U.S. patent application number 14/484686 was filed with the patent office on 2016-03-17 for methods of increasing a thermal conductivity and transferring heat within a subterranean formation, and methods of extracting hydrocarbons from the subterranean formation.
The applicant listed for this patent is Baker Hughes Incorporated. Invention is credited to Ashley L. Christian, Fermin Fernandez-Ibanez, Jacob D. Gibson, Jeffrey J. Krimmel, Chun Lan, Bernhard Meyer-Heye.
Application Number | 20160076348 14/484686 |
Document ID | / |
Family ID | 55454259 |
Filed Date | 2016-03-17 |
United States Patent
Application |
20160076348 |
Kind Code |
A1 |
Fernandez-Ibanez; Fermin ;
et al. |
March 17, 2016 |
METHODS OF INCREASING A THERMAL CONDUCTIVITY AND TRANSFERRING HEAT
WITHIN A SUBTERRANEAN FORMATION, AND METHODS OF EXTRACTING
HYDROCARBONS FROM THE SUBTERRANEAN FORMATION
Abstract
A method of increasing a thermal conductivity of a subterranean
formation and a hydrocarbon-containing material comprises
introducing nanoparticles having a high thermal conductivity into
the subterranean formation. The nanoparticles adhere to surfaces of
the hydrocarbon-containing material and increase the thermal
conductivity of the hydrocarbon-containing material. A heating
fluid is injected into the subterranean formation and contacts the
nanoparticles. Heat is transferred to hydrocarbons of the
hydrocarbon-containing material and reduces a viscosity of the
hydrocarbons. Methods of transferring heat to a
hydrocarbon-containing material, as well as methods of recovering
hydrocarbons from a subterranean formation are also disclosed.
Inventors: |
Fernandez-Ibanez; Fermin;
(Houston, TX) ; Christian; Ashley L.; (San
Antonio, TX) ; Lan; Chun; (Katy, TX) ;
Krimmel; Jeffrey J.; (Houston, TX) ; Gibson; Jacob
D.; (Calgary, CA) ; Meyer-Heye; Bernhard;
(Bremen, DE) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Baker Hughes Incorporated |
Houston |
TX |
US |
|
|
Family ID: |
55454259 |
Appl. No.: |
14/484686 |
Filed: |
September 12, 2014 |
Current U.S.
Class: |
166/302 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 43/2406 20130101; E21B 43/24 20130101 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 43/26 20060101 E21B043/26 |
Claims
1. A method for increasing a thermal conductivity of a subterranean
formation, the method comprising: combining nanoparticles with a
carrier fluid to form a suspension; injecting the suspension into a
subterranean formation; adhering the nanoparticles to surfaces and
within pores of the subterranean formation; and heating
hydrocarbon-containing material within the subterranean formation
and at least a portion of the nanoparticles with a heating
fluid.
2. The method of claim 1, further comprising forming fractures
within the subterranean formation prior to injecting the suspension
into a subterranean formation.
3. The method of claim 1, wherein combining nanoparticles with a
carrier fluid to form a suspension comprises forming a suspension
comprising between about 0.0001 weight percent and about 15 weight
percent of the nanoparticles.
4. The method of claim 1, wherein adhering the nanoparticles to
surfaces and within pores of the subterranean formation comprises
attaching nanoparticles having an average size of between about 5
nm and about 1,000 nm to the surfaces and within pores of the
subterranean formation.
5. The method of claim 1, wherein adhering the nanoparticles to
surfaces and within pores of the subterranean formation comprises
contacting the hydrocarbon-containing material with nanoparticles
comprising at least one of single walled carbon nanotubes,
multi-walled carbon nanotubes, graphene, and nanodiamonds.
6. The method of claim 1, wherein combining nanoparticles with a
carrier fluid to form a suspension comprises combining at least
some nanoparticles having at least one functional group configured
to increase a dispersibility of the nanoparticles with the carrier
fluid.
7. The method of claim 1, wherein heating hydrocarbon-containing
material within the subterranean formation and at least a portion
of the nanoparticles with a heating fluid comprises contacting the
hydrocarbon-containing material and at least a portion of the
nanoparticles with at least one of a hot water or a hot brine
solution.
8. The method of claim 1, wherein heating hydrocarbon-containing
material within the subterranean formation and at least a portion
of the nanoparticles with a heating fluid comprises heating the
hydrocarbon-containing material with steam.
9. The method of claim 1, wherein heating hydrocarbon-containing
material within the subterranean formation and at least a portion
of the nanoparticles with a heating fluid comprises contacting the
nanoparticles adhered to the surfaces and within pores of the
subterranean formation with the heating fluid and transferring heat
through the nanoparticles to the hydrocarbon-containing
material.
10. The method of claim 1, wherein heating hydrocarbon-containing
material within the subterranean formation and at least a portion
of the nanoparticles with a heating fluid comprises reducing a
viscosity of hydrocarbons of the hydrocarbon-containing
material.
11. A method of recovering hydrocarbons from a subterranean
formation, the method comprising: introducing a suspension
including at least one of single wall carbon nanotube
nanoparticles, multi-walled carbon nanotube nanoparticles, graphene
nanoparticles, and nanodiamond nanoparticles into a subterranean
formation; contacting surfaces of the subterranean formation and a
hydrocarbon-containing material with the suspension and adhering at
least some of the nanoparticles to surfaces of the subterranean
formation and the hydrocarbon-containing material; contacting at
least some of the nanoparticles with steam; transferring heat from
at least some of the nanoparticles to the subterranean formation
and the hydrocarbon-containing material to reduce a viscosity of
hydrocarbons within the hydrocarbon-containing material; and
transferring the hydrocarbons to a surface of the subterranean
formation.
12. The method of claim 11, wherein introducing a suspension
including at least one of single wall carbon nanotube
nanoparticles, multi-walled carbon nanotube nanoparticles, graphene
nanoparticles, and nanodiamond nanoparticles into a subterranean
formation comprises introducing a suspension comprising at least
one of single wall carbon nanotube nanoparticles, multi-walled
carbon nanotube nanoparticles, graphene nanoparticles, and
nanodiamond nanoparticles and at least another of single wall
carbon nanotube nanoparticles, multi-walled carbon nanotube
nanoparticles, graphene nanoparticles, and nanodiamond
nanoparticles into the subterranean formation.
