U.S. patent application number 13/658869 was filed with the patent office on 2014-04-24 for inclusion propagation by casing expansion giving rise to formation dilation and extension.
The applicant listed for this patent is GeoSierra LLC. Invention is credited to Grant Hocking.
Application Number | 20140110118 13/658869 |
Document ID | / |
Family ID | 50484294 |
Filed Date | 2014-04-24 |
United States Patent
Application |
20140110118 |
Kind Code |
A1 |
Hocking; Grant |
April 24, 2014 |
INCLUSION PROPAGATION BY CASING EXPANSION GIVING RISE TO FORMATION
DILATION AND EXTENSION
Abstract
The present invention is a method and apparatus for enhanced
recovery of petroleum fluids from the subsurface by initiating and
propagating vertical permeable inclusions in a plane substantially
orthogonal to the borehole axis. These inclusions containing
proppant are thus highly permeable and enhance drainage of heavy
oil from the formation, and also by steam injection into these
planes, enhance oil recovery by heating the oil sand formation, the
heavy oil and bitumen, which will drain under gravity and be
produced. Multiple propped vertical inclusions are constructed at
various locations along a substantially horizontal wellbore by
dilation of the formation in the plane of the intended inclusion by
radial expansion and axial extension of the formation by an
expanding packer system that expands both radially and axially. In
another embodiment of the invention, the expansion device is part
of a casing string or liner and is in contact with the formation by
a swellable elastomer, or by a cement or polymer based grout. The
expansion device is expanded by an inflatable packer and the device
expands both radially outward and extensionally in the axial
direction, giving rise to a dilated extensional plane in the
formation which is substantially orthogonal to the well bore axis.
Injected fluid propagates preferentially in this dilated and
extensional plane within the formation.
Inventors: |
Hocking; Grant; (Alpharetta,
GA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
GeoSierra LLC |
Alpharetta |
GA |
US |
|
|
Family ID: |
50484294 |
Appl. No.: |
13/658869 |
Filed: |
October 24, 2012 |
Current U.S.
Class: |
166/305.1 |
Current CPC
Class: |
E21B 43/26 20130101 |
Class at
Publication: |
166/305.1 |
International
Class: |
E21B 43/26 20060101
E21B043/26 |
Claims
1. A method of forming at least one inclusion in a subterranean
formation, the method comprising the steps of: installing an
expansion control device in a wellbore with a well casing;
expanding the device both radially outward and axially in extension
in the wellbore, and inject fluid into the formation.
2. The method of claim 1, wherein the expansion control device
includes dual inflation packers placed in an open wellbore.
3. The method of claim 1, wherein the expansion control device
includes an expansion casing segment interconnected to the well
casing, with the expansion casing segment in contact with the
formation.
4. The method of claim 3, wherein the expansion casing segment is
in contact with the formation by placing an infill material between
the casing segment and the formation before the expansion step.
5. The method of claim 4, wherein the infill material is a
swellable elastomer.
6. The method of claim 4, wherein the infill material is a cement
based grout.
7. The method of claim 4, wherein the infill material is a polymer
based grout.
8. The method of claim 3, wherein the expansion casing segment is
expanded by an inflatable packer.
9. The method of claim 3, wherein the expansion step of the casing
segment includes widening of at least one axially aligned opening
in a sidewall of the casing section, and widening at least one
circumferentially aligned opening in the sidewall of the casing
section, displacing latch members in circumferential and axial
directions respectively, the widening being a first direction; and
preventing a narrowing of the openings after the expansion step,
the latch members resisting displacement thereof in a second
narrowing direction opposite to the first widening direction.
10. (canceled)
11. The method of claim 9, wherein the expansion step further
comprises limiting a width of the axial and circumferential
openings.
12. The method of claim 11, wherein the width limiting step
includes engaging a stop member with a shoulder, and further
comprising the step of integrally forming the stop member and latch
member.
13. The method of claim 11, wherein the width limiting step
includes yielding a strain hardening latch member.
14. The method of claim 9, wherein the latch member is attached to
the casing section on a first side of the opening, and wherein at
least one shoulder is attached to the casing section on a second
side of the opening opposite from the first side of the
opening.
15. The method of claim 11, wherein the resisting displacement step
further comprises the latch member engaging the shoulder.
16. The method of claim 15, wherein the shoulder is formed adjacent
at least one aperture in the expansion control device for each
opening, and wherein the-expansion step further comprises drawing
the latch member through the aperture.
17. The method of claim 15, wherein the shoulder is formed on an
abutment structure of the expansion control device attached to the
casing section.
18. The method of claim 17, wherein the abutment structure includes
multiple shoulders and apertures extending longitudinally along and
circumferentially around the casing section.
19. The method of claim 18, wherein the expansion control device
includes multiple latch members configured for engagement with the
multiple shoulders.
20. The method of claim 9, wherein the expansion step further
comprises forming the openings by parting the casing section
sidewall along at least one axial and one circumferential slot
formed in the sidewall, and wherein the slot extends only partially
through the casing section sidewall.
21. The method of claim 9, wherein the expansion step further
comprises forming the openings by parting the casing section
sidewall along at least one axial and one circumferential slot
formed in the sidewall, and wherein the slot extends completely
through the casing section sidewall.
22. The method of claim 21, further comprising a separate strip of
material extending across the slot, and wherein the expansion step
further comprises parting the strip.
