U.S. patent application number 13/644556 was filed with the patent office on 2014-04-10 for enhanced hydrocarbon recovery from a single well by electrical resistive heating of multiple inclusions in an oil sand formation.
This patent application is currently assigned to GeoSierra LLC. The applicant listed for this patent is GeoSierra LLC. Invention is credited to Grant Hocking.
Application Number | 20140096951 13/644556 |
Document ID | / |
Family ID | 50431503 |
Filed Date | 2014-04-10 |
United States Patent
Application |
20140096951 |
Kind Code |
A1 |
Hocking; Grant |
April 10, 2014 |
ENHANCED HYDROCARBON RECOVERY FROM A SINGLE WELL BY ELECTRICAL
RESISTIVE HEATING OF MULTIPLE INCLUSIONS IN AN OIL SAND
FORMATION
Abstract
The present invention is a method and apparatus for enhanced
recovery of petroleum fluids from the subsurface by electrical
resistive heating of the oil sand formation and the heavy oil and
bitumen in situ, by electrically energizing vertical inclusion
planes containing electrically conductive proppant. The inclusion
is propagated into a portion of the formation having a Skempton's B
parameter of greater than 0.95 exp(-0.04 p')+0.008 p', where p' is
a mean effective stress in MPa at the depth of the inclusion.
Multiple propped vertical inclusions at various azimuths are
constructed from the well. Electrodes are placed in the well in
electrical contact with the inclusions and an alternating direction
current is passed through the proppant. By electrically resistive
heating of the inclusion, the formation is heated by conduction and
associated hydrocarbon fluids are lowered in viscosity and drain by
gravity back to the well and produced to the surface. By
controlling the reservoir temperature and pressure, a particular
fraction of the in situ hydrocarbon reserve is extracted and water
inflow into the heated zone is minimized.
Inventors: |
Hocking; Grant; (Alpharetta,
GA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
GeoSierra LLC; |
|
|
US |
|
|
Assignee: |
GeoSierra LLC
Alphaaretta
GA
|
Family ID: |
50431503 |
Appl. No.: |
13/644556 |
Filed: |
October 4, 2012 |
Current U.S.
Class: |
166/248 |
Current CPC
Class: |
E21B 43/2401 20130101;
E21B 36/04 20130101 |
Class at
Publication: |
166/248 |
International
Class: |
E21B 43/24 20060101
E21B043/24 |
Claims
1. A method of improving production of hydrocarbons from a
subterranean formation of weakly cemented sediments, the method
comprising the steps of: a) propagating a substantially vertical
first inclusion into the formation in a first preferential
direction from a substantially vertical wellbore intersecting the
formation, wherein the first inclusion is filled with an injected
fluid including electrically conductive proppant particles; b)
passing an electric current through the inclusion by electrodes
placed in the wellbore and heating the formation in a process zone
in the vicinity of the first inclusion; and c) producing the heated
hydrocarbons up the wellbore from the formation.
2. The method of claim 23, wherein the method includes propagating
a plurality of second inclusions initiated from the same wellbore
at progressively shallower depths after the viscosity of the
injected fluid in the immediate lower inclusion has substantially
reduced, wherein the plurality of second inclusions intersect and
coalesce with the inclusion immediately beneath the last of the
second inclusions, and with the electric current passing through
all inclusions.
3. The method of claim 23, wherein the method includes propagating
a plurality of first inclusions at varying azimuths and a plurality
of second inclusions at the same varying azimuths.
4. The method of claim 3, wherein the method includes propagating a
plurality of second inclusions initiated from the same wellbore at
progressively shallower depths after the viscosity of the injected
fluid in the immediately lower inclusion has substantially reduced,
wherein the plurality of second inclusions intersect and coalesce
with the inclusion immediately beneath the last of the second
inclusions on its respective azimuth, and wherein the electric
current passes through all inclusions.
5. The method of claim 1, wherein the proppant particles range in
size from #4 to #100 U.S. mesh and are ceramic beads substantially
coated with an electrically conductive resin.
6. The method of claim 5, wherein the resin is phenol formaldehyde
containing fine graphite particles and is heat hardenable, with
resin present in an amount sufficient to consolidate the proppant,
but insufficient to fill the openings between the proppant.
