Note: Descriptions are shown in the official language in which they were submitted.
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
ENHANCED HYDROCARBON RECOVERY BY
CONVECTIVE HEATING OF OIL SAND FORMATIONS
TECHNICAL FIELD
[0001] The present invention generally relates to enhanced recovery of
petroleum fluids from
the subsurface by convective heating of the oil sand formation and the viscous
heavy oil and
bitumen in situ, more particularly to a method and apparatus to extract a
particular fraction of
the in situ hydrocarbon reserve by controlling the reservoir temperature and
pressure, while
also minimizing water inflow into the heated zone and well bore, resulting in
increased
production of petroleum fluids from the subsurface formation.
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
1
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
deposits. The oil sands contain a viscous hydrocarbon material, commonly
referred to as
bitumen, in an amount that ranges up to 15% by weight. Bitumen is effectively
immobile at
typical reservoir temperatures. For example at 15 C, bitumen has a viscosity
of -1,000,000
centipoise. However, at elevated temperatures the bitumen viscosity changes
considerably to
-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.
[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 assisted gravity drainage) steam injection and
gravity
2
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
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. 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
3
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
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, 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
4
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
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 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.
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
[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.
[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.
6
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
[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 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.
7
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
[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.
SUMMARY OF THE INVENTION
[00022] The present invention is a method and apparatus for enhanced recovery
of
petroleum fluids from the subsurface by convective heating of the oil sand
formation and the
heavy oil and bitumen in situ, by either a downhole heater in the well bore or
heat supplied to
the well bore by a heat transferring fluid from a surface fired heater or
surface burner.
8
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
Multiple propped hydraulic fractures are constructed from the well bore into
the oil sand
formation and filled with a highly permeable proppant. The permeable propped
fractures and
well bore are filled with a diluent and elevated temperatures from the heater
set up thermal
convective cells in the diluent forcing heated diluent to flow upward and
outward in the
propped fractures and circulating back down and back towards the well bore
heating the oil
sands and in situ bitumen on the vertical faces of the propped fractures. The
diluent now
mixed with produced products from the oil sand re-enters the bottom of the
well bore and
passes over the heater element and is reheated to continue to flow in the
convective cell.
Thus the heating and diluting of the in place bitumen is predominantly
circumferential, i.e.
orthogonal to the propped fracture, diffusion from the propped vertical
fracture faces
progressing at a nearly uniform rate into the oil sand deposit. To limit
upward growth of the
process, a non condensing gas can be injected to remain in the uppermost
portions of the
propped fractures.
[00023] The processes active at the contact of the diluent with the bitumen in
the oil sand
are predominantly diffusive, being driven by partial pressure gradients and
thermal gradients,
resulting in the diffusion of diluent components into the bitumen and the
conduction of heat
from the diluent into the bitumen and oil sand formation. Upon softening of
the bitumen, the
oil will become mobile and additional smaller convective cells will developed
providing
better mixing of the diluent in the propped fracture and the every expanded
zone of mobile oil
in the native oil sand formation.
[00024] The diluent would preferably be an on site diluent, light oil, or
natural gas
condensate stream, or a mixture thereof, with its selected composition to
provide a primarily
liquid phase of the diluent in the process zone at the imposed reservoir
temperatures and
pressures. The diluent could be derived from synthetic crude if available. The
prime use of
the diluent is to transfer by convection, heat from the well bore to the
process zone, heat and
dilute the produced product to yield a mixture that will flow readily at the
elevated
temperatures through the oil sands and propped fractures back to the well
bore. 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 diluent,
and the presence of nearby water bodies. The process can be operated at a low
temperature
range of -100 C for a heavy oil rich oil sand deposit and at a moderate
temperature range of
-150 -180 C for a bitumen rich oil sand deposit, basically to reduce the
bitumen viscosity
and thus mobilized the in place oil. However, the process can be operated a
much higher
9
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
temperatures >270 C to pyrolysis the in place hydrocarbon in the presence of
hydrogen
and/or catalysts. The operating pressure of the process may be selected to
closely match the
ambient reservoir conditions to minimize water inflow into the process zone
and the well
bore. However, the process operating conditions may deviate from this pressure
in order to
maintain the diluent and produced mixture in a predominantly liquid state,
i.e. the diluent is
to remain in most part soluble in the produced heavy oil or bitumen at the
operating process
temperatures and pressures.
[00025] To accelerate the process, forced convection by a pump can assist and
transfer
additional heat into the propped fracture convective cells, by pumping the
diluent and
produced product at greater velocities past the heater and into the propped
fractures and
mobile zone within the oil sands.
