U.S. patent application number 14/455222 was filed with the patent office on 2014-11-27 for nanofluids and methods of use for drilling and completion fluids.
This patent application is currently assigned to BAKER HUGHES INCORPORATED. The applicant listed for this patent is Baker Hughes Incorporated. Invention is credited to ANTONIA ENRIQUE CARDENAS, DAVID E. CLARK, LIRIO QUINTERO.
Application Number | 20140349894 14/455222 |
Document ID | / |
Family ID | 45467421 |
Filed Date | 2014-11-27 |
United States Patent
Application |
20140349894 |
Kind Code |
A1 |
QUINTERO; LIRIO ; et
al. |
November 27, 2014 |
NANOFLUIDS AND METHODS OF USE FOR DRILLING AND COMPLETION
FLUIDS
Abstract
Nanomaterial compositions are useful for applications in
drilling and completion fluids as enhancers of electrical and
thermal conductivity, emulsion stabilizers, wellbore strength
improvers, drag reduction agents, wettability changers, corrosion
coating compositions and the like These nanomaterials may be
dispersed in the liquid phase in low volumetric fraction,
particularly as compared to corresponding agents of larger size.
Nanofluids (fluids containing nano-sized particles) may be used to
drill at least part of the wellbore. Nanofluids for drilling and
completion applications may be designed including nanoparticles
such as carbon nanotubes. These fluids containing nanomaterials,
such as carbon nanotubes, meet the required rheological and
filtration properties for application in challenging HPHT drilling
and completions operations.
Inventors: |
QUINTERO; LIRIO; (Houston,
TX) ; CARDENAS; ANTONIA ENRIQUE; (Houston, TX)
; CLARK; DAVID E.; (Humble, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Baker Hughes Incorporated |
Houston |
TX |
US |
|
|
Assignee: |
BAKER HUGHES INCORPORATED
Houston
TX
|
Family ID: |
45467421 |
Appl. No.: |
14/455222 |
Filed: |
August 8, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
13166448 |
Jun 22, 2011 |
8822386 |
|
|
14455222 |
|
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|
61359111 |
Jun 28, 2010 |
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Current U.S.
Class: |
507/110 ;
507/103; 507/129; 507/131; 507/135; 507/136; 507/139; 507/140 |
Current CPC
Class: |
C09K 2208/12 20130101;
C09K 8/32 20130101; C09K 8/05 20130101; C09K 8/524 20130101; C09K
2208/22 20130101; C09K 8/035 20130101; C09K 2208/10 20130101; C09K
8/032 20130101; C09K 2208/32 20130101; C09K 2208/34 20130101; C09K
2208/20 20130101; C09K 8/528 20130101 |
Class at
Publication: |
507/110 ;
507/140; 507/135; 507/103; 507/139; 507/136; 507/129; 507/131 |
International
Class: |
C09K 8/32 20060101
C09K008/32; C09K 8/05 20060101 C09K008/05 |
Claims
1. A drilling fluid having increased rheological stability
comprising: a base fluid selected from the group consisting of an
aqueous fluid, a non-aqueous fluid and combinations thereof, where
the base fluid comprises a continuous phase; solid particles
suspended in the continuous phase; and nanoparticles having a size
less than 999 nm, selected from the group consisting of silica,
magnesium oxide, iron oxide, copper oxide, zinc oxide, nickel
oxide, alumina, boron, carbon black, graphene, carbon nanotubes,
ferromagnetic nanoparticles, nanoplatelets, surface-modified
nanoparticles, halloysite clay nanotubes, polymer-based
nanoparticles, degradable nanoparticles, nanocapsules, mesoporous
nanoparticles, multistimuli-responsive nanospheres, core/shell
nanoparticles, and combinations thereof; where the nanoparticles
are present in the fluid in an amount effective to improve the
rheological stability of the fluid over a temperature range from
ambient up to about 320.degree. C. and a pressure range of about
atmospheric pressure up to about 350 MPa, as compared with an
identical drilling fluid absent the nanoparticles.
2. The drilling fluid of claim 1 where the nanoparticles have at
least one dimension less than 100 nm.
3. The drilling fluid of claim 1 further comprising a surfactant in
an amount effective to suspend the nanoparticles in the base
fluid.
4. The drilling fluid of claim 1 where the nanoparticles have an
electrical charge.
5. The drilling fluid of claim 1 where the nanoparticles are
functionalized nanoparticles having at least one functional group
selected from the group consisting of sulfonate, sulfate,
sulfosuccinate, thiosulfate, succinate, carboxylate, hydroxyl,
glucoside, ethoxylate, propoxylate, phosphate, ethoxylate, ether,
amines, amides and combinations thereof.
6. The drilling fluid of claim 1 where the nanoparticles are
functionalized nanoparticles having at least two functional groups
where: one functional group is a hydrophilic group; and a second
functional group is a hydrophobic group.
7. The drilling fluid of claim 1 where the amount of nanoparticles
in the drilling fluid range from about 5 ppm to about 150,000
ppm.
8. The drilling fluid of claim 1 where the nanoparticles are
functionalized nanoparticles with a polar and a non-polar
group.
9. The drilling fluid of claim 1 where the nanoparticles
encapsulate at least one encapsulated additive, where the at least
one encapsulated additive is selected from the group consisting of
wax and asphaltene inhibitors, shale stabilizers, corrosion
inhibitors, rate of penetration enhancers, scale inhibitors,
hydrate inhibitors, biocides, lubricants, additives for acid
treatment, cross linking agents, chemicals to treat acid gases,
tracers, gel forming polymers and combinations thereof.
10. The drilling fluid of claim 9 where the encapsulated additive
is released from the nanoparticles by a triggering release
mechanism selected from the group consisting of change of pH,
change of temperature, change of electrolyte type, change of
concentration, application of a magnetic field, application of a
electromagnetic field, and combinations thereof.
11. A drilling fluid having increased rheological stability
comprising: a base fluid selected from the group consisting of an
aqueous fluid, a non-aqueous fluid and combinations thereof, where
the base fluid comprises a continuous phase; solid particles
suspended in the continuous phase; and nanoparticles have at least
one dimension less than 100 nm, selected from the group consisting
of silica, magnesium oxide, iron oxide, copper oxide, zinc oxide,
nickel oxide, alumina, boron, carbon black, graphene, carbon
nanotubes, ferromagnetic nanoparticles, nanoplatelets,
surface-modified nanoparticles, halloysite clay nanotubes,
polymer-based nanoparticles, degradable nanoparticles,
nanocapsules, mesoporous nanoparticles, multistimuli-responsive
nanospheres, core/shell nanoparticles, and combinations thereof;
where the nanoparticles are present in the fluid in an amount
effective to improve the rheological stability of the fluid ranging
from about 5 ppm to about 150,000 ppm over a temperature range from
ambient up to about 320.degree. C. and a pressure range of about
atmospheric pressure up to about 350 MPa, as compared with an
identical drilling fluid absent the nanoparticles.
12. The drilling fluid of claim 11 further comprising a surfactant
in an amount effective to suspend the nanoparticles in the base
fluid.
13. The drilling fluid of claim 11 where the nanoparticles have an
electrical charge.
14. The drilling fluid of claim 11 where the nanoparticles are
functionalized nanoparticles having at least one functional group
selected from the group consisting of sulfonate, sulfate,
sulfosuccinate, thiosulfate, succinate, carboxylate, hydroxyl,
glucoside, ethoxylate, propoxylate, phosphate, ethoxylate, ether,
amines, amides and combinations thereof.
15. The drilling fluid of claim 11 where the nanoparticles are
functionalized nanoparticles having at least two functional groups
where: one functional group is a hydrophilic group; and a second
functional group is a hydrophobic group.
16. The drilling fluid of claim 11 where the nanoparticles are
functionalized nanoparticles with a polar and a non-polar
group.
17. The drilling fluid of claim 11 where the nanoparticles
encapsulate at least one encapsulated additive, where the at least
one encapsulated additive is selected from the group consisting of
wax and asphaltene inhibitors, shale stabilizers, corrosion
inhibitors, rate of penetration enhancers, scale inhibitors,
hydrate inhibitors, biocides, lubricants, additives for acid
treatment, cross linking agents, chemicals to treat acid gases,
tracers, gel forming polymers and combinations thereof.