13. The method of claim 11, wherein introducing a suspension
including at least one of single wall carbon nanotube
nanoparticles, multi-walled carbon nanotube nanoparticles, graphene
nanoparticles, and nanodiamond nanoparticles into a subterranean
formation comprises introducing the suspension into a portion of
the subterranean formation having a lower thermal conductivity than
other portions of the subterranean formation.
14. The method of claim 11, wherein introducing a suspension
including at least one of single wall carbon nanotube
nanoparticles, multi-walled carbon nanotube nanoparticles, graphene
nanoparticles, and nanodiamond nanoparticles into a subterranean
formation comprises introducing a suspension comprising a first
portion of nanoparticles having a first functional group and a
second portion of nanoparticles having a second functional group
into the subterranean formation.
15. The method of claim 11, wherein introducing a suspension
including at least one of single wall carbon nanotube
nanoparticles, multi-walled carbon nanotube nanoparticles, graphene
nanoparticles, and nanodiamond nanoparticles into a subterranean
formation and contacting at least some of the nanoparticles with
steam comprises: introducing a first suspension including at least
one of single wall carbon nanotube nanoparticles, multi-walled
carbon nanotube nanoparticles, graphene nanoparticles, and
nanodiamond nanoparticles into the subterranean formation;
contacting at least some of the nanoparticles of the first
suspension with steam; introducing a second suspension including at
least one of single wall carbon nanotube nanoparticles,
multi-walled carbon nanotube nanoparticles, graphene nanoparticles,
and nanodiamond nanoparticles into a subterranean formation; and
contacting at least some of the nanoparticles of the second
suspension with steam.
16. The method of claim 15, wherein introducing a second suspension
into the subterranean formation comprises contacting hydrocarbons
that were not contacted by nanoparticles of the first
suspension.
17. The method of claim 11, wherein introducing a suspension into a
subterranean formation comprises introducing an aqueous-based
suspension into the subterranean formation at a temperature of
between about 90.degree. C. and about 100.degree. C.
18. The method of claim 11, further comprising introducing another
suspension including at least one of single wall carbon nanotube
nanoparticles, multi-walled carbon nanotube nanoparticles, graphene
nanoparticles, and nanodiamond nanoparticles into the subterranean
formation after transferring the hydrocarbons to the surface of the
subterranean formation.
19. The method of claim 11, wherein introducing a suspension
including at least one of single wall carbon nanotube
nanoparticles, multi-walled carbon nanotube nanoparticles, graphene
nanoparticles, and nanodiamond nanoparticles into a subterranean
formation comprises introducing the suspension into the
subterranean formation during a hydraulic fracturing process.
20. A method of transferring heat to a hydrocarbon-containing
material, the method comprising: introducing a suspension
comprising nanoparticles having an average thermal conductivity
greater than about 2,000 W/m-K into a formation containing
hydrocarbons; contacting at least a portion of the formation having
a lower thermal conductivity than surrounding portions of the
formation with the suspension to adhere nanoparticles of the
suspension to the hydrocarbons of the at least a portion of the
formation; contacting the nanoparticles and the formation with
steam; and extracting hydrocarbons from the formation.
Description
TECHNICAL FIELD
[0001] Embodiments of the disclosure relate generally to methods of
increasing the thermal conductivity of subterranean formations.
More particularly, embodiments of the disclosure relate to methods
of increasing a thermal conductivity of a hydrocarbon-containing
material within a subterranean formation with nanoparticle
materials, and to methods of enhancing hydrocarbon recovery using
the nanoparticles.
BACKGROUND
[0002] Enhanced oil recovery includes processes for increasing the
amount of hydrocarbon material (e.g., crude oil, natural gas, etc.)
recovered from a subterranean formation. Methods of enhanced oil
recovery include water flooding, steam assisted gravity drainage
(SAGD), steam flooding (e.g., cyclic steam stimulation (CSS)), and
related methods. In these processes, a carrier fluid (e.g., water,
brine, steam, etc.) is injected into a subterranean formation
through injection wells to heat and/or sweep a hydrocarbon material
contained within interstitial spaces (e.g., pores, cracks,
fractures, channels, etc.) of the subterranean formation toward
production wells offset from the injection wells.
[0003] However, heavy hydrocarbon materials (e.g., hydrocarbons
having an API gravity of about 22 (specific gravity of about 0.92)
or lower), or bitumen (e.g., bituminous sands including oil sands
and tar sands) often exhibit a high viscosity and, therefore, are
often difficult to produce. The high viscosity of such heavy
hydrocarbons makes them difficult to mobilize and transport from a
subterranean formation to the surface to be produced. Reducing the
viscosity of such heavy hydrocarbons and bitumen is often a goal of
hydrocarbon recovery processes.
[0004] Methods for enhancing the recovery of hydrocarbons and
bitumen often include thermal stimulation methods, with the goal of
decreasing the viscosity of the hydrocarbons. One thermal process
of lowering the viscosity of hydrocarbons in subterranean
formations is to flood the formation with a heating medium (e.g.,
steam). Steam increases the temperature of the hydrocarbons in the
formation, which lowers the viscosity of the hydrocarbons and
allows the hydrocarbons to drain or be swept towards an oil well to
be produced. The steam may also sweep the hydrocarbon-containing
regions of the subterranean formation (e.g., the reservoir) and
physically displace any hydrocarbons within the reservoir and push
the hydrocarbons towards producing wells. Steam can also condense
into water, which can then act as a low viscosity carrier phase for
an emulsion of the hydrocarbon and the water, allowing heavy
hydrocarbons to be more easily produced. In other conventional
thermal stimulation processes, steam may be injected into the
formation through wormholes, fissures, or fractures within the
subterranean formation to create a steam chamber. In some methods,
such as CSS, steam may be injected into the subterranean formation
and allowed to soak within the subterranean formation for a period
of days or weeks. As the steam soaks within the
hydrocarbon-containing formation, at least a portion of the
hydrocarbons are heated and the viscosity of the heated
hydrocarbons is reduced. The heated hydrocarbons may be swept or
drain to a production well and be produced. Another method of
thermal stimulation is steam assisted gravity drainage wherein two
horizontal wells are drilled. Steam is injected into an upper well
and heat from the steam transfers to bitumen, reducing the
viscosity and mobilizing the bitumen. The bitumen may drain to a
lower well, where it may be produced.
