvent, and diluent gas injection for a continuous steam
injection system.
[00034] FIG. 6 is a horizontal cross-section view of a well casing having
multiple fracture
dual winged initiation sections after initiation of all four controlled
vertical fractures.
[00035] FIG. 7 is an isometric view of a well casing having four propped
fractures with
downhole steam, solvent, and diluent gas injection for a cyclic pulsed
pressure steam injection
system.
[00036] FIG. 8 is an isometric view of a well casing having dual multi-stage
propped fractures
with downhole steam, solvent, and diluent gas injection for a continuous steam
injection system.
DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT
[00037] Several embodiments of the present invention are described below and
illustrated in
the accompanying drawings. The present invention is a method and apparatus for
enhanced
recovery of petroleum fluids from the subsurface by injection of steam and a
hydrocarbon
vaporized solvent in contact with the oil sand formation and the heavy oil and
bitumen in situ.
Multiple propped hydraulic fractures are constructed from the well bore into
the oil sand
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formation and filled with a highly permeable proppant. Steam, a hydrocarbon
solvent, and a
non-condensing diluent gas are injected into the well bore and the propped
fractures. The
injected gas flows upwards and outwards in the propped fractures contacting
the oil sands and in
situ bitumen on the vertical faces of the propped fractures. The steam
condenses on the cool
bitumen and thus heats the bitumen by conduction, while the hydrocarbon
solvent vapors diffuse
into the bitumen from the vertical faces of the propped fractures. The bitumen
softens and flows
by gravity to the well bore, exposing fresh surface of bitumen for the process
to progressively
soften and mobilize the bitumen in a predominantly circumferential, i.e.
orthogonal to the
propped fracture, diffusion direction at a nearly uniform rate into the oil
sand deposit. The
produced product of oil and dissolved solvent is pumped to the surface where
the solvent can be
recycled for further injection.
[00038] Referring to the drawings, in which like numerals indicate like
elements, FIGS. 1 and
2 illustrate the initial setup of the method and apparatus for forming either
an in situ cyclic
pressure pulsed or continuous injection of steam, solvent, and diluent into
the oil sand deposit
and for the extraction of the processed hydrocarbons. Conventional bore hole 5
is completed by
wash rotary or cable tool methods into the formation 8 to a predetermined
depth 7 below the
ground surface 6. Injection casing 1 is installed to the predetermined depth
7, and the installation
is completed by placement of a grout 4 which completely fills the annular
space between the
outside the injection casing 1 and the bore hole 5. Injection casing 1
consists of four initiation
sections 21, 22, 23, and 24 to produce two fractures one orientated along
plane 2, 2' and one
orientated along plane 3, 3'. Injection casing 1 must be constructed from a
material that can
withstand the pressures that the fracture fluid exerts upon the interior of
the injection casing 1
during the pressurization of the fracture fluid. The grout 4 can be any
conventional material (if
elevated temperatures are contemplated a steam injection casing cementation
system is
preferred) that preserves the spacing between the exterior of the injection
casing 1 and the bore
hole 5 throughout the fracturing procedure, preferably a non-shrink or low
shrink cement based
grout that can withstand the imposed temperature and differential strains.
[00039] The outer surface of the injection casing 1 should be roughened or
manufactured such
that the grout 4 bonds to the injection casing 1 with a minimum strength equal
to the down hole
pressure required to initiate the controlled vertical fracture. The bond
strength of the grout 4 to
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the outside surface of the casing 1 prevents the pressurized fracture fluid
from short circuiting
along the casing-to-grout interface up to the ground surface 6.
[00040] Referring to FIGS. 1, 2, and 3, the injection casing 1 comprises two
fracture dual
winged initiation sections 21, 22, 23, and 24 installed at a predetermined
depth 7 within the bore
hole 5. The winged initiation sections 21, 22, 23, and 24 can be constructed
from the same
material as the injection casing 1. The position below ground surface of the
winged initiation
sections 21, 22, 23, and 24 will depend on the required in situ geometry of
the induced hydraulic
fractures and the reservoir formation properties and recoverable reserves.
[00041] The hydraulic fractures will be initiated and propagated by an oil
based fracturing
fluid consisting of a gel formed as a reaction product of aluminum phosphate
ester and a base,
typically sodium aluminate. The reaction of the ester and base creates a
solution that yields high
viscosity in diesels or moderate to high API gravity hydrocarbons. Gelled
hydrocarbons are
advantageous in water sensitive oil producing formations to avoid formation
damage, that would
otherwise be caused by water based fracturing fluids. Alternatively a water
based fracturing
fluid gel can be used.