18. A drilling fluid having increased rheological stability
comprising: a base fluid selected from the group consisting of an
aqueous fluid, a non-aqueous fluid and combinations thereof, where
the base fluid comprises a continuous phase; solid particles
suspended in the continuous phase; nanoparticles having a size less
than 999 nm and an electrical charge, selected from the group
consisting of silica, magnesium oxide, iron oxide, copper oxide,
zinc oxide, nickel oxide, alumina, boron, carbon black, graphene,
carbon nanotubes, ferromagnetic nanoparticles, nanoplatelets,
surface-modified nanoparticles, halloysite clay nanotubes,
polymer-based nanoparticles, degradable nanoparticles,
nanocapsules, mesoporous nanoparticles, multistimuli-responsive
nanospheres, core/shell nanoparticles, and combinations thereof;
and a surfactant in an amount effective to suspend the
nanoparticles in the base fluid where the nanoparticles are present
in the fluid in an amount effective to improve the rheological
stability of the fluid over a temperature range from ambient up to
about 320.degree. C. and a pressure range of about atmospheric
pressure up to about 350 MPa, as compared with an identical
drilling fluid absent the nanoparticles.
19. The drilling fluid of claim 18 where the nanoparticles have at
least one dimension less than 100 nm.
20. The drilling fluid of claim 18 where the amount of
nanoparticles in the drilling fluid range from about 5 ppm to about
150,000 ppm.
Description
CROSS-REFERENCES TO RELATED APPLICATIONS
[0001] This application is a divisional patent application from
U.S. patent application Ser. No. 13/166,448 filed Jun. 22, 2011,
issued as U.S. Pat. No. ______ on ______, which in turn claimed the
benefit of U.S. Provisional Patent Application Ser. No. 61/359,111
filed Jun. 28, 2010, both of which are incorporated herein in their
entirety by reference.
TECHNICAL FIELD
[0002] The present invention relates to drilling fluids and
completion fluids for use in wellbores and subterranean reservoirs,
and more particularly relates, in one non-limiting embodiment, to
drilling fluids and completion fluids which contain nanoparticles
of effective type and in sufficient quantity to improve the
properties thereof.
BACKGROUND
[0003] Drilling fluids used in the drilling of subterranean oil and
gas wells along with other drilling fluid applications and drilling
procedures are known. In rotary drilling there are a variety of
functions and characteristics that are expected of drilling fluids,
also known as drilling muds, or simply "muds". The drilling fluid
is expected to carry cuttings up from beneath the bit, transport
them up the annulus, and allow their separation at the surface
while at the same time the rotary bit is cooled and cleaned. A
drilling mud is also intended to reduce friction between the drill
string and the sides of the hole while maintaining the stability of
uncased sections of the borehole. The drilling fluid is formulated
to prevent unwanted influxes of formation fluids from permeable
rocks penetrated and also often to form a thin, low permeability
filter cake which temporarily seals pores, other openings and
formations penetrated by the bit. It is desirable to minimize the
loss into the formation of the relatively expensive drilling fluid.
Drilling fluids must also be formulated to stabilize the wellbore
wall to keep it from swelling, for instance in the case of drilling
through shale. The drilling fluid may also be used to collect and
interpret information available from drill cuttings, cores and
electrical logs, thus its electrical properties are important.
Drilling fluids should also not unnecessarily aggravate the
tendency of drill bits, tubulars and other downhole equipment to
corrode, and, in a particular non-limiting embodiment, should help
prevent such corrosion. It will be appreciated that within the
scope of the claimed invention herein, the term "drilling fluid"
also encompasses "drill-in fluids", "completion fluids", "workover
fluids" and remediation fluids.
[0004] It is apparent to those selecting or using a drilling fluid
for oil and/or gas exploration, and field development that an
essential component of a selected fluid is that it be properly
balanced to achieve the necessary characteristics for the specific
end application. Because drilling fluids are called upon to perform
a number of tasks simultaneously, this desirable balance is not
always easy to achieve. It is also important for the properties of
the drilling fluid to be stable, for instance that the rheological
properties (viscosity, etc.) are stable throughout the pressure and
temperature ranges that the fluid experiences, possibly including
high temperature, high pressure conditions which are abbreviated
HTHP.
[0005] Drilling fluids are typically classified according to their
base fluid. In water-based muds, solid particles are suspended in a
continuous phase consisting of water or brine. Oil can be
emulsified in the water which is the continuous phase. Brine-based
drilling fluids, of course are water-based mud (WBM) in which the
aqueous component is brine. Oil-based muds (OBM) are the opposite
or inverse of water-based muds. In oil-based muds, solid particles
are suspended in a continuous phase consisting of oil. Water or
brine can be emulsified in the oil and therefore the oil is the
continuous phase. Oil-based muds can be either all-oil based or
water-in-oil macroemulsions, which are also called invert
emulsions. In oil-based mud, the oil may consist of any oil or
water-immiscible fluid that may include, but is not limited to,
diesel, mineral oil, esters, refinery cuts and blends, or
alpha-olefins. OBMs as defined herein also include synthetic-based
fluids or muds (SBMs) which are synthetically produced rather than
refined from naturally-occurring materials. SBMs often include, but
are not necessarily limited to, olefin oligomers of ethylene,
esters made from vegetable fatty acids and alcohols, ethers and
polyethers made from alcohols and polyalcohols, paraffinic, or
aromatic, hydrocarbons alkyl benzenes, terpenes and other natural
products and mixtures of these types.
[0006] Formation damage involves undesirable alteration of the
initial characteristics of a producing formation, typically by
exposure to drilling fluids, completion fluids or in the production
phase of the well. The water or solid particles in the fluids used
in drilling and completion operations tend to decrease the pore
volume and effective permeability of the producible formation in
the near-wellbore region. There may be at least three possible
mechanisms at work. First, solid particles from the fluid may
physically plug or bridge across flowpaths in the porous formation.
Second, when water contacts certain clay minerals in the formation,
the clays typically swell, thus increasing in volume and in turn
decreasing the pore volume. Third, chemical reactions between the
fluid and the formation rock and fluids may precipitate solids or
semisolids that plug pore spaces. Phase transitions due to changes
in pressure or temperature of fluid composition during the wellbore
construction and production may lead to undesirable precipitation
or formation of asphaltenes, wax, scales, etc.
[0007] Reduced hydrocarbon production can result from reservoir
damage when a drilling mud deeply invades the subterranean
reservoir. It will also be understood that the drilling fluid, e.g.
oil-based mud, is deposited and concentrated at the borehole face
and partially inside the formation. Many operators are interested
in improving formation clean up and removing the cake or plugging
material and/or improving formation damage after drilling into
reservoirs with oil-based muds.
[0008] It is also important when drilling subterranean formations
to keep the wellbore stable, so that the walls of the borehole do
not cave into the hole, and that the stability of the walls is
maintained. Other issues involve improving the electrical
resistivity or otherwise modifying the electrical conductivity of
the drilling fluid. In some cases, it is desirable to diminish the
drilling fluid resistivity, that is, improve the inverse property
or the electrical conductivity of the fluid.
[0009] It would be desirable if drilling fluid compositions and
methods could be devised to avoid damage to the near-wellbore area
of the formation, as well as assess the location and existence of
damage and aid and improve the ability to clean up damage and
difficulties caused to the wellbore, the formation, equipment in
the wellbore (for instance, stuck pipe), and to remove and/or
resolve problems more completely and easily, without causing
additional damage to the formation, wellbore and/or equipment.
BRIEF DESCRIPTION OF DRAWING
[0010] FIG. 1 is a graph comparison of the pore pressure
transmission performances for two water-based fluid systems with
and without added nanoparticles (Formulation A and B
respectively).
SUMMARY
[0011] There is provided, in one non-limiting form, a drilling
fluid that includes a base fluid which may be an aqueous fluid, a
non-aqueous fluid and/or combinations thereof. The drilling fluid
also includes nanoparticles having a size less than 999 nm.