[0005] However, the aforementioned methods of thermal stimulation
may not effectively heat large portions of hydrocarbon-containing
materials within a subterranean formation. For example, a large
portion of the hydrocarbons may be isolated from the steam. The
hydrocarbons may be surrounded by a formation with a substantially
low porosity (e.g., having very small pores and throat openings),
reducing the accessibility of the steam to the hydrocarbons. Pore
throat sizes may be as low as 1 .mu.m in sandstones and shale
formations and may be as low as about 10 nm in tight-gas
sandstones, reducing the accessibility of the heating medium to
major portions of the hydrocarbons within such formations. Thus,
heat transfer to the hydrocarbons within such formations may be
limited by the thermal conductivity of the formation surrounding
entrapped hydrocarbons.
BRIEF SUMMARY
[0006] Embodiments disclosed herein include methods of increasing a
thermal conductivity of a subterranean formation as methods of
recovering hydrocarbons from a hydrocarbon-containing material
within the formation. For example, in accordance with one
embodiment, a method for increasing a thermal conductivity of a
subterranean formation comprises combining nanoparticles with a
carrier fluid to form a suspension, injecting the suspension into a
subterranean formation, adhering the nanoparticles to surfaces and
within pores of the subterranean formation, and heating
hydrocarbon-containing material within the subterranean formation
and at least a portion of the nanoparticles with a heating
fluid.
[0007] In additional embodiments, a method of recovering
hydrocarbons from a subterranean formation comprises introducing a
suspension including at least one of single wall carbon nanotube
nanoparticles, multi-walled carbon nanotube nanoparticles, graphene
nanoparticles, and nanodiamond nanoparticles into a subterranean
formation, contacting surfaces of the subterranean formation and a
hydrocarbon-containing material with the suspension and adhering at
least some of the nanoparticles to surfaces of the subterranean
formation and the hydrocarbon-containing material, contacting at
least some of the nanoparticles with steam, transferring heat from
at least some of the nanoparticles to the subterranean formation
and the hydrocarbon-containing material to reduce a viscosity of
hydrocarbons within the hydrocarbon-containing material, and
transferring the hydrocarbons to a surface of the subterranean
formation.
[0008] In further embodiments, a method of transferring heat to a
hydrocarbon-containing material comprises introducing a suspension
comprising nanoparticles having an average thermal conductivity
greater than about 2,000 W/m-K into a formation containing
hydrocarbons, contacting at least a portion of the formation having
a lower thermal conductivity than surrounding portions of the
formation with the suspension to adhere nanoparticles of the
suspension to the hydrocarbons of the at least a portion of the
formation, contacting the nanoparticles and the formation with
steam, and extracting hydrocarbons from the formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] FIG. 1 is a simplified flow diagram depicting a method of
heating a hydrocarbon-containing material and recovering
hydrocarbons from the hydrocarbon-containing material, in
accordance with embodiments of the disclosure.
DETAILED DESCRIPTION
[0010] The following description provides specific details, such as
material types, compositions, material thicknesses, and processing
conditions in order to provide a thorough description of
embodiments of the disclosure. However, a person of ordinary skill
in the art will understand that the embodiments of the disclosure
may be practiced without employing these specific details. Indeed,
the embodiments of the disclosure may be practiced in conjunction
with conventional techniques employed in the industry. In addition,
the description provided below does not form a complete process
flow for heating and recovering hydrocarbons from a
hydrocarbon-containing subterranean formation. Only those process
acts and structures necessary to understand the embodiments of the
disclosure are described in detail below. A person of ordinary
skill in the art will understand that some process components
(e.g., pipelines, line filters, valves, temperature detectors, flow
detectors, pressure detectors, and the like) are inherently
disclosed herein and that adding various conventional process
components and acts would be in accord with the disclosure.
Additional acts or materials to heat and extract a hydrocarbon
material from a subterranean formation or from bitumen may be
performed by conventional techniques.
[0011] A rate of hydrocarbon recovery from a subterranean formation
may be increased by increasing a thermal conductivity of a
subterranean formation including hydrocarbons. For example, the
transfer of heat to desired portions of a hydrocarbon-containing
material within a subterranean formation may be increased by
increasing the thermal conductivity of the subterranean formation
and the hydrocarbon-containing material. In some embodiments, the
thermal conductivity of the subterranean formation or
hydrocarbon-containing material may be increased by increasing the
thermal conductivity of the subterranean formation and
hydrocarbon-containing material exhibiting a lower thermal
conductivity than other portions of the formation and
hydrocarbon-containing material. Accordingly, by increasing the
thermal conductivity of the subterranean formation and
hydrocarbon-containing material, hydrocarbons from a subterranean
formation may be recovered with less steam and energy than in
conventional thermal stimulation methods.
[0012] According to embodiments disclosed herein, a suspension
including nanoparticles exhibiting a high thermal conductivity
suspended in a carrier fluid is introduced into a subterranean
formation to increase the thermal conductivity of the subterranean
formation. The nanoparticles are configured to adhere to the
surfaces of hydrocarbon-containing material within the subterranean
formation and to organic surfaces (e.g., hydrocarbons) of the
hydrocarbon-containing material. The nanoparticles may travel
through interfaces of the host rock and surfaces of the
hydrocarbon-containing material and disperse throughout the
hydrocarbon-containing material, including regions within tightly
packed formations (e.g., tight-gas sandstones, small pore shales,
etc.). The nanoparticles may be configured (e.g. due to their size
and shape) to travel through hydrocarbon-containing materials with
reduced pore throat sizes and regions of reduced porosity (e.g.,
reduced pore sizes). As the nanoparticles travel through and adhere
to the hydrocarbon-containing material, the they conductivity of
the hydrocarbon-containing material increases. The
hydrocarbon-containing material, including the high thermal
conductivity nanoparticles attached thereto, may be exposed to a
heating medium (e.g., a heating fluid), such as high temperature
water or brine, high pressure steam, and combinations thereof. The
heating fluid may contact at least a portion of the
hydrocarbon-containing material and at least a portion of the
attached nanoparticles. Trapped hydrocarbons may be heated at an
accelerated rate because of the increased overall thermal
conductivity of the hydrocarbon-containing material. Heat transfer
through the subterranean formation and the hydrocarbon-containing
material may be directed by a heat flow path defined by locations
of the nanoparticles adhered to surfaces of the
hydrocarbon-containing material. Accordingly, a heat transfer rate
through the hydrocarbon-containing material is increased, reducing
overall steam consumption and the time required to heat a given
volume of the hydrocarbon-containing material. The methods
described herein may require less steam, produce less waste water,
and emit less carbon dioxide than conventional recovery methods.