Description
TECHNICAL FIELD
[0001] The present invention generally relates to enhanced recovery
of petroleum fluids from the subsurface by initiating and
propagating vertical permeable inclusions in a plane substantially
orthogonal to the borehole axis. These inclusions containing
proppant are thus highly permeable and enhance drainage of heavy
oil from the formation, and also by steam injection into these
planes, enhance oil recovery by heating the oil sand formation, the
heavy oil and bitumen, which will drain under gravity and be
produced. Multiple propped vertical inclusions are constructed at
various locations along a substantially horizontal wellbore by
dilation of the formation in the plane of the intended inclusion by
radial expansion and axial extension of the formation. This dilated
and extensional plane within the formation provides a preferential
pathway for injected fluid to propagate in the formation.
BACKGROUND OF THE INVENTION
[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.degree. API gravity) deposits
are found largely in unconsolidated sandstones, being high porosity
permeable cohensionless sands with minimal grain to grain
cementation. The hydrocarbons are extracted from the oils sands
either by mining or in situ methods.
[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 or oil sands, bitumen and
heavy oil, these terms will be used interchangeably herein. The oil
sand deposits in Alberta, Canada extend over many square miles and
vary in thickness up to hundreds of feet thick. Although some of
these deposits lie close to the surface and are suitable for
surface mining, the majority of the deposits are at depth ranging
from a shallow depth of 150 feet down to several thousands of feet
below ground surface. The oil sands located at these depths
constitute some of the world's largest presently known petroleum
deposits. The oil sands contain a viscous hydrocarbon material,
commonly referred to as bitumen, in an amount that ranges up to 15%
by weight. Bitumen is effectively immobile at typical reservoir
temperatures. For example at 15.degree. C., bitumen has a viscosity
of .about.1,000,000 centipoise. However at elevated temperatures
the bitumen viscosity changes considerably to be .about.350
centipoise at 100.degree. C. down to .about.10 centipoise at
180.degree. C. The oil sand deposits have an inherently high
permeability ranging from .about.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.degree.-5.degree. 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.degree. C. compared to
ambient reservoir temperatures of .about.15.degree. 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, steamflood
using injector wells for steam injection and producer wells on 5
and 9 point layout for vertical wells and combinations of vertical
and horizontal wells, SAGD (steam assisted gravity drainage) steam
injection and gravity production of heated hydrocarbons using two
horizontal wells, VAPEX (vapor assisted petroleum extraction)
solvent vapor injection and gravity production of diluted
hydrocarbons using horizontal wells, and combinations of these
methods.
[0006] Cyclic steam stimulation and steamflood hydrocarbon enhanced
recovery methods have been utilized worldwide, beginning in 1956
with the discovery of CSS, huff and puff or steam-soak in Mene
Grande field in Venezuela and for steamflood in the early 1960s in
the Kern River field in California. These steam assisted
hydrocarbon recovery methods including a combination of steam and
solvent are described in U.S. Pat. No. 3,739,852 to Woods et al,
U.S. Pat. No. 4,280,559 to Best, U.S. Pat. No. 4,519,454 to
McMillen, U.S. Pat. No. 4,697,642 to Vogel, and U.S. Pat. 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 in U.S. Pat. No. 4,344,485 to Butler, and U.S. Pat. No.
5,215,146 to Sanchez and thermal extraction methods in U.S. Pat.
No. 4,085,803 to Butler, U.S. Pat. No. 4,099,570 to Vandergrift,
and U.S. Pat. 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 heat and
hydrogenate the heavy oils insitu in the presence of a metal
catalyst. See U.S. Pat. No. 3,994,340 to Anderson et al., U.S. Pat.
No. 4,696,345 to Hsueh, U.S. Pat. No. 4,706,751 to Gondouin, U.S.
Pat. No. 5,054,551 to Duerksen, and U.S. Pat. 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.
[0010] Solvents applied to the bitumen soften the bitumen and
reduce its viscosity and provide a non-thermal mechanism to improve
the bitumen mobility. Hydrocarbon solvents consist of vaporized
light hydrocarbons such as ethane, propane or butane or liquid
solvents such as pipeline diluents, natural condensate streams or
fractions of synthetic crudes. The diluent can be added to steam
and flashed to a vapor state or be maintained as a liquid at
elevated temperature and pressure, depending on the particular
diluent composition. While in contact with the bitumen, the
saturated solvent vapor dissolves into the bitumen. This diffusion
process is due to the partial pressure difference in the saturated
solvent vapor and the bitumen. As a result of the diffusion of the
solvent into the bitumen, the oil in the bitumen becomes diluted
and mobile and will flow under gravity. The resultant mobile oil
may be deasphalted by the condensed solvent, leaving the heavy
asphaltenes behind within the oil sand pore space with little loss
of inherent fluid mobility in the oil sands due to the small weight
percent (5-15%) of the asphaltene fraction to the original oil in
place. Deasphalting the oil from the oil sands produces a high
grade quality product by 3.degree.-5.degree. 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.degree. C. compared to ambient reservoir
temperatures of .about.15.degree. C.
[0011] Solvent assisted recovery of hydrocarbons in continuous and
cyclic modes is described including the VAPEX process and
combinations of steam and solvent plus heat. See U.S. Pat. No.