Suitable nanoparticles include, but are not necessarily limited to,
nano-silica, nano magnesium oxide, nano-iron oxide, nano-manganese
oxide, nano-copper oxide, nano-zinc oxide, nano-nickel oxide,
nano-alumina, nano-boron, carbon black, nano-graphene, carbon
nanotube, ferromagnetic nanoparticles, nanoplatelets of these
materials, surface-modified nanoparticles, halloysite clay
nanotubes, polymer-based nanoparticles, degradable nanoparticles,
nanocapsules, mesoporous nanoparticles, multistimuli-responsive
nanospheres, core/shell nanoparticles and combinations of these. By
"multistimuli-responsive", it is meant that the nanospheres respond
or react to more than one type of stimulus, e.g. pressure,
temperature, pH, etc. The drilling fluid may also include a
surfactant in an amount effective to suspend the nanoparticles in
the base fluid. The amount of nanoparticles in the fluid is
associated with its intended function, e.g. the content of
nanoparticles present in the fluid to stabilize shale of a
subterranean formation adjacent to the wellbore will be inferred
from the petrophysical characteristics of the formation and what
the intended impact is.
[0012] In another non-restrictive version there is provided a
drilling fluid that includes a base fluid which may be an aqueous
fluid, a non-aqueous fluid and/or combinations thereof. The
drilling fluid also includes nanofibers having an average
cross-sectional dimension of less than 100 nm and an average
particle length of several times (in one non-limiting example, 10
times) the nanofiber diameter. Suitable nanofibers include, but are
not necessarily limited to, carbon nanotubes, carbon, graphitized
carbon, coated nanofibers, metal oxides, carbide or nitride
nanofibers, as well as polymers, including but not limited to
polyethylene oxide, polyaramids, polyaniline, polyvinyl alcohol,
polystyrene, polyacrylonitrile, nylon, polyester. Nanoparticles may
also comprise these materials. The drilling fluid may also
optionally include a surfactant in an amount effective to suspend
the nanoparticles in the base fluid. The nanoparticles are present
in the fluid in an amount effective to affect the electrical,
thermal properties of the fluid as compared with an identical
drilling fluid absent the nanoparticles, where either resistivity
or conductivity is improved or the electrical conductivity of the
fluid is otherwise modified.
[0013] In another non-limiting embodiment there is provided a
drilling fluid which includes a base fluid selected from the group
consisting of an aqueous fluid, a non-aqueous fluid and/or
combinations thereof. The drilling fluid also contains
nanoparticles having an average particle size less than 999,
alternatively having an average particle size less than 100 nm.
Suitable nanoparticles include, but are not necessarily limited to,
materials of nano-silica, nano-barium sulfate, nano-magnesium
oxide, nano-iron oxide, nano-copper oxide, nano-zinc oxide,
nano-nickel oxide, nano-alumina, nano-boron, carbon black,
nano-graphene, carbon nanotube, ferromagnetic nanoparticles;
nanoplatelets, surface-modified nanoparticles halloy-site clay
nanotubes, polymer-based nanoparticles, degradable nanoparticles,
nanocapsules, mesoporous nanoparticles, multistimuli-responsive
nanospheres, core/shell nanoparticles and combinations of these.
The drilling fluid may also contain a surfactant or surfactants, if
required, in an amount effective to suspend the nanoparticles in
the base fluid. The nanoparticles are present in the fluid in an
amount effective to maintain the rheological properties of the
fluid over a temperature range of about 0.degree. C. up to about
320.degree. C. and a pressure range of about atmospheric pressure
up to about 350 MPa, as compared with an identical drilling fluid
absent the nanoparticles.
[0014] There is further provided in a different, non-restrictive
version, a drilling fluid which contains a base fluid having an
aqueous fluid, a non-aqueous fluid and/or combinations thereof,
along with nanoparticles having a size less than 999 nm, selected
from the group consisting of but are not necessarily limited to
nano-silica, magnesium oxide, nano-iron oxide, nano-copper oxide,
nano-zinc oxide, nano-nickel oxide, nano-alumina, nano-boron,
carbon black, nano-graphene, carbon nanotube, ferromagnetic
nanoparticles, nanoplatelets, surface-modified nanoparticles, and
combinations thereof. The nanoparticles, which may be nanofibers,
are present in the fluid in an amount effective to improve the drag
reduction of the fluid as compared with an identical drilling fluid
absent the nanoparticles.
[0015] Additionally, there is provided in a different non-limiting
embodiment an emulsified drilling fluid having a base fluid that
contains an emulsion of an aqueous fluid and a non-aqueous fluid.
The emulsified drilling fluid includes nanoparticles having a size
less than 999 nm of materials such as silica, magnesium, iron
oxide, copper oxide, zinc oxide, nickel oxide, alumina, boron,
carbon black, graphene, carbon nanotube, ferromagnetic
nanoparticles, surface-modified nanoparticles, halloysite clay
nanotubes, polymer-based nanoparticles, degradable nanoparticles,
nanocapsules, mesoporous nanoparticles, multistimuli-responsive
nanospheres, core/shell nanoparticles and combinations thereof. The
emulsified drilling fluid contains a surfactant in an amount
effective to suspend the nanoparticles in the base fluid. The
nanoparticles are present in the fluid in an amount effective to
improve the stability of the emulsion as compared with an identical
drilling fluid absent the nanoparticles.
[0016] Alternatively there is provided in a non-restrictive
version, a drilling fluid with a base fluid including either or
both of an aqueous fluid and a non-aqueous fluid as well as
nanoparticles having a size less than 999 nm. Suitable
nanoparticles include, but are not necessarily limited to,
nano-silica, nano magnesium oxide, nano-iron oxide, nano-copper
oxide, nano-zinc oxide, nano-nickel oxide, nano-alumina,
nano-boron, carbon black, nano-graphene, carbon nanotube,
ferromagnetic nanoparticles, nanoplatelets, surface
modified-nanoparticles, halloysite clay nanotubes, polymer-based
nanoparticles, degradable nanoparticles, nanocapsules, mesoporous
nanoparticles, multistimuli-responsive nanospheres, core/shell
nanoparticles and combinations of these, as well as a surfactant if
required in an amount effective to suspend the nanoparticles in the
base fluid. The nanoparticles are present in the fluid in an amount
effective to reverse the wettability of a downhole material
selected from the group consisting of filter cake, drill cuttings,
wellbore surfaces, casing, metal surfaces, such as the surfaces of
downhole equipment, and combinations thereof.
[0017] Further there is provided in another non-limiting
embodiment, an equipment/drilling fluid combination having improved
corrosion resistance. The drilling fluid includes a base fluid
which may include an aqueous fluid and/or a non-aqueous fluid. The
drilling fluid also includes nanoparticles having a size less than
999 nm. Suitable nanoparticles include, but are not necessarily
limited to, nano-silica, nano-magnesium oxide, nano-iron oxide,
nano-copper oxide, nano-zinc oxide, nano-nickel oxide,
nano-alumina, nano-boron, carbon black, nano-graphene, carbon
nanotube, ferromagnetic nanoparticles, nanoplatelets, surface
modified nanoparticles, halloysite clay nanotubes, polymer-based
nanoparticles, degradable nanoparticles, nanocapsules, mesoporous
nanoparticles, multistimuli-responsive nanospheres, core/shell
nanoparticles and combinations of these. The drilling fluid may
also contain an optional surfactant in an amount effective to
suspend the nanoparticles in the base fluid. The drilling fluid is
in contact with equipment at least partially composed of a material
which may be stainless steel, duplex steel, chrome steel,
martensitic alloy steels, ferritic alloy steels, austenitic
stainless steels, precipitation-hardened stainless steels, high
nickel content steels, and combinations thereof. The nanoparticles
are present in the fluid in an amount effective to improve the
corrosion resistance of (lessen the corrosion of) the equipment as
compared with an identical drilling fluid absent the nanoparticles.
In this non-limiting embodiment the nanoparticles may include, but
are not necessarily limited to scavenger materials for oxygen,
hydrogen sulfide (H.sub.2S), carbon dioxide, carbonyl sulfide
(COS), hydrogen cyanide (HCN), carbon disulfide (CS.sub.2) and
mixtures thereof.