7. The method of claim 1, wherein the proppant particles of range
in size from #4 to #100 U.S. mesh and are selected from a group of
conductive materials such as metals, melt alloys, metal oxides,
metal salts, metal-containing catalysts, calcined petroleum coke or
graphite beads, green or black silicon carbide, boron carbide or a
mixture thereof.
8. The method of claim 1, wherein the proppant particles ranging in
size from #4 to #100 U.S. mesh and are selected from a group of
non-conductive materials such as ceramics, glass and sands coated
with a conductive layer either being metal, metal oxide, metal
salts, conductive resins or mixtures thereof.
9. The method of claim 1, wherein pressure in a majority of the
heated process zone is held at ambient reservoir pressure by
injecting into the process zone steam, non-condensing gas or a
hydrocarbon solvent in a vaporized state or a mixture thereof.
10. The method of claim 9, wherein the solvent is one of a group of
ethane, propane, butane or a mixture thereof.
11. The method of claim 9, wherein the solvent is mixed with a
diluent gas.
12. The method of claim 11, wherein the diluent gas is
non-condensable under.
13. The method of claim 12, wherein the non-condensable diluent gas
has a lower solubility in the formation than the saturated
hydrocarbon solvent.
14. The method of claim 13, wherein the diluent gas is one of a
group of methane, nitrogen, carbon dioxide, natural gas or a
mixture thereof.
15. The method of claim 1, wherein the method further includes
injecting a hydrogenising gas into the wellbore and thus into the
fluids in the process zone to promote hydrogenation and thermal
cracking reactions for at least a portion of the hydrocarbons in
the process zone.
16. The method of claim 15, wherein the hydrogenising gas consists
of one of the group of H2 and CO or a mixture thereof.
17. The method of claim 15, wherein the method further includes
catalyzing the hydrogenation and thermal cracking reactions of at
least a portion of the hydrocarbons in the process zone.
18. The method of claim 17, wherein a metal-containing catalyst is
used to catalyze said hydrogenation and thermal cracking
reactions.
19. The method of claim 18, wherein the catalyst is contained in a
canister in tubing inside of the wellbore.
20. The method of claim 1, wherein the proppant particles in the
first inclusion includes a catalyst for hydrogenation and thermal
cracking reactions within the process zone.
21. The method of claim 2, wherein the proppant particles placed in
the middle depth inclusions, excluding the uppermost and lowermost
inclusions, have an electrical conductivity that ranges from low to
high as the lateral distance increases of the placed proppant
particles from the wellbore.
22. The method of claim 4, wherein the proppant particles placed in
the middle depth inclusions, excluding the uppermost and lowermost
inclusions, have an electrical conductivity that ranges from low to
high as the lateral distance increases of the placed proppant
particles from the wellbore.
23. The method of claim 1, wherein the method further includes
propagating a substantially vertical second inclusion filled with
the injected fluid including electrically conductive proppant
particles in the same preferential direction as the first
inclusion, wherein the second inclusion is initiated after the
viscosity of the injected fluid in the first inclusion has
substantially reduced and wherein the second inclusion is located
above the first inclusion from the same substantially vertical
wellbore to intersect and coalesce with the first vertical
inclusion in the same formation, and passing an electric current
through the first and second inclusions by the electrodes placed in
the wellbore, and heating the formation in the process zone in the
vicinity of the first and second inclusions.
24. The method of claim 1, wherein a portion of the formation in
which the first inclusion is formed has a Skempton B parameter
greater than 0.95 exp(-0.04 p')+0.008 p', where p' is a mean
effective stress in MPa at the depth of the first inclusion and the
water saturation in the formation pores is greater or equal to
10%.
25. A hydrocarbon production well in a formation of unconsolidated
and weakly cemented sediments having an ambient reservoir pressure
and temperature comprising: a) a substantially vertical bore hole
in the formation to a predetermined depth; b) an injection casing
grouted in the bore hole depth to create a substantially vertical
wellbore, the injection casing being radially expandable by the
introduction of a fluid; c) a vertical first inclusion in the
formation created by the fluid delivered into the injection casing
with sufficient pressure to dilate the injection casing and to
create the first inclusion in the formation, wherein the first
inclusion is filled with the fluid including electrically
conductive proppant particles and wherein the first inclusion is
oriented in the formation in a first preferential direction
extending from and in communication with the substantially vertical
wellbore; and d) electrodes placed in the wellbore for passing an
electric current through the inclusion for heating the formation in
a process zone in the vicinity of the first inclusion and thereby
producing the heated hydrocarbons up the wellbore from the
formation.