Accordingly, economical hydrocarbon production rates may be
achieved in less time than in conventional thermal stimulation
methods.
[0013] As used herein, the "nanoparticle" means and includes
particles having an average particle size of less than about 1,000
nm. The nanoparticles may have an average particle size of less
than about 1,000 nm. The nanoparticles may include materials
exhibiting a high thermal conductivity, such as a thermal
conductivity above about 2,000 W/m-K.
[0014] As used herein, the term "pore throat" means and includes an
opening at a point where two grains of material (e.g., formation,
sand, etc.) meet, which connects larger pore volumes between the
grains. Generally, the pore throat decreases with a decreasing
grain size.
[0015] As used herein, the term "hydrocarbon-containing material"
means and includes materials that include hydrocarbons and may
include materials that surround the hydrocarbons. For example, a
hydrocarbon-containing material may include bitumen and may also
include bitumen and surrounding host rock formations, such as
sandstones and shale formations.
[0016] Referring to FIG. 1, a simplified flow diagram illustrating
a method of obtaining a hydrocarbon material contained within a
subterranean formation in accordance with embodiments of the
disclosure is shown. The method may include a suspension formation
process 100 including forming a suspension including a plurality of
nanoparticles; an injection process 102 including introducing the
suspension into the subterranean formation and
hydrocarbon-containing material to attach the nanoparticles to
surfaces of the hydrocarbon-containing material; an optional
heating process 104 including flowing a solution of water or brine
to heat the hydrocarbon-containing material; a steam injection
process 106 including injecting high pressure steam into the
subterranean formation and contacting the nanoparticles adhered to
the hydrocarbon-containing material with the steam and heating the
hydrocarbons within the hydrocarbon-containing material; an
optional cycle process 108, including repeating the injection
process 102, the optional heating process 104, and the steam
injection process 106; and an extraction process 110 including
extracting the heat stimulated hydrocarbons from the subterranean
formation.
[0017] The subterranean formation may be stimulated to create flow
channels from a wellbore to hydrocarbon-containing materials
located within the subterranean formation. In some embodiments,
channels may be formed in the subterranean formation during
drilling operations or during a cold heavy oil production with sand
process (known in the industry as "CHOPS"). The channels may be
referred to in the art as "wormholes" and may create fluid
conductivity paths between the wellbore and the subterranean
formation, such as between the wellbore and hydrocarbon-containing
regions of the subterranean formation.
[0018] In other embodiments, fractures within the subterranean
formation may be forming by hydraulic fracturing. Hydraulic or
propellant-based fracturing may create fractures in the
subterranean formation in zones adjacent hydrocarbon-containing
materials to create channels through which hydrocarbons may flow to
the wellbore, through a production string, and to the surface. A
hydraulic fracturing process may include injecting a fracturing
fluid (e.g., water, a high velocity propellant gas, etc.) into a
wellbore at high pressures. The fracturing fluid may be directed to
a hydrocarbon-containing material within the subterranean
formation. The high pressure fracturing fluid creates fractures in
the subterranean formation. Proppant suspended in fracturing fluids
may be introduced (e.g., injected) into the formation to prop open
the fluid channels created during the fracturing process at
pressures below the pressure at which the fractures are created.
The fractures, when open, may provide a flow path for
hydrocarbon-containing materials within the formation to flow from
the formation to the production string and to the surface. The
fractures may also provide a flow path for materials including the
nanoparticles to travel from the wellbore, through the fractures,
and to the hydrocarbon-containing material. In some embodiments, at
least a portion of the proppants may be coated with the
nanoparticles.
[0019] Prior to heating the hydrocarbon-containing material, the
hydrocarbon-containing material may be contacted with a suspension
including nanoparticles having a high thermal conductivity. The
nanoparticles may be mixed with a carrier fluid and suspended
within the carrier fluid in a suspension formation process 100. The
suspension formation process 100 includes suspending the
nanoparticles in a carrier fluid to form a suspension of
nanoparticles. The nanoparticles may be insoluble in the carrier
fluid and suspended throughout the carrier fluid. In some
embodiments, the carrier fluid is a colloidal suspension including
colloidal nanoparticles. The colloidal nanoparticles may be a
dispersed phase in a continuous carrier fluid phase and may be
uniformly dispersed within the carrier fluid.
[0020] The carrier fluid may be an aqueous-based fluid with solid
nanoparticles suspended in a continuous phase of the carrier fluid.
The carrier fluid may be an aqueous fluid, such as a water or a
brine solution. In other embodiments, the carrier fluid is a
non-aqueous fluid, such as a hydrocarbon fluid, a brine-in-oil
emulsion, or a water-in-oil emulsion. In some embodiments, the
nanoparticles may be suspended in a high pressure steam carrier
fluid. The steam may heat the subterranean formation and the
hydrocarbon-containing material at the same time that the
nanoparticles are introduced to the hydrocarbon-containing
material. In other embodiments, the carrier fluid is a solvent. The
solvent may include a mixture of one or more types of
nanoparticles. The solvent may include materials such as methane,
ethane, propane, isobutane, n-butane, pentanes, hexanes, heptanes,
CO.sub.2, surfactants, aromatics such as benzene, xylene, and
toluene, refined products such as gasoline and diesel, and
combinations thereof.