[0018] In another non-limiting embodiment there is provided a
drilling fluid which includes a base fluid which may include an
aqueous fluid, a non-aqueous fluid and/or combinations thereof. The
drilling fluid also contains nanoparticles having an average
particle size less than 999 nm. Suitable nanoparticles include, but
not limited to, nano-silica, magnesium oxide, nano-iron oxide,
nano-copper oxide, nano-zinc oxide, nano-nickel oxide,
nano-alumina, nano-boron, carbon black, nano-graphene, carbon
nanotube, ferromagnetic nanoparticles, nanoplatelets,
surface-modified nanoparticles, halloysite clay nanotubes,
polymer-based degradable nanoparticles, nanocapsules,
multistimuli-responsive nanospheres, core/shell nanoparticles and
combinations thereof, containing at least one encapsulated additive
including but not necessarily limited to, wax and asphaltene
inhibitors, shale stabilizers, corrosion inhibitors, rate of
penetration (ROP) enhancers, scale inhibitors, hydrate inhibitors,
biocides, lubricants, additives for acid treatment, cross linking
agents, chemicals to treat acid gases, tracers, gel forming
polymers and the like.
[0019] Alternatively there is provided in a non-restrictive
version, a drilling fluid with a base fluid including either or
both of an aqueous fluid and a non-aqueous fluid as well as
nanoparticles having a size less than 999 nm selected from a group
including but not limited to nano-silica, magnesium oxide,
nano-iron oxide, nano-copper oxide, nano-zinc oxide, nano-alumina,
nano-boron, carbon black, nano-graphene, carbon nanotube,
ferromagnetic nanoparticles, nanoplatelets, surface-modified
nanoparticles, halloysite clay nanotubes, polymer-based degradable
nanoparticles, nanocapsules, multistimuli-responsive nanospheres,
core/shell nanoparticles and combinations thereof, containing
encapsulated corrosion inhibitors including but not necessarily
limited to scavenger materials for oxygen, hydrogen sulfide
(H.sub.2S), carbon dioxide, carbonyl sulfide (COS), hydrogen
cyanide (HCN), carbon disulfide (CS.sub.2), and mixtures thereof.
The encapsulated corrosion inhibitor is released when the
nanoparticle is subjected to a specific triggering mechanism
providing a self-healing corrosion protection. The triggering
mechanism includes but is not necessary limited to changes of pH,
temperature, electrolyte type or concentration, or application of a
magnetic or electromagnetic field.
[0020] There may be additionally provided in another
non-restrictive version, a completion fluid that includes a base
fluid which may be an aqueous fluid and/or a non-aqueous fluid. The
completion fluid also includes nanoparticles having a size less
than 100 nm, selected from the group consisting of nano-silica,
magnesium oxide and other nano-oxides, nano-iron oxide, nano-copper
oxide, nano-zinc oxide, nano-nickel oxide, nano-alumina,
nano-boron, carbon black, nano-graphene, carbon nanotubes and other
carbon-based materials, ferromagnetic nanoparticles, nanoplatelets,
surface-modified nanoparticles, along with an optional surfactant
in an amount effective to suspend the nanoparticles in the base
fluid. The nanoparticles are present in the fluid in an amount
effective to improve fluid loss by increasing the viscosity as
compared with an identical drilling fluid absent the
nanoparticles.
[0021] Also there is provided in a different non-limiting
embodiment a drilling fluid that contains a base fluid that is an
aqueous fluid and/or a non-aqueous fluid. The drilling fluid also
includes nanoparticles having a size less than 999 nm, selected
from the group consisting of nano-silica, magnesium oxide,
nano-iron oxide, nano-copper oxide, nano-zinc oxide, nano-nickel
oxide, nano-alumina, nano-boron, carbon black, nano-graphene,
carbon nanotube, ferromagnetic nanoparticles, nanoplatelets,
surface-modified nanoparticles and combinations thereof. The
drilling fluid additionally includes a surfactant in an amount
effective to suspend the nanoparticles in the base fluid. The
nanoparticles are present in the fluid in an amount effective to
improve lost circulation as compared with an identical drilling
fluid absent the nanoparticles.
[0022] In another non-limiting embodiment there is provided a
drilling fluid which includes a base fluid selected from the group
consisting of an aqueous fluid, a non-aqueous fluid and/or
combinations thereof. The drilling fluid also contains
nanoparticles having an average particle size less than 999,
alternatively having an average particle size less than 100 nm,
which nanoparticles include materials of nano-silica, nano-barium
sulfate, nano-magnesium oxide, nano-iron oxide, nano-copper oxide,
nano-zinc oxide, nano-nickel oxide, nano-alumina, nano-boron,
carbon black, nano-graphene, carbon nanotube, ferromagnetic
nanoparticles, nanoplatelets, surface-modified nanoparticles,
halloysite clay nanotubes, polymer-based degradable nanoparticles,
nanocapsules, multistimuli-responsive nano-spheres, core/shell
nanoparticles and combination thereof. The nanoparticles present in
the fluid contain encapsulated or incorporated therein a gel
forming additive including but not limited to polyacrylamide,
crosslinking agents, in situ crosslinkable polymers, superabsorbent
polymers and the like that are released by applying a triggering
mechanism which includes but is not necessary limited to changes of
pH, temperature, electrolyte type or concentration, or application
of a magnetic or electromagnetic field. Such triggering would
release and allow the encapsulated gel forming additive to activate
to form gel, hydrate and expand in the presence of formation water,
plugging the pores and blocking water movement and dehydrating and
shrinking when contacting oil, hence allowing the oil to flow.
DETAILED DESCRIPTION
[0023] Nano-material compositions have been discovered as useful
for applications in drilling and completion fluids as enhancers of
electrical and thermal conductivity, emulsion stabilizers, wellbore
strengthening components, drag reducers, wettability changers, as
corrosion-inhibiting coatings, etc. It has been found that the
nanofluids for drilling and completion applications may be designed
by adding nano-composites and/or organic and inorganic
nano-particulate materials, such as carbon nanotubes,
functionalized nanotubes, nanospheres, nano magnesium oxide, nano
barium sulfate, nano-nickel oxide, nano-silica, nano-iron oxide,
metal nanoparticles, surface-modified nanoparticles, halloysite
clay nanotubes, polymer-based nanoparticles, degradable
nanoparticles, nanocapsules, mesoporous nanoparticles,
multistimuli-responsive nanospheres, core/shell nanoparticles and
the like and their combinations. The use of surfactants together
with nanoparticles may form self-assembly structures that enhance
the thermodynamic, physical, and rheological properties of drilling
and completion fluids. The use of surfactants is optional. These
nanomaterials are dispersed in the liquid phase, typically in low
volumetric fraction. The liquid phase may be any liquid, such as an
aqueous phase or non-aqueous phase, or mixtures such as an emulsion
of oil-in-water (O/W) or water-in-oil (W/O). The nanofluids may be
used in conventional operations and in challenging drilling and
completions operations that require stable fluids for high
temperature and pressure conditions (HTHP). Within the context of
this application, the term "mesoporous" refers to a material
containing pores with diameters between about 2 and about 50
nm.
[0024] In the present context, nanoparticles are defined as having
at least one dimension less than 999 nm, although other dimensions
may be larger than this. In one non-limiting instance, in the case
of carbon nanotubes (single wall or multi-wall), the smallest
dimension may be less than 100 nm, for instance, the diameter of
the nanotubes, but the length of the nanotubes may be much longer
than 100 nm, for instance 1000 nm or more. Such nanoparticles would
be within the scope of the drilling and completion fluids
herein.
[0025] The dimensions of nanoparticles are on an atomic scale. One
nanometer is one millionth of a millimeter, which corresponds to
the width of ten hydrogen atoms. Nanoparticles in nature are
ultrafine, usually larger than atom clusters, but smaller than
ordinary microparticles. While materials on a micron scale have
properties similar to the larger materials from which they are
derived, assuming homogeneous composition, the same is not true of
nanoparticles. An immediate example is the very large interfacial
or surface area per volume for nanoparticles. The consequence of
this phenomenon is a very large potential for interaction with
other matter, as a function of volume. For short carbon fibers, the
surface areas may be as small as about 1 m.sup.2/g, whereas for
multiwall nanotubes (MWNTs), the surface area may range from about
40 to about 300 m.sup.2/g, but may be up to about 1315 m.sup.2/g
for a single-wall nanotubes (SWNT) or up to about 1800 m.sup.2/g
for graphene (a one-atom-thick planar sheet of sp.sup.2-bonded
carbon atoms that are densely packed in a honeycomb crystal
lattice; a sort of atomic scale "chicken wire" made of carbon atoms
and their bonds).