26. The production well of claim 25, wherein the production well
further includes a substantially vertical second inclusion filled
with the fluid including electrically conductive proppant particles
in the same preferential direction as the first inclusion but
initiated after the viscosity of the injected fluid in the first
inclusion has substantially reduced and wherein the second
inclusion is located above the first inclusion, wherein the second
inclusion originates from the same substantially vertical wellbore
and intersects and coalesces with the first vertical inclusion in
the same formation and the electrodes pass the electric current
through the first and second inclusions to heat the formation in
the process zone in the vicinity of the first and second
inclusions.
27. The production well of claim 25, wherein a portion of the
formation having the first inclusion has a Skempton B parameter
greater than 0.95 exp(-0.04 p')+0.008 p', where p' is a mean
effective stress in MPa at the depth of the first inclusion and the
water saturation in the formation pores is greater or equal to
10%.
28. The production well of claim 26, wherein the production well
has a plurality of second inclusions initiated from the same
wellbore at progressively shallower depths after the viscosity of
the injected fluid in the immediate lower inclusion has
substantially reduced, wherein the plurality of second inclusions
intersect and coalesce with the inclusion immediately beneath the
last of the second inclusions, and wherein the electrodes pass the
electric current through all inclusions.
29. The production well of claim 26, wherein the production well
has a plurality of first inclusions at varying azimuths and a
plurality of second inclusions at the same varying azimuths.
30. The production well of claim 29, wherein the production well
has a plurality of second inclusions initiated from the same
wellbore at progressively shallower depths after the viscosity of
the injected fluid in the immediately lower inclusion has
substantially reduced, wherein the plurality of second inclusions
intersect and coalesce with the inclusion immediately beneath the
last of the second inclusions on its respective azimuth, and the
electrodes pass the electric current through all inclusions.
31. The production well of claim 25, wherein the proppant particles
ranging in size from #4 to #100 U.S. mesh and are ceramic beads
substantially coated with an electrically conductive resin.
32. The production well of claim 31, wherein the resin is phenol
formaldehyde containing fine graphite particles and is heat
hardenable, with resin present in an amount sufficient to
consolidate the proppant, but insufficient to fill the openings
between the proppant.
33. The production well of claim 25, wherein the proppant particles
range in size from #4 to #100 U.S. mesh and are selected from a
group of conductive materials such as metals, melt alloys, metal
oxides, metal salts, metal-containing catalysts, calcined petroleum
coke or graphite beads, green or black silicon carbide, boron
carbide or a mixture thereof.
34. The production well of claim 25, wherein the proppant particles
range in size from #4 to #100 U.S. mesh are selected from a group
of non-conductive materials such as ceramics, glass and sands
coated with a conductive layer either being metal, metal oxide,
metal salts, conductive resins or mixtures thereof.
35. The production well of claim 25, wherein the production well
includes means for injecting steam, non-condensing gas, or a
hydrocarbon solvent in a vaporized state or a mixture thereof into
the process zone thereby maintaining the pressure in a majority of
the heated process zone at ambient reservoir pressure.
36. The production well of claim 35, wherein the solvent is one of
a group of ethane, propane, butane or a mixture thereof.
37. The production well of claim 35, wherein the solvent is mixed
with a diluent gas.
38. The production well of claim 37, wherein the diluent gas is
non-condensable under process conditions.
39. The production well of claim 38, wherein the non-condensable
diluent gas has a lower solubility in the formation than the
saturated hydrocarbon solvent.
40. The production well of claim 39, wherein the diluent gas is one
of a group of methane, nitrogen, carbon dioxide, natural gas or a
mixture thereof.
41. The production well of claim 25, wherein the production well
further includes means for injecting a hydrogenising gas into the
wellbore and thus into the fluids in the process zone to promote
hydrogenation and thermal cracking reactions for at least a portion
of the hydrocarbons in the process zone.
42. The production well of claim 41, wherein the hydrogenising gas
consists of one of the group of H2 and CO or a mixture thereof.
43. The production well of claim 42, wherein the production well
further includes means for catalyzing the hydrogenation and thermal
cracking reactions of at least a portion of the hydrocarbons in the
process zone.