[0021] The nanoparticles may include nanoparticles exhibiting a
high thermal conductivity, such as a thermal conductivity higher
than about 2,000 watts per meter kelvin (W/m-K). Non-limiting
examples of suitable nanoparticles include single walled carbon
nanotubes (SWCNTs) (about 6,000 W/m-K), multi-walled carbon
nanotubes (MWCNTs) (about 3,000 W/m-K), graphene (about 5,000
W/m-K), and nanodiamonds (about 2,300 W/m-K). Thus, nanoparticles
including SWCNTs, MWCNTs, graphene, nanodiamonds, and combinations
thereof, may be mixed into a carrier fluid to form a suspension
including the nanoparticles. The suspension may include SWCNTs,
MWCNTs, graphene, nanodiamonds, and combinations thereof. In some
embodiments, the suspension may include one or more of SWCNTs,
MWCNTs, graphene, and nanodiamonds, and at least another of SWCNTs,
MWCNTs, graphene, and nanodiamonds.
[0022] The nanoparticles may have a diameter between about 5 nm and
about 1,000 nm, such as between about 5 nm and about 10 nm, between
about 10 nm and about 20 nm, between about 20 nm and about 50 nm,
between about 50 nm and about 100 nm, between about 100 nm and
about 500 nm, or between about 500 nm and about 1,000 nm. The
nanoparticles may have a length that is substantially larger than a
diameter of the nanoparticles. For example, a length of the
nanoparticles may be up to about 25,000 nm, such as between about 5
nm and about 50 nm, between about 50 nm and about 500 nm, between
about 500 nm and about 1,000 nm, between about 1,000 nm and about
5,000 nm, between about 5,000 nm and about 10,000 nm, or between
about 10,000 nm and about 25,000 nm.
[0023] The nanoparticles may be monodisperse wherein each of the
nanoparticles has substantially the same size, shape, and material
composition, or may be polydisperse, wherein the nanoparticles
include a range of sizes, shapes, and/or material composition. In
some embodiments, each of the nanoparticles has substantially the
same size and the same shape as each of the other
nanoparticles.
[0024] The carrier fluid may include between about 0.0001 weight
percent (wt. %) to about 15 weight percent, such as between about
0.001 weight percent and about 1.0 weight percent, between about
1.0 weight percent and about 5.0 weight percent, or between about
5.0 weight percent and about 15 weight percent of the
nanoparticles. In some embodiments, the suspension may include a
first type of nanoparticle suspended within the carrier fluid and a
second, different type of nanoparticle suspended within the carrier
fluid. For example, the carrier fluid may include at least one of
single walled carbon nanotubes, multi-walled carbon nanotubes,
graphene, and nanodiamonds and at least another of single walled
carbon nanotubes, multi-walled carbon nanotubes, graphene, and
nanodiamonds suspended within the carrier fluid.
[0025] The thermal conductivity of the suspension including the
nanoparticles may be between about 2.0 W/m-K and about 100 W/m-K,
such as between about 2.0 W/m-K and about 20 W/m-K, between about
20 W/m-K and about 50 W/m-K, between about 50 W/m-K and about 75
W/m-K, or between about 75 W/m-K and about 100 W/m-K.
[0026] The nanoparticles may include one or more functional groups.
The functional groups may increase a dispersibility of the
nanoparticles in the carrier fluid. By way of non-limiting example,
at least one edge, surface, or end of the nanoparticles may be
modified to include at least one functional group. In some
embodiments, the nanoparticles are functionalized only at a surface
thereof. Functionalized nanoparticles may prevent flocculation or
agglomeration of the nanoparticles within the suspension. In some
embodiments, at least a portion of the nanoparticles are
functionalized and at least another portion of the nanoparticles
are unfunctionalized. Functionalization of at least a portion of
the nanoparticles may increase the dispersibility of the
nanoparticles within the carrier fluid, but may, undesirably,
reduce the overall thermal conductivity of the nanoparticle
suspension. In some embodiments, a minimal portion of the
nanoparticles are functionalized to suspend a desired amount of
nanoparticles within the suspension. In some embodiments, one type
of nanoparticle may be functionalized and other types of
nanoparticles may be unfunctionalized and suspended within the same
carrier fluid. In some embodiments, at least a portion of the
nanoparticles are functionalized with at least one of a hydroxyl
group (OH), a carboxyl group (--COOH), an amine group ((NRR'R''),
wherein R, R', and R'' may include hydrogen, another functional
group, or an organic group), an alkyl group, and polyethylene
glycol functional groups.
[0027] The nanoparticles may also include one or more functional
groups configured to adhere the nanoparticles to the formation
surrounding the hydrocarbon-containing material, or to organic
surfaces of the hydrocarbon-containing material (e.g., bitumen).
Thus, at least a first portion of the nanoparticles may include one
functional group to increase the dispersibility of the
nanoparticles in the carrier fluid and at least a second portion of
the nanoparticles may include another functional group configured
to adhere the nanoparticles to the hydrocarbon-containing material
or increase a dispersibility of the nanoparticles within
hydrocarbons of the hydrocarbon-containing material. The carrier
fluid may include at least a first portion of nanoparticles
including a first functional group, a second portion of
nanoparticles including a second functional group different than
the first functional group, and a third portion of nanoparticles
that are unfunctionalized. Each of the first portion of
nanoparticles, the second portion of nanoparticles, and the third
portion of nanoparticles may include the same type of nanoparticle
or may include different types of nanoparticles. For example, a
suspension may include at least one of single walled carbon
nanotubes, multi-walled carbon nanotubes, graphene, and
nanodiamonds functionalized with a first functional group, at least
another of single walled carbon nanotubes, multi-walled carbon
nanotubes, graphene, and nanodiamonds functionalized with a second
functional group, and at least another of unfunctionalized single
walled carbon nanotubes, multi-walled carbon nanotubes, graphene,
and nanodiamonds. In some embodiments, the nanoparticles may
include at least one hydroxyl group for increasing the
dispersibility of the nanoparticles within an aqueous carrier fluid
and may also include one or more carbonyl, carboxyl, hydroxyl, and
amine groups configured to attach the nanoparticles to the
hydrocarbon-containing material. In other embodiments, at least a
portion of the nanoparticles may be functionalized with a
hydrophobic functional group and at least another portion of the
nanoparticles may be functionalized with a hydrophilic functional
group. In some embodiments, nanoparticles may be functionalized
with both hydrophilic functional groups and hydrophilic functional
groups.