[00026] During the heating and diluting process in situ, only a small quantity
of the mobile
produced product will be extracted from the subsurface in order to maintain
reservoir
pressures optimum for the process and to maintain a high liquid level in the
process zone,
thus resulting heat transfer occurring at more or less a uniform rate in a
circumferential
direction. Drawing down the pressure for petroleum extraction will result in
gas release from
the mixture filling the upper portion of the process zone as the liquids are
extracted from the
formation. Upon production of the liquid hydrocarbons the gas in the process
zone could be
produced by sweeping the process zone with another gas, or the gas could be re-
pressurized
to reservoir conditions to minimize water inflow into the process zone and the
thermal energy
in the process zone oil sands allowed to conduct radially into the surrounding
cooler oil sands
and thus mobilize additional hydrocarbons (i.e. a heat conductive soak) albeit
at a much
reduced rate than during the active heating phase of the process. Finally the
remaining liquid
hydrocarbons and gas are produced from the oil sand formation after some
extended heat
conductive soak period.
[00027] The prime benefits of the above process are to provide an efficient
low
temperature heating phase to mobilize the hydrocarbon in situ, to produce a
higher grade
petroleum product, and to maintain ambient reservoir pressure conditions and
thus limit water
inflow into the process zone. The disadvantage of the process is that only
minimal quantities
of hydrocarbons are extracted from the subsurface during the active heating
phase of the
process since the majority of the hydrocarbons are produced near the end of
the process.
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
[00028] 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.
[00029] Therefore, the present invention provides a method and apparatus for
enhanced
recovery of petroleum fluids from the subsurface by convective heating of the
oil sand
formation and the viscous heavy oil and bitumen in situ, more particularly to
a method and
apparatus to extract a particular fraction of the in situ hydrocarbon reserve
by controlling the
reservoir temperature and pressure, while also minimizing water inflow into
the heated zone
and well bore resulting in increased production of petroleum fluids from the
subsurface
formation.
[00030] 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
[00031] 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.
[00032] 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.
[00033] FIG. 3 is an isometric view of a well casing having dual propped
fractures with
downhole heater and convection fluid flow shown in the subsurface.
[00034] FIG. 4 is a horizontal cross-sectional side elevation view of a well
casing and
propped fracture with downhole heater and convective fluid flow shown in the
subsurface.
[00035] FIG. 5 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.
[00036] FIG. 6 is an isometric view of a well casing having four propped
fractures with
downhole heater and convection fluid flow shown in the subsurface.
[00037] FIG. 7 is an isometric view of a well casing having dual multi-stage
propped
fractures with downhole heater and convection fluid flow shown in the
subsurface.
11
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT
[00038] 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 convective
heating of the oil
sand formation and the heavy oil and bitumen in situ, by either a downhole
heater in the well
bore or heat supplied to the well bore by a heat transferring fluid from a
surface fired heater
or surface burner. Multiple propped hydraulic fractures are constructed from
the well bore
into the oil sand formation and filled with a highly permeable proppant. The
permeable
propped fractures and well bore are filled with a diluent, the heater and pump
activated with
forced thermal convective flow forcing the heated diluent to flow upward and
outward in the
propped fractures and circulating back down and back towards the well bore
heating the oil
sands and in situ bitumen on the vertical faces of the propped fractures. The
diluent now
mixed with produced products from the oil sand re-enters the bottom of the
well bore and
passes over the heater element and is reheated to continue to flow in the
convective cell. Thus
the heating and diluting of the in place bitumen is predominantly
circumferentially, i.e.
orthogonal to the propped fracture, diffusion from the propped vertical
fracture faces
progressing at a nearly uniform rate into the oil sand deposit. The heated low
viscosity oil is
produced through the well bore at the completion of the active heating phase
of the process.
[00039] Referring to the drawings, in which like numerals indicate like
elements, FIGS. 1,
2, and 3 illustrate the initial setup of the method and apparatus for forming
an in situ forced
convective heating system of 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 used in steam
injection
casing cementation systems 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 high temperature and
differential strains.
12
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
[00040] 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 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.
[00041] 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 fracture and the reservoir formation properties and
recoverable reserves.
[00042] 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. The oil
based gel provides the added advantage of placing the required diluent within
the propped
fracture, without the inherent problems of injecting a diluent into a water
saturated proppant
fracture if water based fracturing fluids were used.
[00043] 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, 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
13
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
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 viscosity at
fracturing shear rates within
the fracture throat of - 1-20 sec-1 needs to be greater than 100 centipoise.
[00044] 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 lateral 31 and
vertical extent 32
(FIG. 3), 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.
[00045] Referring to FIG. 3, the casing 1 is washed clean of fracturing fluids
and screens
25 and 26 are present in the casing as a bottom screen 25 and a top screen 26
for hydraulic
connection from the casing well bore 1 to the propped fractures 30. A downhole
electric
heater 17 is placed inside the casing, with a downhole pump 18, connected to a
power and
instrumentation cable 27, with downhole packers 16 to isolate the top screen
interval from the
remaining sections of the well bore, piping 27, and downhole valve 19. The
heater 17 and
pump 18 are energized through electric power provided from the surface through
cable 27.