[0026] In general, MWNTs are easier to manufacture than SWNTs and
are thus relatively cheaper and more plentiful. However, SWNTs are
more valued because they can be more precisely engineered, for
instance to contain certain desired functional groups in more
precise proportion. Split or cleaved nanotubes may provide
"nanoribbons", similar to graphene, but in a longitudinal strip
form. The potential for such nanoribbons or nanostrips is that the
edge sites may be more easily reacted with various reactants to
give functional groups as compared with reacting the surface atoms
of SWNTs or MWNTs. Techniques to cleave or split a nanotube (e.g.
as described by J. Tour (Rice University), or M. Torrones
(Instituto Potosino de Investigacion Cientifica y Tecnologica,
Mexico), or H. Dai (Stanford University) and/or others) involve
methods that longitudinally "unzip" a nanotube, resulting in a
"nano-sheet" of graphene. More information may be found in C.
BARRAS, "Nanotubes Unzip to Offer Computing Route Beyond Silicon,"
New Scientist, April, 2009, available at:
http://www.newscientist.com/article/dn16955-nanotubes-unzip-to-offer--
computing-route-beyond-silicon.html, incorporated herein by
reference in its entirety. Other shapes may be useful in the
compositions and methods herein, including, but not necessarily
limited to, nano-sized platelets or nanoplatelets.
[0027] Nevertheless, it should be understood that surface-modified
nanoparticles, including but not necessarily limited to,
surface-modified nanoplatelets, surface-modified nanoribbons,
surface-modified nanostrips, etc. may find utility in the
compositions and methods herein. "Surface-modification" is defined
here as the process of altering or modifying the surface properties
of a particle by any means, including but not limited to physical,
chemical, electrochemical or mechanical means, and with the intent
to provide a unique desirable property or combination of properties
to the surface of the particle, which differs from the properties
of the surface of the unprocessed particle.
[0028] Functionalized nanoparticles are defined herein as those
which have had their edges or surfaces modified to contain at least
one functional group including, but not necessarily limited to,
sulfonate, sulfate, sulfosuccinate, thiosulfate, succinate,
carboxylate, hydroxyl, glucoside, ethoxylate, propoxylate,
phosphate, ethoxylate, ether, amines, amides, and combinations
thereof.
[0029] Nanoparticles composed of other materials besides
carbon-carbon lattices will also be useful, for instance calcium
carbonate nanoparticles, which in turn suggests that potassium
carbonate nanoparticles may also be beneficial. Other suitable
nanoparticle materials include, but are not necessarily limited to,
TiO.sub.2, Al.sub.2O.sub.3, MgO and/or Mg(OH).sub.2, FeO,
Fe.sub.2O.sub.3, Fe.sub.3O.sub.4, CuO, SiO.sub.2, ZnO, CeO.sub.2,
Mn.sub.3O.sub.4, SiC, Si.sub.3N.sub.4, and the like.
[0030] These enormous surface areas per volume dramatically
increase the interaction of the nanoparticles with the matrix or
surrounding fluid. This surface area may serve as sites for bonding
with functional groups, including polymerization, and can influence
crystallization, chain entanglement, and morphology, and thus can
generate a variety of properties in the matrix. In the present
context, the matrix includes the base fluid of a drilling fluid or
a completion fluid. For instance, it is anticipated that
nanoparticles and conventional polymers may be linked or bonded
together directly or through certain intermediate chemical linkages
to combine some of the advantageous properties of each. Similarly,
polymers may be connected with nanoparticles in particular ways,
such as by spiral wrapping of a polymer around a carbon nanotube.
It may be necessary to modify the nanotube surface to achieve such
a structure. Suitable polymers include, but are not necessarily
limited to,
poly(m-phenylenevinylene-co-2,5-dioctoxy-p-phenylenevinylene)
(PmPV), polyaniline, poly(para-phenylenevinylene) (PPV),
poly(methyl methacrylate) (PMMA), polyvinyl alcohol (PVA), and the
like. Such nanoparticle-polymer hybrids may use nanoparticles and
nanotubes as polymer-type building blocks in conventional
copolymer-type structures, such as block copolymers, graft
copolymers, cross-linking at the side of a nanotube, e.g. and the
like.
[0031] Additionally, because of the very large surface area to
volume present in nanoparticles, it is expected that in most, if
not all cases, much less proportion of nanoparticles need be
employed relative to micron-sized additives conventionally used to
achieve or accomplish a similar effect.
[0032] Further, certain nanoparticles (e.g. MgO and/or
Mg(OH).sub.2, and the like), appear to connect with or associate
with other small particles and surfaces, such as clay and non-clay
particles, including charged and non-charged particles. Since
nanoparticles are so small, the charge density per unit volume is
very large. Due to at least in part to their small size, the
surface forces (like van der Waals and electrostatic forces) of
nanoparticles help them associate, group or flocculate fine
particles together in larger collections, associations or
agglomerations in ways different from their micro-size
counterparts. Such charges and forces may help secure such small
particles to a larger surface or substrate, for instance, to help
stabilize a borehole wall.
[0033] In another non-limiting embodiment, degradable nanoparticles
are nanoparticles which degrade, cleave or break down into smaller
particles which themselves are useful or degrade, cleave or break
to allow the controlled release of encapsulated one or more
water-soluble, or oil-soluble additives including but not
necessarily limited to, wax and asphaltene inhibitors, shale
stabilizers, corrosion inhibitors, rate of penetration (ROP)
enhancers, scale inhibitors, hydrate inhibitors, biocides,
lubricants, additives for acid treatment, cross linking agents,
chemicals to treat acid gases, tracers, gel forming polymers and
the like. One non-restrictive example is a polymer nanoparticle
that cleaves into two subgroups or moieties, one or both of which
have useful functionality. Examples of degradable nanoparticles may
be found in U.S. Patent Application 2005/0196343 A1 which relates
to methods of producing polymeric degradable nanoparticles used in
drug and agent delivery, as well as imaging and diagnosis. This
patent is incorporated by reference herein in its entirety.
[0034] In one sense, drilling fluids have made use of nanoparticles
for many years, since the clays commonly used in drilling muds are
naturally-occurring, 1 nm thick discs of aluminosilicates. Such
nanoparticles exhibit extraordinary rheological properties in water
and oil. However, in contrast, the nanoparticles that are the main
topic herein are synthetically formed nanoparticles where size,
shape and chemical composition are carefully controlled.
[0035] It is known to modify nanoparticles, particularly carbon
nanotubes, to introduce chemical functional groups thereon,
particularly on the outer surface of the nanotube, for instance by
reacting the nanotube with a peroxide such as diacyl peroxide to
add acyl groups which are in turn reacted with diamines to give
amine functionality, which may be further reacted. Covalent
functionalization includes, but is not necessarily limited to,
oxidation and subsequent chemical modification of oxidized
nanotubes, fluorination, reactions of fluoronanotubes, free radical
additions, addition of carbenes, nitrenes and other radicals,
arylamine attachment via diazonium chemistry, and the like. Besides
covalent functionalization, chemical functionality may be
introduced by noncovalent functionalization, .pi.-.pi. interactions
and polymer interactions, such as wrapping a nanotube with a
polymer, direct attachment of reactants to carbon NT sidewalls by
attacking the sp.sup.2 bonds, direct attachment to open ends of
nanotubes or to the edges of a cleaved or split nanotubes, and the
like.
[0036] The drilling fluids herein, which may include completion
fluids, except as noted, may contain nanoparticles which
beneficially affect the properties of the drilling fluid, and in
some cases may change the properties of the drilling fluids in
which they reside, based on various stimuli including, but not
necessarily limited to, temperature, pressure, pH, chemical
composition, salinity, and the like. Such fluids are sometimes
termed "smart fluids". This is due to the fact that the
nanoparticles can be custom designed on an atomic level to have
very specific functional groups, and thus the nanoparticles react
to a change in surroundings or conditions in a way that is
beneficial. It should be understood that it is expected that
nanoparticles may have more than one type of functional group,
making them multifunctional. Multi-functional nanoparticles may be
useful for simultaneous applications, in a non-limiting example of
a drilling fluid, lubricating the bit, stabilizing the shale while
drilling and provide low shear rate viscosity. In another
non-restrictive embodiment, nanoparticles suitable for stabilizing
shale include those having an electric charge that permits them to
associate with the shale.