[0028] Non-limiting examples of functional groups include, but are
not limited to, hydroxyl (OH) groups, carboxyl (--COOH) groups,
carbonyl groups (a compound including a carbon-oxygen double bond
(C.dbd.O)), such as a ketone, an aldehyde, a carboxylate group
(RCOO), an ester group, and an alkoxy group (an alkyl group with a
carbon-oxygen single bond (R--O--R')), an alkyl group, an alkenyl
group (C.dbd.C), an alkynyl group (C.ident.C), an organohalide
group (R--X, wherein R is a hydrocarbon and X is a halide, such as
F, Cl, Br, or I), a halide group, an amine group (primary amine,
secondary amine, tertiary amine), an amide group (organic amides
(--NHCO--), a sulfanoamide, a phosphoroamide), an organosulfur
group, an epoxy group, a polyamine group, a sulfonate group
(RSO.sub.2O.sup.-), a sulfate group (SO.sub.4.sup.2-), a succinate
group (HOOC--(CH.sub.2).sub.2--COO.sup.-), a sulfosuccinate group
(HOOC--CH.sub.2--SO.sub.3--COOH), a thiosulfate group
(S.sub.2O.sub.3.sup.2-), a glucoside group
(C.sub.6H.sub.12O.sub.6--O), an ethoxylate group
(R--(OC.sub.2H.sub.4).sub.nOH), a propoxylate group
(R--(OC.sub.3H.sub.6).sub.nOH), a phosphate group
(PO.sub.4.sup.3-), an ether group (R--O--R'), an
ethoxylatepropoxylate group, a phenyl group (R--C.sub.6H.sub.5), a
benzyl group (C.sub.6H.sub.5--CH.sub.2), perfluro compounds, a
thiol group (R--SH), an epoxy group, a lactone, a metal, an
organo-metallic group, an oligomer (e.g., a dimer, a trimer, a
tetramer, etc.), a polymer, an acid chloride group (RCOCl), and
combinations thereof. By way of non-limiting example, where the
hydrocarbon-containing material includes carboxylic acids, a
portion of the nanoparticles may be functionalized with one or more
of amine groups, hydroxyl groups, and combinations thereof to
attach the nanoparticles to carboxylic acid groups within the
hydrocarbon-containing material.
[0029] In some embodiments, between about 0 weight percent (0 wt.
%) and about 20 weight percent, such as between about 0 weight
percent and about 5 weight percent, between about 5 weight percent
and about 10 weight percent, or between about 10 weight percent and
about 20 weight percent of the nanoparticles are functionalized
while the remaining nanoparticles are unfunctionalized.
[0030] The nanoparticles may be configured to adhere to the
subterranean formation, to the hydrocarbon-containing material, and
to combinations thereof. In some embodiments, at least a portion of
the nanoparticles are configured to adhere to the subterranean
formation and at least another portion of the nanoparticles are
configured to adhere to the hydrocarbon-containing material (e.g.,
bitumen). As the nanoparticles adhere to surfaces of the formation,
the thermal conductivity of the subterranean formation may
increase. Similarly, as the nanoparticles adhere to surfaces of the
hydrocarbon-containing material, the thermal conductivity of the
hydrocarbon-containing material may increase. As the thermal
conductivity of the subterranean formation and the
hydrocarbon-containing material increase, the hydrocarbons within
the subterranean formation may be stimulated to elevated
temperatures with less steam and in less time than conventional
heat stimulation methods. The nanoparticles may be configured to
travel to deeper portions (e.g., shale rich portions) of the
hydrocarbon-containing material and increase a thermal conductivity
of the deeper portions of the hydrocarbon-containing material,
increasing the rate at which heat is transferred to the
hydrocarbons trapped within the hydrocarbon-containing
material.
[0031] The carrier fluid may further include one or more
surfactants to increase the dispersibility of the nanoparticles
within the carrier fluid. For example, the surfactants may comprise
between about 0.01 weight percent and about 15 weight percent of
the carrier fluid, such as between about 0.01 weight percent and
about 5 weight percent of the carrier fluid. The surfactants may be
non-ionic, anionic, cationic, amphoteric, zwitterionic, janus, and
combinations thereof. Non-limiting examples of suitable non-ionic
surfactants include alkyl polyglycosides, sorbitan esters, methyl
glucoside esters, amine ethoxylates, diamine ethoxylates,
polyglycerol esters, alkyl ethoxylates, and alcohols that have been
polypropoxylated and/or polyethoxylated or both. Anionic
surfactants may include alkali metal alkyl sulfates, alkyl ether
sulfonates, alkyl sulfonates, alkyl aryl sulfonates, linear and
branched alkyl ether sulfates and sulfonates, alcohol
polypropoxylated sulfates, alcohol polyethoxylated sulfates,
alcohol polypropoxylated polyethoxylated sulfates, alkyl
disulfonates, alkylaryl disulfonates, alkyl disulfates, alkyl
sulfosuccinates, alkyl ether sulfates, linear and branched ether
sulfates, alkali metal carboxylates, fatty acid carboxylates, and
phosphate esters. Cationic surfactants may include, but are not
necessarily limited to, arginine methyl esters, alkanolamines and
alkylenediamides. Other surfactants may include dimeric or gemini
surfactants, cleavable surfactants, janus surfactants, and extended
surfactants (also called extended chain surfactants).
[0032] The nanoparticles in the suspension may be introduced to the
hydrocarbon-containing material and adhere to the
hydrocarbon-containing material in the injection process 102. The
nanoparticles may be introduced into the subterranean formation
with stimulation fluids, such as thermal treating fluids, hydraulic
fracturing fluids, or any other suitable fluid for transporting the
nanoparticles to the subterranean formation.
[0033] The injection process 102 may include introducing the
nanoparticles to the subterranean formation at high pressures.
Injecting the nanoparticle suspension into the subterranean
formation at high pressures may create fractures within the
subterranean formation. The fractures may form conduits through
which the nanoparticles may travel through the formation and to the
hydrocarbon-containing material. In other embodiments, the
nanoparticles may be suspended within a fracturing fluid and
introduced to the subterranean formation during a hydraulic
fracturing process. The fracturing fluid may include a mixture of
proppants for holding fractures created by the fracturing fluid
open. The fracturing fluid may also include nanoparticles that may
travel through the fractures and adhere to the subterranean
formation within the fractures. The nanoparticles may also travel
to the hydrocarbon-containing material beyond the fractures and
travel through the hydrocarbon-containing material.