4,450,913 to Allen et al, U.S. Pat. No. 4,513,819 to Islip et al,
U.S. Pat. No. 5,407,009 to Butler et al, U.S. Pat. No. 5,607,016 to
Butler, U.S. Pat. No. 5,899,274 to Frauenfeld et al, U.S. Pat. No.
6,318,464 to Mokrys, U.S. Pat. No. 6,769,486 to Lim et al, and U.S.
Pat. 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.
[0012] Direct heating and electrical heating methods for enhanced
recovery of hydrocarbons from oil sands and oil shales have been
disclosed in combination with steam, hydrogen, catalysts and/or
solvent injection at temperatures to ensure the petroleum fluids
gravity drain from the formation and at significantly higher
temperatures (300.degree. to 400.degree. range and above) to
pyrolysis the oil shales. See U.S. Pat. No. 2,780,450 to
Ljungstrom, U.S. Pat. No. 4,597,441 to Ware et al, U.S. Pat. No.
4,926,941 to Glandt et al, U.S. Pat. No. 5,046,559 to Glandt, U.S.
Pat. No. 5,060,726 to Glandt et al, U.S. Pat. No. 5,297,626 to
Vinegar et al, U.S. Pat. No. 5,392,854 to Vinegar et al, U.S. Pat.
No. 6,722,431 to Karanikas et al. In situ combustion processes have
also been disclosed see U.S. Pat. No. 5,211,230 to Ostapovich et
al, U.S. Pat. No. 5,339,897 to Leaute, U.S. Pat. No. 5,413,224 to
Laali, and U.S. Pat. No. 5,954,946 to Klazing a et al.
[0013] In situ processes involving downhole heaters are described
in U.S. Pat. No. 2,634,961 to Ljungstrom, U.S. Pat. No. 2,732,195
to Ljungstrom, U.S. Pat. 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. Pat. No. 2,548,360 to Germain, U.S. Pat. No. 4,716,960 to
Eastlund et al, U.S. Pat. No. 5,060,287 to Van Egmond, U.S. Pat.
No. 5,065,818 to Van Egmond, U.S. Pat. No. 6,023,554 to Vinegar and
U.S. Pat. No. 6,360,819 to Vinegar. Flameless downhole combustor
heaters are described, see U.S. Pat. No. 5,255,742 to Mikus, U.S.
Pat. No. 5,404,952 to Vinegar et al, U.S. Pat. No. 5,862,858 to
Wellington et al, and U.S. Pat. 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. Pat. No. 6,056,057 to Vinegar et al and U.S. Pat.
No. 6,079,499 to Mikus et al.
[0014] 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. Pat. No. 3,739,852 to Woods et al,
U.S. Pat. No. 5,297,626 to Vinegar et al, and U.S. Pat. No.
5,392,854 to Vinegar et al. Also during initiation of the SAGD
process overpressurized conditions are usually imposed to
accelerate the steam chamber development, followed by a prolonged
period of underpressurized condition to reduce the steam to oil
ratio. Maintaining reservoir pressure during heating of the oil
sands has the significant benefit of minimizing water inflow to the
heated zone and to the well bore.
[0015] Electrical resistive heating of oil shale and oil sand
formations utilizing a hydraulic fracture filled with an
electrically conductive material are described in U.S. Pat. No.
3,137,347 to Parker, involving a horizontal hydraulic fracture
filled with conductive proppant and with the use of two (2) wells
to electrically energizing the fracture and raise the temperature
of the oil shale to pyrolyze the organic matter and produce
hydrocarbon from a third well, in U.S. Pat. No. 5,620,049 to Gipson
et al. with a single well configuration in a hydrocarbon formation
predominantly a vertical fracture filled with conductive
temperature setting resin coated proppant and the electric current
passes through the conductive proppant to a surface ground and the
single well is completed to raise the temperature of the oil
in-situ to reduce its viscosity and produce hydrocarbons from the
same well, in U.S. Pat. No. 6,148,911 to Gipson et al. with a
single well configuration in a gas hydrate formation with
predominantly a horizontal fracture filled with conductive proppant
and the electric current passes through the conductive proppant to
a surface ground, raising the temperature of the formation to
release the methane from the gas hydrates and the single well is
completed for methane production, in U.S. Pat. No. 7,331,385 to
Symington et al. in U.S. Pat. No. 7,631,691 to Symington et al. and
in Canadian Patent No 2,738,873 to Symington et al. all with a
predominantly vertical fracture filled with conductive proppant and
the conductive fracture is electrically energized by contact with
at least two (2) wells or in the case of a single well presumably
through the well and surface ground with the oil shale raised to a
temperature to pyrolyze the organic matter into producible
hydrocarbons, with the electrically conductive fracture composed of
electrically conductive proppant and non-electrically conductive
non-permeable cement. The single well systems described above all
suffer from low efficiency and high energy loss due to the current
passes through a significant distance of the formation from the
conductive fracture to the surface ground. Also the systems with
two or more wellbores do not disclosed how the electrode to
conductive fracture contact will be other than a point contact
resulting in significant energy loss and overheating at such a
contact.
[0016] It is well known that extensive heavy oil reservoirs are
found in formations comprising unconsolidated, weakly cemented
sediments. Unfortunately, the methods currently used for extracting
the heavy oil from these formations have not produced entirely
satisfactory results. Heavy oil is not very mobile in these
formations, and so it would be desirable to be able to form
increased permeability planes in the formations and by injecting
steam or solvents into these planes and/or by direct electrical
resistive heating of the plane, heating the formation and thus
increase the mobility of the heavy oil in the formation and by
drainage through the permeable planes to the wellbore for
production up the well.