44. The production well of claim 43, wherein a metal-containing
catalyst is used to catalyze said hydrogenation and thermal
cracking reactions.
45. The production well of claim 44, wherein the catalyst is
contained in a canister in tubing inside of the wellbore
casing.
46. The production well of claim 25, wherein the proppant particles
in the first inclusion includes a catalyst for hydrogenation and
thermal cracking reactions within the process zone.
47. The production well of claim 28, wherein the proppant particles
placed in the middle depth inclusions, excluding the uppermost and
lowermost inclusions, have an electrical conductivity that ranges
from low to high as the lateral distance increases of the placed
proppant particles from the wellbore.
48. The production well of claim 30, wherein the proppant particles
placed in the middle depth inclusions, excluding the uppermost and
lowermost inclusions, have an electrical conductivity that ranges
from low to high as the lateral distance increases of the placed
proppant particles from the wellbore.
Description
TECHNICAL FIELD
[0001] The present invention generally relates to enhanced recovery
of petroleum fluids from the subsurface by electrical resistive
heating of electrically conductive proppant in vertical inclusions,
thereupon heating 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.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 -1,000,000 centipoise. However at elevated temperatures the
bitumen viscosity changes considerably to be .about.350 centipoise
at 1000.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, steam 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 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 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 are 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 Kiazinga et al.
[0013] In situ processes involving down hole 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 down
hole 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 down hole 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 down hole 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 over pressurized conditions are usually imposed to
accelerate 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.
[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 placing
electrically conductive proppant in these planes, and by passing an
electric current through the propped planes, 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
al., 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.
[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
have been observed are 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 in a single
well and in multiple wells by direct electrical resistive heating
of electrically conductive permeable vertical inclusions combined
with steam, gas and/or solvent injection or a mixture 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
[0027] The present invention is a method and apparatus for enhanced
recovery of petroleum fluids from the subsurface by electrical
resistive heating of the oil sand formation and the heavy oil and
bitumen in situ, by electrically energizing vertical inclusion
planes containing electrically conductive proppant. In one
embodiment of this invention, multiple propped vertical inclusions
at various azimuths are constructed from a single well and
propagate into the oil sand formation and filled with a
electrically conductive proppant. Additional vertical inclusions
filled with the same proppant are initiated in the same well at
progressively shallower depths but on azimuth with the lower
propped inclusions, such that they propagate laterally and vertical
into the formation and intersect and coalesce with the lower
inclusions on the same substantially respective azimuth. Electrodes
are placed in the well in electrical contact with the lowermost and
uppermost inclusions and an alternating direction current is passed
through the proppant contained in the inclusions. By electrically
resistive heating of the inclusion, the formation is heated by
conduction and associated hydrocarbon fluids are lowered in
viscosity and drain by gravity back to the well to be produced to
the surface.
[0028] The heating of the formation and in place heavy oil and
bitumen is via heat conduction from the electrically resistive
heated inclusions and is predominantly circumferential, i.e.
orthogonal to the propped vertical inclusions. To limit upward
growth of the process and/or to limit loss of heat by conduction to
overlying formations, a non condensing gas can be injected to
remain in the uppermost portions of the heated process zone.
[0029] Although the present invention contemplates the formation of
vertical propped inclusions which generally extend laterally away
from a vertical or near vertical well penetrating an earth
formation and in a generally vertical plane, those skilled in the
art will recognize that the invention may be carried out in earth
formations wherein the fractures and the well bores can extend in
directions other than vertical.
[0030] Therefore, the present invention provides a method and
apparatus for enhanced recovery of petroleum fluids from the
subsurface by electrically resistive heating propped electrical
conductive permeable inclusions, thereupon heating 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.
[0031] 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
[0032] FIG. 1 is a schematic isometric view of a well system and
associated method embodying principles of the present
invention;
[0033] FIG. 2 is a schematic isometric view of the well system with
a single lower propagating inclusion;
[0034] FIG. 3 is a schematic isometric view of the well system with
an injected single lower inclusion and single upper propagating
inclusion;
[0035] FIG. 4 is a schematic isometric view of the well system
completed with a single lower inclusion, a single upper inclusion,
and a single middle inclusion;
DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT
[0036] 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 electrical resistive
heating of propped vertical inclusions in an oil sand formation,
and thus heating the oil sand formation and the heavy oil and
bitumen in situ by conduction. Multiple propped vertical inclusions
at various azimuths are constructed from the well into the oil sand
formation and filled with a electrically conductive proppant.