[0034] In yet other embodiments, the nanoparticles may be
introduced into the subterranean formation after creating hydraulic
fractures in the subterranean formation and prior to heat
stimulation of the hydrocarbon-containing material. For example,
after hydraulic fracturing is complete, a carrier fluid including
the nanoparticles may be introduced into the subterranean
formation. The nanoparticles may adhere to the subterranean
formation within the fractures and may also travel across the
hydrocarbon-containing material beyond the fractures. For example,
the nanoparticles may travel within pores of the
hydrocarbon-containing material as small as about 1,000 nm. The
nanoparticles may adhere to the hydrocarbon-containing material at
regions with small domains (e.g., pore throat sizes and pores) and
regions of reduced porosity that may not be sufficiently stimulated
during conventional heat stimulation techniques.
[0035] In yet other embodiments, the nanoparticles may be
introduced into the hydrocarbon-containing material through
wormholes within the subterranean formation. For example, wormholes
may be created by removing sand filters from the well and producing
sand with produced hydrocarbons, such as in cold heavy oil
production with sand (known in the industry as "CHOPS"). In some
embodiments, an initial stage of hydrocarbons may be recovered by
CHOPS. Wormholes may be formed within the subterranean formation
during the CHOPS production stage and prior to introducing the
nanoparticles into the subterranean formation. The nanoparticles
may be introduced into the subterranean formation through the
wormholes formed during the initial CHOPS production stage.
[0036] In some embodiments, the suspension may be heated to a
temperature below a boiling point of the carrier fluid prior to
introducing the suspension into the hydrocarbon-containing
material. Where the carrier fluid includes an aqueous-based fluid
(e.g., water or brine), the carrier fluid may be heated to a
temperature between about 90.degree. C. and about 100.degree. C.
and introduced into the subterranean formation.
[0037] The hydrocarbon-containing material may include oil sands
having an average pore throat diameter of about 1 .mu.m or less.
The number, size, and distribution of the pore throats may control
the flow, capillary pressure, and the resistivity of flow through
the formation. In some embodiments, the nanoparticles travel
between pores and throats of a hydrocarbon-containing material
having at least some pores and throats smaller than about one
micrometer (1 .mu.m). In some embodiments, pore throat diameters
may be as low as between about 5 nm and about 1,000 nm, such as
between about 5 nm and about 10 nm, between about 10 nm and about
100 nm, between about 100 nm and about 500 nm, or between about 500
nm and about 1,000 nm. For example, tight gas sandstones and shales
may have pore throat diameters as low as about 5 nm. The
nanoparticles may have an average size that is less than the
average pore throat diameter or of the smallest pore throats in the
hydrocarbon-containing material.
[0038] The thermal conductivity of the hydrocarbon-containing
material (e.g., oil sands) may range from between about 1.5 W/m-K
to about 2.5 W/m-K. The nanoparticles may exhibit a thermal
conductivity that is about three orders of magnitude higher (i.e.,
about 1,000 times higher) than the thermal conductivity of the
hydrocarbon-containing material. Therefore, a relatively low amount
of nanoparticles in the hydrocarbon-containing material may
significantly increase the average thermal conductivity of the
hydrocarbon-containing material.
[0039] In some embodiments, the nanoparticles may be directed to
portions of the hydrocarbon-containing material having a lower
thermal conductivity than other portions of the
hydrocarbon-containing material. By way of example, regions of the
hydrocarbon-containing material having a lower porosity (e.g.,
sandstone and shale rich regions) may have a lower thermal
conductivity than other regions of the hydrocarbon-containing
material. Low thermal conductivity portions of the
hydrocarbon-containing material may create non-uniform heat
distribution in the hydrocarbon-containing material during thermal
stimulation processes. For example, as steam is injected into the
hydrocarbon-containing material, non-uniform heat distribution may
result in a non-homogeneous steam chamber, wherein portions of the
hydrocarbon-containing material remain unaffected by the steam,
resulting in a lower than optimal volumetric sweep efficiency and
hydrocarbon recovery rate. Contacting portions of the
hydrocarbon-containing material having a lower natural thermal
conductivity than other portions of the hydrocarbon-containing
material with a higher concentration of nanoparticles than the
other portions of the hydrocarbon-containing material may improve
the uniformity of heat distribution within the
hydrocarbon-containing material (e.g., increase a rate at which
heat is transferred to the low thermal conductivity regions). Thus,
heat transfer may be increased throughout the
hydrocarbon-containing material as the thermal conductivity of at
least portions of the subterranean formation and the
hydrocarbon-containing material is increased. In some embodiments,
the suspension of nanoparticles is directed at only the
hydrocarbon-containing material without contacting other regions of
the subterranean formation to improve the homogeneity of the
thermal conductivity of the subterranean formation and the
hydrocarbon-containing material.
[0040] In some embodiments, the nanoparticles are directed to
shale-rich portions of the hydrocarbon-containing material
including regions of hydrocarbons isolated by the tight spacing
(e.g., small pore throats and pore diameters) of the
hydrocarbon-containing material. By way of example, a thermal
conductivity of shale rich portions of a hydrocarbon-containing
material may be lower than a thermal conductivity of other portions
of the hydrocarbon-containing material. In some embodiments, a
first portion of nanoparticles may be directed to the
hydrocarbon-containing material and a second portion of
nanoparticles having a smaller average particle size may be
directed to the hydrocarbon-containing material to contact deeper
portions of the hydrocarbon-containing material than the first
portion of nanoparticles. The first portion of nanoparticles and
the second portion of nanoparticles may be suspended in the same
carrier fluid. In other embodiments, a first portion of
nanoparticles having a first thermal conductivity may be directed
to a first portion of the hydrocarbon-containing material having a
lower thermal conductivity than a second portion of the
hydrocarbon-containing material. A second portion of nanoparticles
having a second thermal conductivity lower than the first thermal
conductivity may be directed to the second portion of the
hydrocarbon-containing material.