[0017] However, techniques used in hard, brittle rock to form
fractures therein are typically not applicable to ductile
formations comprising unconsolidated, weakly cemented sediments.
The method of controlling the azimuth of a vertical hydraulic
planar inclusion in formations of unconsolidated or weakly cemented
soils and sediments by slotting the well bore or installing a
pre-slotted or weakened casing at a predetermined azimuth has been
disclosed. The method disclosed that a vertical hydraulic planar
inclusion can be propagated at a pre-determined azimuth in
unconsolidated or weakly cemented sediments and that multiple
orientated vertical hydraulic planar inclusions at differing
azimuths from a single well bore can be initiated and propagated
for the enhancement of petroleum fluid production from the
formation. See U.S. Pat. No. 6,216,783 to Hocking et al, U.S. Pat.
No. 6,443,227 to Hocking et al, U.S. Pat. No. 6,991,037 to Hocking,
U.S. Pat. No. 7,404,441 to Hocking, U.S. Pat. No. 7,640,975 to
Cavender et al., U.S. Pat. No. 7,640,982 to Schultz et al., U.S.
Pat. No. 7,748,458 to Hocking, U.S. Pat. No. 7,814,978 to Steele et
U.S. Pat. No. 7,832,477 to Cavender et al., U.S. Pat. No. 7,866,395
to Hocking, U.S. Pat. No. 7,950,456 to Cavender et al., U.S. Pat.
No. 8,151,874 to Schultz et al. The method disclosed that a
vertical hydraulic planar inclusion can be propagated at a
pre-determined azimuth in unconsolidated or weakly cemented
sediments and that multiple orientated vertical hydraulic planar
inclusions at differing azimuths from a single well bore can be
initiated and propagated for the enhancement of petroleum fluid
production from the formation. It is now known that unconsolidated
or weakly cemented sediments behave substantially different from
brittle rocks from which most of the hydraulic fracturing
experience is founded. The above methods cited, disclose a method
to create a planar inclusion that is parallel to the borehole axis,
and these methods do not disclose how such an inclusion can be
initiated and propagated orthogonal to the borehole axis.
[0018] The methods disclosed above find especially beneficial
application in ductile rock formations made up of unconsolidated or
weakly cemented sediments, in which it is typically very difficult
to obtain directional or geometric control over inclusions as they
are being formed. Weakly cemented sediments are primarily
frictional materials since they have minimal cohesive strength. An
uncemented sand having no inherent cohesive strength (i.e., no
cement bonding holding the sand grains together) cannot contain a
stable crack within its structure and cannot undergo brittle
fracture. Such materials are categorized as frictional materials
which fail under shear stress, whereas brittle cohesive materials,
such as strong rocks, fail under normal stress.
[0019] The term "cohesion" is used in the art to describe the
strength of a material at zero effective mean stress. Weakly
cemented materials may appear to have some apparent cohesion due to
suction or negative pore pressures created by capillary attraction
in fine grained sediment, with the sediment being only partially
saturated. These suction pressures hold the grains together at low
effective stresses and, thus, are often called apparent
cohesion.
[0020] The suction pressures are not true bonding of the sediment's
grains, since the suction pressures would dissipate due to complete
saturation of the sediment. Apparent cohesion is generally such a
small component of strength that it cannot be effectively measured
for strong rocks, and only becomes apparent when testing very
weakly cemented sediments.
[0021] Geological strong materials, such as relatively strong rock,
behave as brittle materials at normal petroleum reservoir depths,
but at great depth (i.e. at very high confining stress) or at
highly elevated temperatures, these rocks can behave like ductile
frictional materials. Unconsolidated sands and weakly cemented
formations behave as ductile frictional materials from shallow to
deep depths, and the behavior of such materials are fundamentally
different from rocks that exhibit brittle fracture behavior.
Ductile frictional materials fail under shear stress and consume
energy due to frictional sliding, rotation and displacement.
[0022] Conventional hydraulic dilation of weakly cemented sediments
is conducted extensively on petroleum reservoirs as a means of sand
control. The procedure is commonly referred to as "Frac-and-Pack."
In a typical operation, the casing is perforated over the formation
interval intended to be fractured and the formation is injected
with a treatment fluid of low gel loading without proppant, in
order to form the desired two winged structure of a fracture. Then,
the proppant loading in the treatment fluid is increased
substantially to yield tip screen-out of the fracture. In this
manner, the fracture tip does not extend further, and the fracture
and perforations are backfilled with proppant.
[0023] The process assumes a two winged fracture is formed as in
conventional brittle hydraulic fracturing. However, such a process
has not been duplicated in the laboratory or in shallow field
trials. In laboratory experiments and shallow field trials what has
been observed is chaotic geometries of the injected fluid, with
many cases evidencing cavity expansion growth of the treatment
fluid around the well and with deformation or compaction of the
host formation.
[0024] Weakly cemented sediments behave like a ductile frictional
material in yield due to the predominantly frictional behavior and
the low cohesion between the grains of the sediment. Such materials
do not "fracture" and, therefore, there is no inherent fracturing
process in these materials as compared to conventional hydraulic
fracturing of strong brittle rocks.