Electrodes are placed in the well, and an alternating current
passes through the electrically conductive proppant contained in
the inclusions, thus heating the inclusion by electrical resistive
heating and in turn heating the formation and fluids by thermal
conduction. The low viscosity heated hydrocarbon liquids drain by
gravity and are produced to the surface up the well.
[0037] 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 placing
electrically conductive proppant in these planes, and by passing an
alternating electric current through the propped planes, giving
rise to electrically resistive heating of the proppant, and heating
the formation by thermal conduction 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.
[0038] 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 producing heavy
oil 42 from 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).
[0039] As depicted in FIG. 1, a single vertical 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.
[0040] The casing string 11 has expansion devices 12 and a sump
section 13 interconnected therein. The expansion devices 12 operate
to expand the casing string 11 radially outward and thereby dilate
the formation 14 proximate the devices, in order to initiate
forming of generally vertical and planar inclusions 18, 19
extending outwardly from the wellbore at various azimuths. Suitable
expansion devices for use in the well system 10 are described in
U.S. 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. Other
expansion devices may be used in the well system 10 in keeping with
the principles of the invention.
[0041] Once the devices 12 are operated to expand the casing string
11 radially outward, fluid 22 is forced into the dilated formation
14 to propagate the inclusions 18, 19 into the formation. It is not
necessary for the inclusions 18, 19 to be formed simultaneously or
for all of the lower and upper inclusions to be formed together.
Shown in FIG. 1 is an eight (8) wing inclusion well system 10, with
eight (8) inclusions 18 formed at the lower depth and eight (8)
inclusions 19 constructed at shallower depth. The well system 10
does not necessarily need to consist of eight (8) inclusions at the
same depth orientated at various azimuths, but could consist of
one, two, three, four, five, six or even seven vertical planar
inclusions at various azimuths at the same depth, with such choice
of the number of inclusions constructed depending on the
application, formation type and/or economic benefit.
[0042] Typically, the lower inclusions 18 are constructed first,
with each wing of the eight (8) inclusions 18 injected
independently of the others. Following completion of the lower
inclusions 18, the upper inclusions 19 are injected, and these
inclusions 19 intersect and coalesce with their respective on
azimuth lower inclusions 18. The lower inclusions 18 act as a pore
pressure sink during injection of the upper inclusions 19, and thus
ensure the upper inclusions 19 intersect and coalesce with their
own azimuth respective lower inclusion 18. The well system 10 is
shown with inclusions 18, 19 constructed at only two depths, this
well system 10 is cited as only one example of the invention, since
there could be alternate forms of the invention containing numerous
of upper inclusions constructed at progressively shallower depths,
depending on the thickness of the formation 14, the distribution of
hydrocarbons within the formation 14, and/or economic benefit.
[0043] The injected fluid 22 carries the proppant to the extremes
of the inclusions 18, 19. Upon propagation of the inclusions 18, 19
to their required lateral and vertical extent, the thickness of the
inclusions 18, 19 may need to be increased by utilizing the process
of tip screen out. The tip screen out process involves modifying
the proppant loading and/or inject fluid 22 properties to achieve a
proppant bridge at the inclusion tips. The injected fluid 22 is
further injected after tip screen out, but rather then extending
the inclusion laterally or vertically, the injected fluid 22
widens, i.e. thickens, and fills the inclusion from the inclusion
tips back to the well bore.
[0044] 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 and
on the specific gravity and size distribution of the proppant 20.
For example, the viscosity of the injected fluid 22 is preferably
greater than approximately 100 centipoise. However, if foamed fluid
is used, a greater range of viscosity and injection rate may be
permitted while still maintaining directional and geometric control
over the inclusions. The viscosity and volumetric rate of the
injected fluid 22 need to be sufficient to transport the
electrically conductive 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 ceramic beads coated with a electrically conductive
resin, of which one particularly suitable conductive resin
comprises phenol formaldehyde containing fine graphite particles.
Such a resin is heat hardenable at temperatures of around
60.degree. C. or higher, thus capable of mechanically binding the
proppant together 21 without loss of permeability of the propped
inclusion.