[0037] Such drilling fluids are expected to have surfactants, such
as surfactants and/or polymers present and interacting with the
nanoparticles to help the fluids achieve these goals. Such fluids
are expected to find uses in fluid flooding, reservoir conformance,
and completion fluids. Designing specific hydrophobic or
hydrophilic character into such drilling fluids, such as through
the use of novel organic chemistry on the surface of the very high
surface area functionalized nanoparticles is expected to
significantly alter the operating and organizing of water floods,
surfactant floods, stabilizing drilling fluids, fluids to change
the wettability of surfaces downhole, stabilizing drilling fluids,
and the like. Drilling fluids containing such carefully designed
nanoparticles are expected to either block or increase the porosity
of the formations into which they are injected. Such engineered
nanoparticles, e.g. nanocrystalline materials, in these drilling
fluids are expected to increase drilling speeds through
subterranean formations and decrease the wear of drilling parts
significantly.
[0038] It may be helpful in designing new drilling fluids
containing engineered nanoparticles to match the nanoparticle type
with the proper surfactant to achieve dispersion for the particular
drilling fluid. Surfactants are generally considered optional, but
may be used to improve the quality of the dispersion, e.g. a
dispersion of barite or magnesium oxide nanoparticles. Ways of
dispersing colloidal-size particles in drilling fluids is known,
but how to disperse nanoparticles at the low shear rate viscosities
experienced by drilling fluids may be a challenge, that is, how to
disperse nanoparticles with little or no shear, except when they
are subject to high shear when ejected through jets in the drill
bit. Expected suitable surfactants include, but are not necessarily
limited to non-ionic, anionic, cationic and amphoteric surfactants
and blends thereof. Suitable nonionic surfactants include, but are
not necessarily limited to, alkyl polyglycosides, sorbitan esters,
methyl glucoside esters, amine ethoxylates, diamine ethoxylates,
polyglycerol esters, alkyl ethoxylates, alcohols that have been
polypropoxylated and/or polyethoxylated or both. Suitable anionic
surfactants selected from the group consisting of 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. Suitable cationic surfactants
include, but are not necessarily limited to, arginine methyl
esters, alkanolamines and alkylenediamides. Suitable surfactants
may also include surfactants containing a non-ionic spacer-arm
central extension and an ionic or nonionic polar group. Other
suitable surfactants are dimeric or gemini surfactants and
cleavable surfactants.
[0039] It is also anticipated that combinations of certain
surfactants and nanoparticles will "self-assemble" into useful
structures, similar to the way certain compositions containing
surfactants self-assemble into liquid crystals of various different
structures and orientations. It is expected that nanotubes will
align along the director of the micelle forming the liquid crystal
phase. Further details may be found in Lagerwall and Scalia.
"Carbon Nanotubes in Liquid Crystals", J. Mater. Chem., 2008, 18,
2890-2898, incorporated herein by reference in its entirety.
[0040] In one non-limiting example a drilling fluid containing
nanoparticles is expected to be useful to stabilize the wellbore
during drilling, particularly the shale regions encountered during
drilling which may contain areas that tend to slough into the
borehole or have clays which undesirably swell when contacted with
water introduced as part of the drilling fluid. Such a drilling
fluid may be an aqueous-based fluid such as a WBM, a non-aqueous
based fluid such as an OBM or SBM, or a combination thereof, namely
an emulsion. A surfactant may be present in an amount effective to
suspend the nanoparticles in the fluid. Nanoparticles expected to
be useful in such shale stabilizing fluids are those which contain
functionalities that associate with the shale and help keep it in
its original condition or as close to its original condition as
possible, that is strengthen the borehole wall. Nanoparticles
having a surface charge may assist with this shale stabilization,
such as carbon nanotubes. Further, the small size of the
nanoparticles permits them excellent access to the shale matrix to
inhibit both the external and internal surfaces of clays to
minimize damage to the structure of the shale. Such nanoparticles
include, but are not necessarily limited to, carbon nanotubes, such
as single wall and multiwall carbon nanotubes (SWNTs and MWNTs)
which have been chemically reacted to bear functional groups
including, but not necessarily limited to, SH, NH.sub.2, NHCO, OH,
COON, F, Br, Cl, I, H, R--NH, R--O, R--S, CO, COCl and SOCl, where
R is selected from the group consisting of low molecular weight
organic chains with a carbon number on average but not necessarily
limited to 10 or less. Other nanoparticles for shale stabilization
include, but are not necessarily limited to, carbon nanotubes,
functionalized carbon nanotubes, deformable polymer latex
nanoparticles selected from a group including, but not limited to,
polyethylene, polymethyl methacrylate, carboxylated
styrene/butadiene copolymer, polyvinylacetate copolymer, polyvinyl
acetate/vinyl chloride/ethylene copolymer, polyvinyl acetate/
ethylene copolymer, natural latex, polyisoprene,
polydimethylsiloxane and mixtures thereof. The amount of
nanoparticles in such shale-stabilizing fluids may range from about
5 ppm to about 150,000 ppm, and from about 5 ppm to about 50,000
ppm in an alternate non-limiting embodiment. Surfactants useful to
suspend such nanoparticles in shale stabilizing fluids include, but
are not necessarily limited to those previously identified. Such
surfactants may be present in the drilling fluids in amounts from
about 10 ppm to about 100,000 ppm. Improving the stability of deep
wellbores that experience HTHP conditions is particularly
important.
[0041] Drilling fluids containing certain nanoparticles and/or
nanofibers are also expected to have improved electrical
conductivity. In this application, nanofibers are expected to be
useful where the nanofibers have an average cross-sectional
dimension of less than 100 nm but have an average particle length
of several times its cross-sectional dimension. In one
non-restrictive version, the average particle length is at least
five times the cross-sectional dimension, alternatively at least 10
times the cross-sectional dimension. In some cases, it is easier to
manufacture nanofibers of relatively long length than particulates
which are of nanoscale in all dimensions. For small contents of
nanofibers, the electrical conductivity of the fluid slowly
increases with increasing the content of nanofiber in the fluid. At
the percolation limit, the nanofibers are expected to associate in
such a way as to form electrically conductive pathways in the
drilling fluid, resulting in a fast increase in conductivity.
Suitable materials for nanofibers to improve conductivity include,
but are not necessarily limited to carbon, graphite, graphitized
carbon, coated nanofibers, polyaniline composites, functionalized
carbon nanotubes. Nanofibers, such as carbon nanotubes which can
bear an electrical charge are expected to improve the conductivity
of the drilling fluids. Enhanced electrical conductivity drilling
fluids may form an electrically conductive filter cake that highly
improves real time high resolution log while drilling processes, as
compared with an otherwise identical fluid absent the
nanoparticles.
[0042] Suitable materials for nanofibers may be used to modify
electrical conductivity. Modifying electrical conductivity includes
both improving electrical conductivity and improving electrical
resistivity. Such materials for modifying electrical conductivity
include, but are not necessarily limited to carbon, graphite,
polyaniline composites, functionalized carbon nanotubes. The amount
of nanofibers in a drilling fluid to modify the electrical
conductivity of the fluid may range from about 5 ppm to about
150,000 ppm alternatively from about 5 ppm to about 50,000 ppm.
Surfactants useful to include in drilling fluids to improve the
conductivity or resistivity thereof are expected to include, but
not necessarily be limited to, non-ionic, anionic, cationic and
amphoteric surfactants and blends thereof, and may be expected to
be present in amounts of from about 10 ppm to about 100,000
ppm.
[0043] Coated nanofibers include, but are not necessarily limited
to, the above-noted nanofibers coated with one or more materials
including, but not necessarily limited to, metal oxide, copper,
aluminum, zinc, titanium, polymers, stimuli responsive polymers,
surfactants, conducting fluids, hydrophilic agents, hydrophobic
agents, and combinations thereof.
[0044] Nanoparticles are also expected to be able to stabilize
drilling fluids over a wide range of temperature and/or pressure
conditions, including the HTHP environments of very deep wells, and
at proportions much less than current stability additives. By
stabilizing the drilling fluids is meant keeping the rheology of
the fluid the same, such as the viscosity of the fluid, over these
ranges. In one non-limiting embodiment the temperature range is
from about 175.degree. C. independently to about 320.degree. C.;
alternatively from about 175.degree. C. independently to about
275.degree. C. Similarly, in another non-restrictive version, the
pressure may range from about 100 MPa independently to about 350
MPa; alternatively from about 100 MPa independently to about 240
MPa. As used herein with respect to ranges, the term
"independently" means that any lower threshold may be combined with
any upper threshold to give a suitable alternative range.