[0025] Linear elastic fracture mechanics is not generally
applicable to the behavior of weakly cemented sediments. The
knowledge base of propagating viscous planar inclusions in weakly
cemented sediments is primarily from recent experience over the
past ten years and much is still not known regarding the process of
viscous fluid propagation in these sediments.
[0026] Accordingly, there is a need for a method and apparatus for
enhancing the extraction of hydrocarbons from oil sands by
constructing vertical planar permeable inclusions with planes that
are orthogonal to the borehole axis and are thus of greater
assistance in enhancing recovery methods such as SAGD. The SAGD
system with such inclusions installed would not require a steam
circulation period to hydraulically connect the injector and
producer wells, since startup in SAGD mode with the permeable
inclusions would be immediate. Also these inclusions would
penetrate horizontal shale layers, which otherwise may be a barrier
to upward steam chamber growth and limit SAGD production and impair
its performance. The vertical permeable inclusions extending
through such shale layers would greatly enhance SAGD performance.
The immediate drainage and increase in effective drainage height
due to the vertical permeable inclusions will also enhance the
productivity and lower the SOR of the SAGD system.
SUMMARY OF THE INVENTION
[0027] The present invention is a method and apparatus for enhanced
recovery of petroleum fluids from the subsurface by initiating and
propagating vertical permeable inclusions in a plane substantially
orthogonal to the borehole axis. These inclusions containing
proppant are thus highly permeable and enhance drainage of heavy
oil from the formation, and also by steam injection into these
planes, enhance oil recovery by heating the oil sand formation, the
heavy oil and bitumen, which will drain under gravity and be
produced. In one embodiment of this invention, multiple propped
vertical inclusions are constructed at various locations along a
substantially horizontal wellbore by dilation of the formation in
the plane of the intended inclusion by radial expansion and axial
extension of the formation by an expanding packer system that
expands both radially and axially. In another embodiment of the
invention, the expansion device is part of a casing string or liner
and is in contact with the formation by a swellable elastomer, or
by a cement or polymer based grout. The expansion device is
expanded by an inflatable packer and the device expands both
radially outward and extensionally in the axial direction, giving
rise to a dilated extensional plane in the formation which is
substantially orthogonal to the well bore axis. Injected fluid
propagates preferentially in this dilated and extensional plane
within the formation. The vertical inclusions are propagated to
intersect and connect with neighboring horizontal wells to
eliminate the non-productive startup phase of SAGD. Also the
inclusion could be filled with an electrically conductive proppant
and fibers and by placing an alternating current through the
inclusions heat the inclusions by electrical resistive heating and
thus heat the oil sand formation.
[0028] Although the present invention contemplates the formation of
vertical propped inclusions which generally extend laterally away
from a substantially near horizontal well penetrating an earth
formation and in a generally vertical plane, those skilled in the
art will recognize that the invention may be carried out in earth
formations wherein the inclusions and the well bores can extend in
directions other than horizontal, and/or that the well bore axis
could vary in orientation and depth along its length.
[0029] 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
[0030] FIG. 1 is a schematic isometric view of a horizontal well
system and associated method embodying principles of the present
invention;
[0031] FIG. 2 is a schematic isometric view of a dual expanding
packer system, that expands both radially and axially;
[0032] FIG. 3 is a schematic isometric view of the casing expansion
device with weakening slots and latches to limit the extent of
opening and inhibit closure;
[0033] FIG. 4 is a schematic isometric view of the casing expansion
device expanded by an inflatable packer.
DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT
[0034] Several embodiments of the present invention are described
below and illustrated in the accompanying drawings. The present
invention involves a method and apparatus for enhanced recovery of
petroleum fluids from the subsurface by construction of propped
vertical inclusions in the oil sand formation from a substantially
horizontal wellbore for enhancing drainage of heavy oil from the
formation and/or to provide a means of injecting steam, thus
heating the oil sand formation and the heavy oil and bitumen in
situ, and at much reduced viscosity the hydrocarbon flow by gravity
drainage to the well and are produced to surface.
[0035] It is well known that extensive heavy oil reservoirs are
found in formations comprising unconsolidated, weakly cemented
sediments. Unfortunately, the methods currently used for extracting
the heavy oil from these formations have not produced entirely
satisfactory results. Heavy oil is not very mobile in these
formations, and so it would be desirable to be able to form highly
permeable planes in the formations and by injecting steam or
solvents into the permeable planes, heating the formation and
in-situ hydrocarbons and thus increase the mobility of the heavy
oil in the formation and by gravity drainage through the permeable
planes to the wellbore for production up the well.
[0036] Representatively illustrated in FIG. 1 is a well system 10
and associated method which embody principles of the present
invention. The system 10 is particularly useful for constructing
permeable planes 18 in a formation 14. The formation 14 may
comprise unconsolidated and/or weakly cemented sediments for which
conventional fracturing operations are not well suited. The term
"heavy oil" is used herein to indicate relatively high viscosity
and high density hydrocarbons, such as bitumen. Heavy oil is
typically not recoverable in its natural state (e.g., without
heating or diluting) via wells, and may be either mined or
recovered via wells through use of steam and solvent injection, in
situ combustion, etc. Gas-free heavy oil generally has a viscosity
of greater than 100 centipoise and a density of less than 20
degrees API gravity (greater than about 900 kilograms/cubic
meter).