[0045] The well system 10 has electrodes 33, 34 placed inside of
the casing and in electrical contact with the conductive proppant
20. These electrodes 33, 34 are connected via insulated cables 31,
32 to an alternating direction current power source 30. Upon
energizing the electrical power source 30, current passes through
the proppant 20 in the inclusions 18, 19 and by electrical
resistive heating raises the temperature of the proppant 20 in the
inclusions 18, 19. At elevated temperature the conductive resin
heat hardens to bind the proppant particles together at their
contacts 21, without impacting the proppant pack permeability of
the inclusions 18, 19. The resistive heat propagates
circumferentially from the inclusions 18, 19 and conductively heats
the formation 14 and its associated fluids. Heated heavy oil and
bitumen will thus be mobilized and flow under gravity towards the
well and enter the sump 13 and pumped to surface via a PCP
(progressive cavity pump), ESP (electrical submersible pump), gas
lift or natural lift 41, depending on operating temperatures,
pressures and depth, via a production tubing 40.
[0046] 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, and the presence of
nearby water bodies. The process can be operated at a low
temperature range of .about.100.degree. C. for a heavy oil rich oil
sand deposit and at a moderate temperature range of
.about.150.degree.-180.degree. C. for a bitumen rich oil sand
deposit, basically to reduce the heavy oil and bitumen viscosity
and thus mobilized the in place oil. However, the process can be
operated at much higher temperatures >270.degree. C. to
pyrolysis the in place hydrocarbon in the presence of H.sub.2, CO
and/or catalysts. Thus the proppant could contain such catalysts,
or these catalysts could be incorporated into a canister in line
with the production tubing in the well. Such catalysts are
available as HDS (hydrodesulfurization) metal containing catalysts,
and FCC (fluid catalytic cracking) rare earth aluminum silica
catalysts.
[0047] 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 by the injection of
steam, gas or vaporized solvent. 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 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.
[0048] 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.
[0049] 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.
[0050] 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.
[0051] 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.
[0052] 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.
[0053] 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.
[0054] 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).
[0055] 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.
[0056] For use of the system 10 and method in weakly cemented
sediments, preferably the Skempton B parameter is as follows with
p' in MPa:
B>0.95 exp(-0.04p')+0.008p' (3)
The system and associated method are applicable to formations of
weakly cemented sediments (such as tight gas sands, mudstones and
shales) where large intensive 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 and resulting in less drag on
fines in the formation, resulting in reduced flow of formation
fines into the wellbore.
[0057] 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. Electrically conductive proppant can consist of metal
coated ceramics, metal proppant, calcined petroleum coke, graphite
beads, green or black silicon carbide, boron carbide, metal fiber,
shaving or platelets, or non-conductive sands, glass or ceramics
with electrically conductive resin or metal coating, or a mixture
thereof to achieve the desired electrical conductivity,
permeability and also to limit flow back of the proppant from the
propped inclusion into the well bore during production of the
hydrocarbons from the formation. The permeability of the propped
inclusions 18, 19 will typically be orders of magnitude greater
than the formation 14 permeability, generally at least by two
orders of magnitude. As regards the electrical conductivity of the
propped inclusions 18, 19, the electrical conductivity needs to be
greater than the formation 14 electrical conductivity, but not too
great whereas electric energy is lost by excessive short-circuiting
between the electrodes, but an optimum value to achieve optimum,
efficient and economical resistive heating of the inclusions 18,
19.
[0058] 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
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.
[0059] An enlarged scale isometric view of the system 10 is
representatively illustrated in FIG. 2. This view depicts the
system 10 during the propagation of only one of the lowermost
inclusions 18, to provide a clearer description of the process used
to construct the system 10. The viscous fluid propagation process
in these sediments involves the unloading of the formation 14 in
the vicinity of the tips 23, 24, 25 of the propagating viscous
fluid 22, causing dilation of the formation 14, which generates
pore pressure gradients towards this dilating zone. As the
formation 14 dilates at the tips 23, 24, 25 of the advancing
viscous fluid 22, the pore pressure decreases dramatically at the
tips, resulting in increased pore pressure gradients surrounding
the tips.