The pump and thermal buoyancy effects forces the diluent fluid to flow 13 past
the heater
into 14 the pump 18 and up 15 the tubing 27 and out of the top screen 26. The
downhole
valve 19 in the closed position enables the pumped hot fluid to flow through
the top screen 26
into the fracture and oil sand formation as flow vectors 10, 11, and 12
illustrating the
convection cell formation due to the pumped hot fluid. The surface controlled
downhole
valve 19 in the open position enables the pump fluid to flow only up the
tubing 9 and not into
the top screen 26. The fluid diluent is cooled by the oil sands 8 adjacent to
the propped
fractures 30 as it flows from 10 to I l to 12, and enters the well bore
through the bottom
14
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
screen 25 to be convectively moved 13 up past the heater 17 for a return to
the forced
convective re-circulation cell.
[00046] Referring to FIGS. 3 and 4, the hot diluent flows in a re-circulation
force
convective cell as shown by vectors 10, 11, and 12 in the propped fracture 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 partial pressure and temperature gradients. The mixture of diluent 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 to flow eventually as 12 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.
[00047] 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 elevated temperature and diffused diluent. As the mobilized oil sand
region 35 grows the
diluent fluid 12 entering the lower screen 26 of the well bore becomes a
mixture of mobilized
oil from the bitumen and the original diluent. It may be necessary to dilute
this mixture from
time to time with additional diluent to yield the required viscosity and heat
transfer properties
of the heated fluid in the re-circulation cell. Upon growth of the mobilized
oil sand zone to
the lateral 31 and vertical 32 extents of the propped fractures 30, the valve
19 will be open
and the liquid hydrocarbons produced up the tubing 9 to the surface.
[00048] As the pressure is lowered during hydrocarbon production to the
surface, gases
from the diluent and bitumen mixture will fill the mobilized oil sand region
35 and the
propped fractures 34. Re-pressurizing these gases back to ambient reservoir
pressures will
minimize water inflow into the heated region and an extended heat conduction
soak can
provide additional mobilized hydrocarbons from the oil sands with out
additional heat
required. Alternatively, the process zone can be injected with a vaporized
hydrocarbon
solvent, such as ethane, propane, or butane and mixed with a diluent gas, such
as methane,
nitrogen, and carbon dioxide. The solvent will contact the in situ bitumen at
the edge of the
process zone, diffusive into and soften the bitumen, so that it flows by
gravity to the well
bore. Dissolved solvent and product hydrocarbon are produced and further
solvent and
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
diluent gas injected into the process zone. The elevated temperature of the
process zone will
significantly accelerate the diffusion process of the solvent diffusing into
the bitumen
compared to ambient reservoir conditions. The solvent and diluent gas will be
injected at
near reservoir pressures to minimize water inflow into the process zone. The
solvent vapor in
the injection gas is maintained saturated at or near its dew point at the
process operating
temperatures and pressures.
[00049] During the active heating phase of the process, the reservoir
temperatures and
pressures and composition of the produced fluid will be controlled to optimize
the process as
regards the quality and composition of the produced product, the heat
transfer, and diluent
properties of the produced mixture, and to minimize water inflow into the
process zone and
well bore.
[00050] Another embodiment of the present invention is shown on FIGS. 5 and 6,
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. 6.
The casing 1 is
washed clean of fracturing fluids and screens 25 and 26 are present in the
casing as a bottom
screen 25 and a top screen 26 for hydraulic connection of the well bore 10 to
the propped
fractures 30. A downhole electric heater 17 is placed inside the casing, with
a downhole
pump 18, connected to a power and instrumentation cable 27, with downhole
packers 16 to
isolate the top screen interval from the remaining sections of the well bore,
piping 27, and
downhole valve 19. The heater 17 and pump 18 are energized through electric
power
provided from the surface through cable 27. The pump and thermal buoyancy
effects force
the diluent fluid to flow 13 past the heater into 14 the pump 18 and up 15 the
tubing 27 and
out of the top screen 26. The downhole valve 19 in the closed position enables
the pumped
hot fluid to flow through the top screen 26 into the fracture and oil sand
formation as flow
vectors 10, 11, and 12 illustrating the convection cell formation due to the
pumped hot fluid.
The fluid diluent is cooled by the oil sands 8 adjacent to the propped
fractures 30 as it flows
from 10 to 11 to 12, and enters the well bore through the bottom screen 25 to
be convectively
moved 13 up past the heater 17 for a return to the forced convective re-
circulation cell.
Following the active heater phase of the process, the mobilized hydrocarbons
are produced
16
CA 02648014 2008-09-29
WO 2007/117787 PCT/US2007/063185
from the well bore and heated zone through opening the downhole valve 19 and
transported
by tubing 9 to the surface.
[00051] Another embodiment of the present invention is shown on FIG. 7,
similar to FIG.
3 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 material 51. 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 diluent and mobilized oil
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. 3. The proppant
materials are
selected so that the proppant materia150 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 convective heat 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 the fracture zone by at least a factor of 2, and
proppant material 52 in
the 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 materia152.
[00052] 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.
17