[0037] As depicted in FIG. 1, a substantially horizontal well has
been drilled into the formation 14 and the well casing 11 has been
cemented in the formation 14. The term "casing" is used herein to
indicate a protective lining for a wellbore. Any type of protective
lining may be used, including those known to persons skilled in the
art as liner, casing, tubing, etc. Casing may be segmented or
continuous, jointed or unjointed, conductive or non-conductive made
of any material (such as steel, aluminum, polymers, composite
materials, etc.), and may be expanded or unexpanded, etc.
[0038] The horizontal well casing string 11 has expansion devices
12 interconnected therein. The expansion device 12 operates to
expand the casing string 11 radially outward and axially in
extension and thereby dilate the formation 14 proximate the device,
in order to initiate forming of generally vertical and planar
inclusion 18 extending outwardly from the wellbore in a plane
substantially orthogonal to the well axis. Suitable expansion
devices for use in the well system 10 for initiating and
propagating inclusions on planes parallel to the well axis are
described in U.S. Pat. Nos. 6,216,783, 6,330,914, 6,443,227,
6,991,037, 7,404,441, 7,640,975, 7,640,982, 7,748.458, 7,814,978,
7,832,477, 7,866,395, 7,950,456 and 8,151,874. The entire
disclosures of these prior patents are incorporated herein by this
reference. The current invention differs from the earlier cited
disclosures, in that the expansion devices expands both radially
outward and also in extension axially, to develop a dilated
extensional zone in the formation substantially orthogonal to the
wellbore axis. Other expansion devices may be used in the well
system 10 in keeping with the principles of the invention.
[0039] Once the device 12 is operated to expand the casing string
11 radially outward and extensionally axially, fluid 22 is injected
into the dilated formation 14 to propagate the inclusions 18 into
the formation. It is not necessary for the inclusions 18 to be
formed simultaneously. Shown in FIG. 1 are three (3) inclusions 18
in the well system 10, positioned at differing locations along the
well. The well system 10 does not necessarily need to consist of
three (3) inclusions at the same depth orientated at the same
azimuth, but could consist of numerous vertical planar inclusions
at various azimuths at the same depth as would be the case if the
well was curved in plan, with such choice of the number of
inclusions constructed depending on the application, formation type
and/or economic benefit. Also there is only one inclusion shown at
each distinct position along the well; whereas that inclusion could
intersect and coalesce with an inclusion on the same azimuth from a
neighboring well.
[0040] Typically, the inclusions 18 located furthest from the well
head are constructed first, with each inclusion 18 injected
independently as progressed up the well. As the inclusions 18 are
propagated into the formation 14, the inclusions 18 may intersect
and coalesce with previous installed inclusions on similar azimuths
from nearby well. These earlier placed inclusions acts as a pore
pressure sink and thus attract and accelerate the propagation of
the inclusion 18, so as to intersect with the nearby earlier
installed inclusion. The formation 14, pore space may contain a
significant portion of immobile heavy oil or bitumen generally up
to a maximum oil saturation of 90%; however, even at these very
high oil saturations of 90%, i.e. very low water saturation of 10%,
the mobility of the formation pore water is quite high, due to its
viscosity and the formation permeability. The well system 10 is
shown with inclusions 18 constructed at only a single depth, this
well system 10 is cited as only one example of the invention, since
there could be alternate forms of the invention containing numerous
number of inclusions constructed at progressively shallower depths
from shallow wells, depending on the formation thickness, the
distribution of hydrocarbons within the formation 14, and/or
economic benefit.
[0041] The injected fluid 22 carries the proppant to the extremes
of the inclusions 18. Upon propagation of the inclusions 18 to
their required lateral and vertical extent, the thickness of the
inclusions 18 may need to be increased by utilizing the process of
tip screen out. The tip screen out process involves modifying the
proppant loading and/or inject fluid 22 properties to achieve a
proppant bridge at the inclusion tips. The injected fluid 22 is
further injected after tip screen out, but rather then extending
the inclusion laterally or vertically, the injected fluid 22
widens, i.e. thickens, and fills the inclusion from the inclusion
tips back to the well bore.
[0042] The behavioral characteristics of the injected viscous fluid
22 are preferably controlled to ensure the propagating viscous
inclusions maintain their azimuth directionality, such that the
viscosity of the injected fluid 22 and its volumetric rate are
controlled within certain limits depending on the formation 14,
proppant 20 specific gravity and size distribution. For example,
the viscosity of the injected fluid 22 is preferably greater than
approximately 100 centipoise. However, if foamed fluid is used, a
greater range of viscosity and injection rate may be permitted
while still maintaining directional and geometric control over the
inclusions. The viscosity and volumetric rate of the injected fluid
22 need to be sufficient to transport the proppant 20 to the
extremities of the inclusions. The size distribution of the
proppant 20 needs to be matched with that of the formation 14, to
ensure formation fines do not migrate into the propped pack
inclusion during hydrocarbon production. Typical size distribution
of the proppant would range from #12 to #20 U.S. Mesh for oil sand
formations, with an ideal proppant being sand or ceramic beads.
Ceramic beads coated with a resin such as phenol formaldehyde,
being heat hardenable, is capable of mechanically binding the
proppant together 21 in the presence of steam without loss of
permeability of the propped inclusion.