[00042] The pumping rate of the fracturing fluid and the viscosity of the
fracturing fluids
needs to be controlled to initiate and propagate the fracture in a controlled
manner in weakly
cemented sediments such as oil sands. The dilation of the casing and grout
imposes a dilation of
the formation that generates an unloading zone in the oil sand, and such
dilation of the formation
reduces the pore pressure in the formation in front of the fracturing tip. The
variables of interest
are v the velocity of the fracturing fluid in the throat of the fracture, i.e.
the fracture propagation
rate, w the width of the fracture at its throat, being the casing dilation at
fracture initiation, and
the viscosity of the fracturing fluid at the shear rate in the fracture
throat. The Reynolds number
is Re=pvw/ . To ensure a repeatable single orientated hydraulic fracture is
formed, the
formation needs to be dilated orthogonal to the intended fracture plane, and
the fracturing fluid
pumping rate needs to be limited so that the Re is less than 100 during
fracture initiation and less
than 250 during fracture propagation. Also if the fracturing fluid can flow
into the dilated zone in
the formation ahead of the fracture and negate the induce pore pressure from
formation dilation
then the fracture will not propagate along the intended azimuth. In order to
ensure that the
fracturing fluid does not negate the pore pressure gradients in front of the
fracture tip, its
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viscosity at fracturing shear rates within the fracture throat of -1-20 sec-1
needs to be greater
than 100 centipoise.
[00043] The fracture fluid forms a highly permeable hydraulic fracture by
placing a proppant
in the fracture to create a highly permeable fracture. Such proppants are
typically clean sand for
large massive hydraulic fracture installations or specialized manufactured
particles (generally
resin coated sand or ceramic in composition) which are designed also to limit
flow back of the
proppant from the fracture into the well bore. The fracture fluid-gel-proppant
mixture is injected
into the formation and carries the proppant to the extremes of the fracture.
Upon propagation of
the fracture to the required latera131 and vertical extent 32, the
predetermined fracture thickness
may need to be increased by utilizing the process of tip screen out or by re-
fracturing the already
induced fractures. The tip screen out process involves modifying the proppant
loading and/or
fracture fluid properties to achieve a proppant bridge at the fracture tip.
The fracture fluid is
further injected after tip screen out, but rather then extending the fracture
laterally or vertically,
the injected fluid widens, i.e. thickens, and fills the fracture from the
fracture tip back to the well
bore.
[00044] Referring to FIG. 3 for the intermittent cyclic pressure pulsed steam,
solvent, and
diluent gas injection system, the casing 1 is washed clean of fracturing
fluids and a screen 25 is
present in the casing as a bottom screen 25 for hydraulic connection from the
casing well bore 1
to the propped fractures 30. A downhole electric pump 17 is placed inside the
casing, connected
to a power and instrumentation cable 18, with downhole packer 19 and drop tube
16 for steam,
solvent, and diluent gas injection, and piping 9 for production of the
produced hydrocarbons to
the surface. The steam, solvent, and diluent gas are injected at just below or
very close to
reservoir ambient pressure through the drop tube 16, through the screen 25 and
into the propped
fractures 30. The steam, solvent, and diluent gas contact the bitumen from the
propped fracture
faces, the steam heats the bitumen and the solvent diffuses into the bitumen.
The mobile oil
from the bitumen includes dissolved solvents and flows by gravity along with
any in place water
as shown by 11, to form a pool of oil 10 which flows 15 into the screen 25 and
13 into the pump,
and is pumped 14 through the tubing 9 to the surface. The pressure of the
injected gas in the
propped fractures drops slightly as the steam condenses and the solvent
diffuses into the
bitumen, and further steam, solvent, and diluent gas is injected through the
drop tube 16 to
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WO 2007/117810 PCT/US2007/063713
continue the cycle of progressively mobilizing the in place bitumen. The
slight cyclic pressure
cycling will encourage the gravity flow of the oil towards the well bore.
[00045] Referring to FIGS. 3 and 4, the injected steam, solvent, and diluent
gas flow as shown
by vectors 12 from the screen 25 into the propped fractures 30 with proppant
shown 34 and
mobilized oil sand zone 35 adjacent to the propped fractures 34. The mobilized
oil sand zone
extends into the bitumen oil sands 36 by diffusive processes 33 due to the
thermal and partial
pressure gradients. The mixture of solvent and produced bitumen results in a
modified
hydrocarbon that flows from the bitumen 36 into the mobilized oil sand zone 35
and the propped
fracture 34. The modified hydrocarbon eventually flows as 11 down to a pool of
oil 10 and as
flow 15 into the lower screen 25 of the well bore. The process zone includes
the propped
hydraulic fractures 30, the mobile zone 35 in the oil sands of the formation,
and the fluid
contained therein. In some cases, the well bore casing 1 may be considered
part of the process
zone when a part of the process for recovering hydrocarbons from the formation
is carried out in
the well casing.
[00046] The mobilized oil sand zone 35 grows circumferentially 33, i.e.
orthogonal to the
propped fractures 30, and becomes larger with time until eventually the
bitumen within the
lateral 31 and vertical 32 extent of the propped fracture system is completely
mobilized by the
injected solvent. Upon growth of the mobilized oil sand zone circumferentially
to the lateral 31
and vertical 32 extent of the propped fractures 30, the contact area of the in
place bitumen
available for steam condensation and solvent diffusion drops dramatically from
eight fracture
surfaces each of an area of lateral extent 31 times vertical extent 32 plus
virtually a cylindrical
shape of area 2a times the lateral and vertical extents 31 and 32, down to a
cylindrical shape of
area 2a times the lateral and vertical extents 31 and 32, i.e. from 8 plus 27E
down to 27E, i.e. a drop
of 65% in surface contact area, assuming vertical growth of the process zone
has been inhibited
by placing a light non-condensing gas in the uppermost portions of the
fractures. At this stage if
the process is continued the growth of the mobile oil zone will become radial,
and the mobilized
oil will need to flow radially from the mobilized oil zone towards the
fractures and well bore. It
is at this stage that the process slows down and economics will determine if
the
injection/production process continues.