[0045] Nano size colloidal particles may act as an emulsion
stabilizer if they are adsorbed to a fluid-fluid interface, and
promote emulsion stabilization. The type of emulsion obtained would
depend on the wettability of the particles at the oil/water
interface. The stabilization mechanism works via a viscoelastic
interfacial film formed by the small particles residing at the
oil/water interface, reducing drainage and rupture of the film
between droplets. The degree of stabilization would depend on the
particle detachment energy which is related to the free energies
involved in removing an adsorbed nanoparticle from the interface.
In one non-limiting embodiment the stabilization of the emulsion
forming the drilling fluid may involve surfactant-induced
nanoparticle flocculation and synergy between the surfactant and
the nanoparticles as described by Binks, et al., "Synergistic
Interaction in Emulsions Stabilized by a Mixture of Silica
Nanoparticles and Cationic Surfactant", Langmuir 2007, 23,
3626-3636 and Binks and Rodrigues, "Enhanced Stabilization of
Emulsions Due to Surfactant-Induced Nanoparticle Flocculation",
Langmuir 2007, 23, 7436-7439, both incorporated herein by reference
in their entirety. In one non-limiting embodiment, the drilling
fluid would be stable at temperatures up to 370.degree. C. and over
a pressure range of about atmospheric pressure up to about 350 MPa.
Suitable nanoparticles for this application include, but are not
necessarily limited to, those which can carry a charge, as well as
those with functional groups including, but not necessarily limited
to, hydrophilic groups and/or hydrophobic groups, etc. It is
expected that the proportions of such nanoparticles useful to
impart stability may range from about 5 to about 150,000 ppm;
alternatively from about 5 to about 50,000 ppm. These drilling
fluids would be more stable than otherwise identical fluids absent
the nanoparticles. Particular nanoparticles useful to stabilize
emulsions include, but are not necessarily limited to, carbon
nanotubes, functionalized carbon nanotubes, deformable polymer
latex, nanoparticles such as but not limited to magnesium oxide,
barium sulfate and polydimethylsiloxane and combinations
thereof.
[0046] It is further expected that drilling fluids containing
certain kinds of nanoparticles would have improved drag reduction
(reduced frictional fluid flow) as compared with such drag reducing
fluids without nanoparticles. This drag reduction behavior may be
similar to that provided by certain very high molecular weight
polymers, although different polymers are used respectively for
aqueous fluids and non-aqueous fluids. The drag reducing mechanism
may be such that the nanoparticles roll within the fluid in the
contact regions changing and/or sliding into more efficient
rolling-friction configurations, patterns or structures at the
nanoscale. Another probable mechanism includes an enhanced
adhesion-film between the sliding surfaces preventing direct
contact of the surfaces and reducing the frictional force between
the surfaces. It would thus be expected that different
nanoparticles may be useful for different fluid types, however,
multifunctional nanoparticles may be particularly useful to reduce
the drag of emulsions containing both oil and water. Very long
nanofibers, that is, those which have average diameters of less
than 100 nm, but which are much longer than 100 nm, for instance on
the order of about 2,000 to about 5,000 nm may thus provide a drag
reducing effect analogous to polymers. Drag reducing polymers are
generally in the range of about 40 nm long. Narrow nanoribbons or
nanostrips may also provide such an effect. Nanoparticles suitable
to provide drag reduction include, but are not necessarily limited
to, carbon-based nanoparticles, metallic-based nanoparticles
including Ni-based nanoparticles, and those nanoparticles with
functional groups selected from the group including, but not
limited to, SH, NH.sub.2, NHCO, OH, COON, F, Br, Cl, I, H, R--NH,
R--O, R--S, CO, COCl and SOCl, where R is as defined above. It is
expected that the proportions of such nanoparticles useful to
improve drag may range from about 5 to about 150,000 ppm;
alternatively from about 5 to about 50,000 ppm.
[0047] As described, many drilling fluids are emulsions, such as
O/W or W/O emulsions. It is important that these emulsion drilling
fluids maintain their emulsion properties during their use.
Surfactants or combinations of surfactants with cosurfactants are
often used in conventional emulsion drilling fluids to stabilize
them. However, it is expected that dual or multifunctional
nanoparticles could also provide this emulsion stabilizing effect
in a much lower proportion. The nanoparticles may have both
hydrophilic and hydrophobic groups and provide greater stability as
compared with the case where nanoparticles are not used in an
otherwise identical fluid, or the case where conventional
stabilizers are used in an otherwise identical fluid in the same
proportion as the nanoparticles. Other nanoparticles believed to be
useful in changing the wettability of downhole surfaces include,
but are not necessarily limited to, magnesium oxide, block
copolymers described in U.S. Patent Application Publication No.
2006/0205827 incorporated herein by reference in its entirety,
functionalized nanoclays, silicates and aluminas described in U.S.
Patent Application Publication No. 2005/0115462 and the like and
combinations thereof. It is expected that the proportions of such
nanoparticles useful to impart emulsion stability may range from
about 5 to about 100,000 ppm; alternatively from about 5 to about
50,000 ppm. Nanoparticles suitable to reverse the wettability of
downhole materials may include, but are not necessarily limited to
those having a size less than 999 nm, and may be silica, magnesium
oxide, iron oxide, copper oxide, zinc oxide, alumina, boron, carbon
black, graphene, carbon nanotubes, ferromagnetic nanoparticles,
nanoplatelets, surface modified nanoparticles; which may be
optionally functionalized with functional group including, but not
necessarily limited to, sulfonate, sulfate, sulfosuccinate,
thiosulfate, succinate, carboxylate, hydroxyl, glucoside,
ethoxylate, propoxylate, phosphate, ethoxylate, ether, amines,
amides and combinations thereof.
[0048] Nanoparticles that are bifunctional have been termed "Janus"
particles because they may be of platelet shape where the
functional groups on one side are hydrophobic and the functional
groups on the other side are hydrophilic. This bifunctionality is
expected to exist with other nanoparticles such as carbon SWNTs or
MWNTs where one end of the tube has primarily or exclusively
hydrophobic functional groups and the other end of the tube has
primarily or exclusively hydrophilic functional groups. Such
bifunctional nanoparticles, as well as nanoparticles which carry a
charge, are expected to be useful to change the wettability of
surfaces downhole, such as filter cakes, drill cuttings, wellbore
surfaces, deposits which cause stuck pipe (primarily filter cakes,
but other deposits may also cause problems). Such wettability
changes, for instance from oil-wet to water-wet are useful to
remove damage (e.g. near wellbore damage) and other structures
downhole (e.g. filter cakes), and release stuck pipe. Such
bifunctional nanoparticles may be used alone or together with
conventional surfactants, co-surfactants and/or co-solvents. It is
expected that the proportions of such nanoparticles useful to
change the wettability of surfaces downhole may range from about 5
to about 100,000 ppm; alternatively from about 5 to about 50,000
ppm.
[0049] It is also expected that other tools, tubular goods and
equipment downhole may have their resistance to corrosion improved
by nanoparticle additives to the drilling fluid used. Indeed, there
may be a beneficial reaction, association or correspondence with
certain tubular and/or tool surfaces and nanoparticles in the
drilling fluid, such as through a charge on the nanoparticles, as
previously discussed, or by the presence of certain functional
groups on the nanoparticle. It would be useful if such corrosion
resistance improvement methods could be applied to current
metallurgies, including, but not necessarily limited to, stainless
steel, duplex steel, chrome steel, martensitic alloy steels,
ferritic alloy steels, austenitic stainless steels,
precipitation-hardened stainless steels, high nickel content
steels, and combinations thereof, as well as be applicable to
metallurgies to be developed in the future. Useful nanoparticles
for improving corrosion resistance include, but are not necessarily
limited to, oxides of aluminum, silicon, scandium, titanium,
yttrium, zirconium, niobium, lanthanum, hafnium, tantalum or
thorium or other rare-earth elements). In this non-limiting
embodiment the nanoparticles may include, but not necessarily
limited to, scavenger materials for oxygen, hydrogen sulfide
(H.sub.2S), carbon dioxide, carbonyl sulfide (COS), hydrogen
cyanide (HCN), carbon disulfide (CS.sub.2) and mixtures thereof. It
is additionally expected that the proportions of such nanoparticles
useful to improve the corrosion resistance of downhole tools and
tubular goods may range from about 5 to about 100,000 ppm;
alternatively from about 5 to about 20,000 ppm.