[0043] As depicted in FIG. 2, is one configuration of the well
system 10, with the expansion device 12 consisting of two (2)
inflatable packers 15 lowered into an open wellbore on a tubing
string 13. The inflatable packers are expanded radially outward to
contact the formation 14, then expanded further radially outwards
but also pushed axially apart 15', to place the formation in a
dilation and extensional state in a plane orthogonal to the well
axis. Injected fluids 22 are injected into the formation and
propagate preferentially in this dilated and extensional plane
created by the expansion device 12 and thus form the inclusion
18.
[0044] The formation 14 could be comprised of relatively hard and
brittle rock, but the system 10 and method find especially
beneficial application in ductile rock formations made up of
unconsolidated or weakly cemented sediments, in which it is
typically very difficult to obtain directional or geometric control
over inclusions as they are being formed.
[0045] However, the present disclosure provides information to
enable those skilled in the art of hydraulic fracturing, soil and
rock mechanics to practice a method and system 10 to initiate and
control the propagation of a viscous fluid in weakly cemented
sediments, and importantly for the propagating inclusion to
intersect and coalesce with earlier placed permeable inclusions and
thus form a continuous planar inclusion on a particular azimuth
from within a single well or between multiple wells.
[0046] The system and associated method are applicable to
formations of weakly cemented sediments with low cohesive strength
compared to the vertical overburden stress prevailing at the depth
of interest. Low cohesive strength is defined herein as no greater
than 3 MegaPasca (MPa) plus 0.4 times the mean effective stress
(p') in MPa at the depth of propagation.
c<3 MPa+0.4p' (1)
where c is cohesive strength in MPa and p' is mean effective stress
in the formation.
[0047] Examples of such weakly cemented sediments are sand and
sandstone formations, mudstones, shales, and siltstones, all of
which have inherent low cohesive strength. Critical state soil
mechanics assists in defining when a material is behaving as a
cohesive material capable of brittle fracture or when it behaves
predominantly as a ductile frictional material.
[0048] Weakly cemented sediments are also characterized as having a
soft skeleton structure at low effective mean stress due to the
lack of cohesive bonding between the grains. On the other hand,
hard strong stiff rocks will not substantially decrease in volume
under an increment of load due to an increase in mean stress.
[0049] In the art of poroelasticity, the Skempton B parameter is a
measure of a sediment's characteristic stiffness compared to the
fluid contained within the sediment's pores. The Skempton B
parameter is a measure of the rise in pore pressure in the material
for an incremental rise in mean stress under undrained
conditions.
[0050] In stiff rocks, the rock skeleton takes on the increment of
mean stress and thus the pore pressure does not rise, i.e.,
corresponding to a Skempton B parameter value of at or about 0. But
in a soft soil, the soil skeleton deforms easily under the
increment of mean stress and, thus, the increment of mean stress is
supported by the pore fluid under undrained conditions
(corresponding to a Skempton B parameter of at or about 1).
[0051] The following equations illustrate the relationships between
these parameters in equations denoted as (2) as follows:
.DELTA.u=B.DELTA.p
B=(K.sub.u-K)/(.alpha.K.sub.u)
.alpha.=1-(K/K.sub.s) (2)
where .DELTA.u is the increment of pore pressure, B the Skempton B
parameter, .DELTA.p the increment of mean stress, K.sub.u is the
undrained formation bulk modulus, K the drained formation bulk
modulus, .alpha. is the Biot-Willis poroelastic parameter, and
K.sub.s is the bulk modulus of the formation grains. In the system
and associated method, the bulk modulus K of the formation for
inclusion propagation is preferably less than approximately 5
GPa.
[0052] For use of the system 10 and method in weakly cemented
sediments, preferably the Skempton B parameter is as follows with
p' in MPa:
B>0.95exp(-0.04 p')+0.008p' (3)
The system and associated method are applicable to formations of
weakly cemented sediments (such as tight gas sands, mudstones and
shales) where large entensive propped vertical permeable drainage
planes are desired to intersect thin sand lenses and provide
drainage paths for greater gas production from the formations. In
weakly cemented formations containing heavy oil (viscosity>100
centipoise) or bitumen (extremely high viscosity>100,000
centipoise), generally known as oil sands, propped vertical
permeable drainage planes provide drainage paths for cold
production from these formations, and access for steam, solvents,
oils, and heat to increase the mobility of the petroleum
hydrocarbons and thus aid in the extraction of the hydrocarbons
from the formation. In highly permeable weak sand formations,
permeable drainage planes of large lateral length result in lower
drawdown of the pressure in the reservoir, which reduces the fluid
gradients acting towards the wellbore resulting in less drag on
fines in the formation and resulting in reduced flow of formation
fines into the wellbore.
[0053] Proppant is carried by the injected fluid, resulting in a
highly permeable planar inclusion. Such proppants are typically
clean sand or specialized manufactured particles (generally ceramic
in composition), and depending on the size composition, closure
stress and proppant type, the permeability of the fracture can be
controlled. Either type of proppant could be resin coating to
provide for bounding between proppant particles 21 at elevated
temperatures and also to reduce the steam dissolution of the
particle over time. The permeability of the propped inclusions 18
will typically be orders of magnitude greater than the formation 14
permeability, generally at least by two orders of magnitude.