[0060] The pore pressure gradients at the tips 23, 24, 25 of the
inclusion 18 result in the liquefaction, cavitation (degassing) or
fluidization of the formation 14 immediately surrounding the tips.
That is, the formation 14 in the dilating zone about the tips 23,
24, 25 acts like a fluid since its strength, fabric and in situ
stresses have been destroyed by the fluidizing process, and this
fluidized zone in the formation immediately ahead of the viscous
fluid 22 propagating tips 23, 24, 25 is a planar path of least
resistance for the viscous fluid to propagate further. In at least
this manner, the system 10 and associated method provide for
directional and geometric control over the advancing inclusions
18.
[0061] The behavioral characteristics of the injected viscous fluid
22 are preferably controlled to ensure the propagating viscous
fluid does not overrun the fluidized zone and lead to a loss of
control of the propagating process. Thus, the viscosity of the
fluid 22 and the volumetric rate of injection of the fluid should
be controlled to ensure that the conditions described above persist
while the inclusions 18 are being propagated through the formation
14. The propagation rate of the inclusion 18 due to the injected
fluid 22, varies depending on direction, in general due to
gravitation effects, the lateral tip 23 propagation rate is
generally much greater than the upward tip 24 propagation rate and
the downward tip 25 propagation rate. However, these tips 23, 24,
25 propagation rates can change due to heterogeneities in the
formation 14, pore pressure gradients especially associated with
pore pressure sinks, and stress, stiffness and strength contrasts
in the formation 14.
[0062] Referring further to an enlarged scale isometric view of the
system 10 is representatively illustrated in FIG. 3. This view
depicts the system 10 during the propagation of only one of the
uppermost inclusions 19, to provide a clearer description of the
process used to construct the system 10. The lowermost inclusion 18
has been constructed to its final dimension, and the fluid within
the inclusion 18 has lost its viscosity due to breakers placed in
the injected fluid 22. Common breakers consist of enzymes,
catalyzed oxidizers, and organic acids. The formation 14, pore
space may contain a significant portion of immobile heavy oil or
bitumen generally up to a maximum oil saturation of 90%; however,
even at these very high oil saturations of 90%, i.e. very low water
saturation of 10%, the mobility of the formation pore water is
quite high, due to its viscosity and the formation permeability.
Thus during propagation of the uppermost inclusion 19, and provided
the lowermost inclusion pore fluid's viscosity is low due to the
action of the breaker, then the lowermost inclusion 18 acts a large
pore pressure sink, due to size, relative permeability to the
formation, mobility of its and the formation's pore fluids.
[0063] During propagation of the uppermost inclusion 19, the pore
pressure in the overall formation will rise due to the injection of
the fluid 22. The lowermost inclusion 18 will act as a pore
pressure sink and thus attract and accelerate the downward
propagating tip 28, and ensure that the propagating uppermost
inclusion 19 intersects and coalesces with the lowermost inclusion
18, even if there are slight discrepancies in their respective
azimuthal orientations. Upon coalescence of the downward
propagating tip 28 with the lowermost inclusion 18, the tip 28 will
stop propagating in the area of coalescence due to leak off of the
injected fluid 22 to the highly permeable pore pressure sink,
inclusion 18. At completion of the injection of fluid 22 in
inclusions 19, the system 10 configuration will contain continuous
vertical coalescence of inclusions 18 with its respective on
azimuth inclusions 19.
[0064] Referring further to an enlarged scale isometric view of the
system 10 is representatively illustrated in FIG. 4. This view
depicts an alternate configuration of the well system 10 with
successively numerous more upper inclusions 19 installed a
successively shallower depths. The uppermost inclusions are labeled
19, while inclusions installed at greater depth are designated as
19', while the lowermost depth inclusions are labeled as 18. During
the latter stages of the injection of the injected fluid 22 during
construction of middle depth level inclusions 19', the proppant 20
carried by the injected fluid 22 has lower electrical conductivity
than that proppant 20 generally used during inclusion construction,
resulting in a grading of proppant and thus inclusion electrical
conductivity with lateral distance from the well, denoted as a zone
19''. The electrical conductivity of the proppant in zone 19'' will
be lowest near the well and greatest further from the well. The
resultant configuration of the system 10 will extend further
laterally from the well the electrical resistive heating impact of
the system 10 and yield a more efficient and economical system.
[0065] 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.
* * * * *