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[00047] Another embodiment of the present invention is shown on FIG. 5, for a
continuous
steam, solvent, and diluent gas injection system, consisting of a similar
arrangement of hydraulic
fractures 30, injection casing 1, a bottom screen 25 for hydraulic connection
from the casing well
bore 1 to the propped fractures 30, but also a top screen 26 for connection of
upper portions of
the propped fractures to the casing well bore 1. A downhole electric pump 17
is placed inside
the casing, connected to a power and instrumentation cable 18, with downhole
packer 19 and
drop tube 16 for steam, solvent, and diluent gas injection, and piping 9 for
production of the
produced hydrocarbons to the surface. The steam, solvent, and diluent gas are
injected at just
below or very close to reservoir ambient pressure through the drop tube 16,
through the screen
25 and into the propped fractures 30. The spent tail gas, now devoid or
lowered in solvent
content, flows into the casing well bore 1 through the upper screen 27, with
additional steam,
solvent, and diluent gas injected through the drop pipe 16 and the spent tail
gas removed through
the casing well bore 1. This system involves a continuous injection of steam,
solvent, and
diluent gas, compared to the earlier system which was an intermittent process.
[00048] Another embodiment of the present invention is shown on FIGS. 6 and 7,
consisting
of an injection casing 38 inserted in a bore hole 39 and grouted in place by a
grout 40. The
injection casing 38 consists of eight symmetrical fracture initiation sections
41, 42, 43, 44, 45,
46, 47, and 48 to install a total of four hydraulic fractures on the different
azimuth planes 31, 31',
32, 32', 33, 33', 34, and 34'. The process results in four hydraulic fractures
installed from a
single well bore at different azimuths as shown on FIG. 7. The casing 1 is
washed clean of
fracturing fluids and screen 25 is present in the casing as a bottom screen 25
for hydraulic
connection of the casing well bore 1 to the propped fractures 30. A downhole
electric pump 17
is placed inside the casing, connected to a power and instrumentation cable
18, with downhole
packer 19 and drop tube 16 for steam, solvent, and diluent gas injection, and
piping 9 for
production of the produced hydrocarbons to the surface. The steam, solvent,
and diluent gas are
injected at just below or very close to reservoir ambient pressure through the
drop tube 16,
through the screen 25 and into the propped fractures 30. The steam, solvent,
and diluent gas
contact the bitumen from the propped fracture faces, the steam heats the
bitumen, and the solvent
diffuses into the bitumen. The mobile oil from the bitumen includes dissolved
solvents and
flows by gravity along with any in place water as shown by 11, to form a pool
of oil 10, which
flows 15 into the screen 25 and 13 into the pump, and is pumped 14 through the
tubing 9 to the
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surface. This configuration is for a cyclic pressure pulsed intermittent
injection of steam,
solvent, and diluent gas and could be configured similar to FIG. 5 for
continuous steam, solvent,
and diluent gas injection.
[00049] Another embodiment of the present invention is shown on FIG. 8,
similar to FIG. 5
except that the hydraulic fractures are constructed by a multi-stage process
with various proppant
materials of differing permeability. Multi-stage fracturing involves first
injecting a proppant
material 50 to form a hydraulic fracture 30. Prior to creation of the full
fracture extent, a
different proppant material 51 is injected into the fracture over a reduced
central section of the
well bore 53 to create an area of the hydraulic fracture loaded with the
different proppant
materia151. Similarly the multi-stage fracturing could consist of a third
stage by injecting a third
different proppant material 52. By the appropriate selection of proppants with
differing
permeability, the circulation of the steam and vaporized solvent in the formed
fracture can be
extended laterally a greater distance compared to a hydraulic fracture filled
with a uniform
permeable proppant, as shown earlier in FIG. 5. The proppant materials are
selected so that the
proppant material 50 has the highest proppant permeability, with proppant
material 51 being
lower, and with proppant material 52 having the lowest proppant permeability.
The different
permeability of the proppant materials thus optimizes the lateral extent of
the fluids flowing
within the hydraulic fractures and controls the geometry and propagation rate
of the transfer of
heat and solvent to the oil sand formation. The permeability of the proppant
materials will
typically range from 1 to 100 Darcy for the proppant material 50 in the
fracture zone, i.e.
generally being at least 10 times greater than the oil sand formation
permeability. The proppant
material 51 in fracture zone is selected to be lower than the proppant
material 50 in fracture zone
by at least a factor of 2, and proppant material 52 in fracture zone close to
the well bore casing 1
is selected to be in the milli-Darcy range thus limiting fluid flow in the
fracture zone containing
the proppant material 52.
[00050] 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.
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