[0054] The injected fluid 22 varies depending on the application
and can be water, oil or multi-phased based gels. Aqueous based
fracturing fluids consist of a polymeric gelling agent such as
solvatable (or hydratable) polysaccharide, e.g. galactomannan gums,
glycomannan gums and cellulose derivatives. The purpose of the
hydratable polysaccharides is to thicken the aqueous solution and
thus act as viscosifiers, i.e. increase the viscosity by 100 times
or more over the base aqueous solution. A cross-linking agent can
be added which further increases the viscosity of the solution. The
borate ion has been used extensively as a cross-linking agent for
hydrated guar gums and other galactomannans, see U.S. Pat. No.
3,059,909 to Wise. Other suitable cross-linking agents are
chromium, iron, aluminum, and zirconium (see U.S. Pat. No.
3,301,723 to Chrisp) and titanium (see U.S. Pat. No. 3,888,312 to
Tinea of 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.
[0055] An enlarged scale isometric view of the system 10 is
representatively illustrated in FIG. 3. This view depicts another
embodiment of the system 10, consisting of an expansion device 12
that is connected to the casing string 11 and the casing 11 is
either cemented in the wellbore or the expansion device 12 is
coated with a swellable elastomer, swellable in the presence of
water or hydrocarbons or swellable on the application of heat. Such
swellable elastomers are commonly used for the production of
hydrocarbons for a variety of well completion systems. By either
means the expansion device 12 is in contact with the formation 14.
The expansion device 12 could be constructed from a variety of
materials, but a yieldable metal, such as steel is considered a
preferred choice. The expansion device 12 has slots cut through its
thickness in the axial direction as axial slots 31 and in the
circumferential direction as circumferential slots 32. The slots
31, 32 are either machined, or cut by laser or waterjet, are narrow
in width in the range of 0.040'' to 0.080'' and approximately 1''
to 11/2'' in length, depending on the diameter of the expansion
device 12 and the intended application. The slots 31, 32 could be
cut through the entire thickness of the expansion device 12, or
only partial cut through the depth of the expansion device wall
thickness.
[0056] The slots 31, 32 shown consist of three (3) rows of slots
offset from each other both along and orthogonal to the slot
orientation, but could be different multiples of slots depending on
the opening amount required. The axial slots 31 are shown as four
(4) sets of slots 31 being orientated 90.degree. apart. Depending
on the casing diameter and application the axial slots 31 could
consists of any number of sets of slots, e.g. three (3) sets
120.degree. apart or six (6) sets 60.degree. apart. Likewise the
circumferential slots 32 are shown as three (3) sets of slots,
whereas there could be any number of sets of circumferential slots
32, from one (1) set and upwards depending on the required opening,
casing diameter and application. Straps, latches and braces 33, 34,
35, are welded to the expansion device 12 and restrict the amount
of opening of the slots 31, 32 and upon their opening inhibit
closure. The straps, latches or braces could be strips of strain
hardening material, such as stainless steel, that provides for all
the slots to open evenly and inhibit closure of the slots, due to
the stainless steel high strain before failure and its strain
hardening properties. Alternate latches have been cited earlier in
the incorporated references and consist of latches that lock in
place upon a certain amount of opening, inhibit further opening and
hold the slot locked in the open position and inhibit closure of
the slots.
[0057] An enlarged scale isometric view of the system 10 is
representatively illustrated in FIG. 4. This view depicts the
expansion device 12 of the system 10, consisting of a casing string
11 grouted into the formation 14 by cement or in contact with the
formation by a swellable elastomer. A packer 15 connected to tubing
13 is lowered into the well and the packer 15 is set in proximity
to the expansion device 12. The packer 15 is inflated to give rise
to yielding of the slots 31, 32 and activation of the straps,
latches and braces 33, 34, 35, so that the expansion device 12
expands radially outward due to the axial slots 31 but also extends
axially extensionally due to the circumferential slots 32. The
radial expansion and axial extension of the expansion device 12
develops a zone in the formation 14 substantially orthogonal to the
wellbore axis in a dilated and extensional state for the
preferential propagation of injected fluids 22 to propagate in the
formation to form the inclusions 18.
[0058] The pore pressure gradients at the tips of the inclusion 18
result in the liquefaction, cavitation (degassing) or fluidization
of the formation 14 immediately surrounding the tips. That is, the
formation 14 in the dilating zone about the tips acts like a fluid
since its strength, fabric and in situ stresses have been destroyed
by the fluidizing process, and this fluidized zone in the formation
immediately ahead of the viscous fluid 22 propagating tips is a
planar path of least resistance for the viscous fluid to propagate
further. In at least this manner, the system 10 and associated
method provide for directional and geometric control over the
advancing inclusions 18.
[0059] The behavioral characteristics of the injected viscous fluid
22 are preferably controlled to ensure the propagating viscous
fluid does not overrun the fluidized zone and lead to a loss of
control of the propagating process. Thus, the viscosity of the
fluid 22 and the volumetric rate of injection of the fluid should
be controlled to ensure that the conditions described above persist
while the inclusions 18 are being propagated through the formation
14. The propagation rate of the inclusion 18 due to the injected
fluid 22, varies depending on direction, in general due to
gravitation effects, the lateral tip propagation rate is generally
much greater than the upward tip propagation rate and the downward
tip propagation rate. However, these tips propagation rates can
change due to heterogeneities in the formation 14, pore pressure
gradients especially associated with pore pressure sinks, and
stress, stiffness and strength contrasts in the formation 14.
[0060] 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.
* * * * *