[0041] After the suspension of nanoparticles has circulated through
the hydrocarbon-containing material and adhered to at least
portions of the hydrocarbon-containing material, the carrier fluid
may be cycled out of the subterranean formation and back to the
surface. A solution of hot water or hot brine may be introduced
into the subterranean formation and hydrocarbon-containing material
in an optional heating process 104. The hot water or hot brine
solution may be circulated within the hydrocarbon-containing
material and contact at least a portion of the nanoparticles
adhered to surfaces of the hydrocarbon-containing material. The
nanoparticles may accelerate the rate at which heat from the hot
water or hot brine solution is transferred to the hydrocarbons of
the hydrocarbon-containing material. The hot solution may reduce
the viscosity and increase the permeability of the hydrocarbons
contacted by the nanoparticles.
[0042] After the optional heating process 104, high pressure steam
may be introduced to the hydrocarbon-containing material to further
transfer heat to the hydrocarbons contained therein in the steam
injection process 106. Heat from the high pressure steam may
transfer to the hydrocarbon-containing material through the
nanoparticles and reduce the viscosity of the hydrocarbons. As the
hydrocarbons are heated and the viscosity is reduced, the porosity
of the hydrocarbon-containing material may increase and the
hydrocarbons may flow from the hydrocarbon-containing material to
expose more portions of the hydrocarbons within the
hydrocarbon-containing material than were exposed during the
injection process 102 or the optional heating process 104.
[0043] In some embodiments, after a sufficient amount of time,
heated hydrocarbons may be recovered from the
hydrocarbon-containing material in the extraction process 110. If a
sufficient amount of hydrocarbons have been contacted by the
nanoparticles and heated during the steam injection process 106,
the hydrocarbons may flow to a production well and be produced at
the surface.
[0044] In other embodiments, after the steam injection process 106,
an optional cycle process 108 may include repeating at least one of
the injection process 102, the optional heating process 104, and
the steam injection process 106. The optional cycle process 108 may
include introducing nanoparticles into the hydrocarbon-containing
material at various stages of heat stimulation or production.
Nanoparticles may be introduced into the subterranean and adhere to
the hydrocarbon-containing material during the injection process
102. A concentration of nanoparticles within the suspension may be
less than, the same as, or greater than a concentration of
nanoparticles in a suspension of a previous cycle. The carrier
fluid may be the same or different than carrier fluids used in
previous cycles. The nanoparticles suspended in the carrier fluid
may contact surfaces of the hydrocarbon-containing material that
were initially unexposed or inaccessible during previous cycles and
were not previously contacted by nanoparticles. For example, during
the optional heating process 104 and the steam injection process
106, hydrocarbon-bearing surfaces may become exposed as the
hydrocarbon-containing material is heated and a viscosity of the
hydrocarbons is reduced. Trapped hydrocarbons may become exposed as
the hydrocarbon-containing material is heated and the pore size and
pore throats of the hydrocarbon-containing material may increase,
exposing more hydrocarbons of the hydrocarbon-containing material.
Accordingly, each injection process 102 may contact more
hydrocarbons of the hydrocarbon-containing material with
nanoparticles than previous injection processes 102 because the
optional heating process 104 and the steam injection process 106 of
previous cycles may expose more regions of the
hydrocarbon-containing material. Thus, the nanoparticles of an
injection process 102 may adhere to the hydrocarbon-containing
material at locations that were not contacted by the nanoparticles
during a previous injection process 102.
[0045] In some embodiments, the optional cycle process 108 includes
introducing a first suspension including at least one of single
wall carbon nanotube nanoparticles, multi-walled carbon nanotube
nanoparticles, graphene nanoparticles, and nanodiamond
nanoparticles into the subterranean formation in a first injection
process 102 and contacting at least some of the nanoparticles of
the first suspension with steam in a first steam injection process
106. The optional cycle process 108 further includes introducing a
second suspension including at least one of single wall carbon
nanotube nanoparticles, multi-walled carbon nanotube nanoparticles,
graphene nanoparticles, and nanodiamond nanoparticles into a
subterranean formation in a second injection process 102 and
contacting at least some of the nanoparticles of the second
suspension with steam in a second steam injection process 106. The
first suspension and the second suspension may include the same or
different types, concentrations, and functional groups on the
nanoparticles. Steam from the first steam injection process 106 may
expose hydrocarbons that were not contacted by nanoparticles of the
first suspension in the first injection process 106. Nanoparticles
of the second suspension may contact hydrocarbons that were not
contacted by nanoparticles of the first suspension.
[0046] The optional cycle process 108 may be repeated any number of
times. In some embodiments, only one cycle is required and the
thermal conductivity of the hydrocarbon-containing material is
sufficiently increased such that hydrocarbons may be economically
recovered with one cycle. In other embodiments, the
hydrocarbon-containing material may be tightly packed (e.g., shale,
sandstone) such that pore sizes of the hydrocarbon-containing
material are less than about 5 nm. Repeating the cycles may
advantageously expose deeper portions of the hydrocarbon-containing
material and enhance oil recovery beyond conventional thermal
stimulation methods.
[0047] In some embodiments, hydrocarbons may be recovered from the
subterranean formation in between each cycle. In other embodiments,
hydrocarbons may be recovered from the subterranean formation after
repeating two, three, four, etc., cycles. After hydrocarbons are
recovered from the hydrocarbon-containing material, the
hydrocarbon-containing material may be further stimulated by
repeating the injection process 102, the optional heating process
104, the steam injection process 106, the optional cycle process
108. Hydrocarbons may be recovered by repeating the extraction
process 110.
[0048] Accordingly, recovery of hydrocarbons may be increased in
formations including heavy hydrocarbons with reduced water, energy
consumption, and CO.sub.2 emissions. Nanoparticles adhered to the
hydrocarbon-containing material may increase the rate of thermal
transfer across the hydrocarbon-containing material as at least
portions of the hydrocarbon-containing material and nanoparticles
are contacted with a heating fluid.
[0049] While the disclosure is susceptible to various modifications
and alternative forms, specific embodiments have been shown by way
of example in the drawings and have been described in detail
herein. However, the disclosure is not intended to be limited to
the particular forms disclosed. Rather, the disclosure is to cover
all modifications, equivalents, and alternatives falling within the
scope of the disclosure as defined by the following appended claims
and their legal equivalents.
* * * * *