[0050] It is additionally expected that fluids may contain
nanoparticles which are nanocapsules that contain useful materials
that may be delivered at a remote location, such as downhole.
Again, the nanoparticles may have an average particle size less
than 999. Suitable nanoparticles include, but not limited to,
nano-silica, magnesium oxide, nano-iron oxide, nano-copper oxide,
nano-zinc oxide, nano-alumina, nano-boron, carbon black,
nano-graphene, carbon nanotube, ferromagnetic nanoparticles,
nanoplatelets, surface-modified nanoparticles, halloysite clay
nanotubes, polymer-based degradable nanoparticles, nanocapsules,
multistimuli-responsive nanospheres, core/shell nanoparticles and
combinations thereof. In particular core/shell nanoparticles and
other structures may contain encapsulated additives including, but
not necessarily limited to, wax and asphaltene inhibitors, shale
stabilizers, corrosion inhibitors, rate of penetration (ROP)
enhancers, scale inhibitors, hydrate inhibitors, biocides,
lubricants, additives for acid treatment, cross linking agents,
chemicals to treat acid gases, tracers, gel forming polymers and
the like. Controlling the delivery of the additive downhole or in a
subterranean formation and its distribution both in space and time
aims to increase the additive overall efficacy embodies both
controlling the rate of release as well as the triggering release
mechanism which includes, but is not necessary limited to, changes
of pH, temperature, electrolyte type or concentration, or
application of a magnetic field or electromagnetic field and/or
combinations thereof. Further information about core/shell
particles on a nano-scale may be had with reference to A. Kazemi,
et al., "Environmentally Responsive Core/Shell Particles via
Electrohydrodynamic Co-jetting of Fully Miscible Polymer
Solutions," Small, 2008, Volume 4, No. 10, pp. 1756-1762,
incorporated by reference herein in its entirety. Drug delivery
methods using silica nanoparticles have been described by C. Barbe
et al. in "Silica Particles: A Novel Drug-Delivery System", Adv.
Mater., Oct. 18, 2004, Vol. 16, No. 20, pp. 1-8, incorporated by
reference herein in its entirety since such methods are expected to
be applicable to delivering an agent or material downhole at a
remote location.
[0051] It should also be recognized that other useful materials may
be included in the nanocapsules, including, but not necessarily
limited to, the nanoparticles effective to stabilize shale, the
nanofibers effective to modify electrical conductivity, the
nanoparticles effective to stabilize drilling fluid rheology, the
nanoparticles effective to improve drag reduction, the
nanoparticles effective to improve emulsion stability, the
nanoparticles effective to reverse wettability, the nanoparticles
effective to inhibit or prevent corrosion, the nanoparticles
effective to prevent fluid loss, the nanoparticles effective to
improve lost circulation, the nanoparticles effective to inhibit or
prevent water flow, all as described elsewhere herein.
[0052] In another application, nanoparticles may encapsulate
corrosion inhibitors and release the corrosion inhibitor when the
nanoparticle is exposed to a triggering event or environment. Again
such nanoparticles may have a size less than 999 nm, and may
include, but are not limited to, nano-silica, magnesium oxide,
nano-iron oxide, nano-copper oxide, nano-zinc oxide, nano-alumina,
nanoboron, carbon black, nano-graphene, carbon nanotube,
ferromagnetic nanoparticles, nanoplatelets, surface-modified
nanoparticles, halloysite clay nanotubes, polymer-based degradable
nanoparticles, nanocapsules multistimuli-responsive nanospheres,
core/shell nanoparticles and combinations thereof. The encapsulated
corrosion inhibitors may include, but are not necessarily limited
to, scavenger materials for oxygen, hydrogen sulfide (H.sub.2S),
carbon dioxide, carbonyl sulfide (COS), hydrogen cyanide (HCN),
carbon disulfide (CS.sub.2), and mixtures thereof. The encapsulated
corrosion inhibitor is released when the nanoparticle is subjected
to a specific triggering mechanism providing a self-healing
corrosion protection. Suitable triggering mechanisms include, but
are not necessary limited to, changes of pH, temperature,
electrolyte type or concentration, or application of a magnetic or
electromagnetic field. U.S. Patent Application Publication No.
2009/0078153 describes corrosion inhibiting pigments comprising
nanoreservoirs of corrosion inhibitor. The corrosion inhibitor is
released upon the action of a trigger. This publication is
incorporated by reference herein in its entirety.
[0053] Completion fluids are also expected to benefit from the
presence of nanoparticles within them. Completion fluids generally
do not contain solids, however, because of the extremely small size
of nanoparticles, their presence may be tolerated in low
proportions while still imparting an improvement in a property or
properties to the completion fluid. For instance, improvements in
fluid loss and viscosity of clear brines may help seal off
permeability without the formation of a filter cake in the usual
way that "filter cake" is understood. For instance, it is expected
that an internal structure, that is, in the near wellbore region,
not a "cake" on the wellbore surface, formed from drilling solids
and nanoparticles, without otherwise added solids, may usefully
serve to regulate permeability. Because of the small size of the
nanoparticles, they may pass through the pores of the near wellbore
region to form an internal structure that regulates permeability.
The electrical or other forces that hold them together would create
a structure that regulates permeability. Similarly, once those
forces are disrupted and the permeability control is no longer
needed, the nanoparticles may be readily produced back from the
near wellbore region due to their small size. Because of the much
greater surface area of nanoparticles compared to micron-sized and
larger particles, only about 1 ppg (0.12 kg/liter) of nanoparticles
may do the job of 10 ppg (1.2 kg/liter) of other analogous
materials. The reduced solid volumes with increased surface area
would thus help maintain equivalent viscosities of such completion
fluids.
[0054] Nanoparticles expected to be useful components of completion
fluids include, but are not necessarily limited to nano-silica,
nano-alumina, nano-zinc oxide, nano-boron, nano-iron oxide,
zeolites carbonates, piezoelectric crystals, pyroelectric crystals
and combinations thereof (see U.S. Pat. No. 7,559,369 and U.S.
Patent Application Publication No. 2009/0312201 A1, both
incorporated herein by reference in their entirety). It is expected
that the proportions of such nanoparticles useful to provide
beneficial properties to completion fluids may range from about 5
to about 150,000 ppm; alternatively from about 5 to about 50,000
ppm.
[0055] It is additionally expected that nanoparticles may serve as
lost circulation additives in drilling fluids, either alone or
together with conventional additives such as carbonates, barite,
ilemite, manganese tetroxide, manganous oxide, magnesium oxide,
etc. when such conventional additives are sized as normally, but
also when reduced to nano-scale sizes where they may be more
effective. That is, new materials, alone or together with
conventional materials, whether of conventional size or of a
nanoscale size may be suitable lost circulation additives because
of how they may associate with each other and other structures
(such as the wellbore wall) downhole, either by electrical charge
or other surface interaction due to their inherent properties or
due to certain functional groups on the surfaces thereof. In
non-limiting examples, nano-sized calcium carbonate or nano-sized
barite may be employed. Fibers of either nano-scale and/or
conventional scale may also usefully connect, associate or bond
with these materials reduce fluid losses. Associations formed in
this way may form useful plugs. The potential to form a thin,
non-erodible and largely impermeable structure similar in function
to a filter cake with well-dispersed and tightly packed "fabric"
and structural nanoparticles, nanoparticle-based fluids may be
expected to eliminate or reduce the scope of reservoir damage while
improving well productivity. Because of the large surface area to
volume ratio of nanoparticles in these structures, cleaning
compositions and methods used before completing a well may remove
these structures easily from the borehole wall by permitting
intensive interactions with the drilling fluid. Thus, the
contradictory requirements of a structure that prevents loss of
fluid into the reservoir during drilling, but which is easily
removable before completion is particularly advantageous for
drilling fluids containing nanoparticles. Stated another way,
properly designed and engineered nanoparticles have the potential
to build structural barriers according to the size and shape of the
fluid loss paths are expected to provide effective sealing of the
porous and permeable zones, and naturally fractured formations.
Multifunctional nanoparticles may possess both sealing and
strengthening potential, which is expected to reduce the scope of
induced lost circulation.
[0056] Other new potential nanoparticles useful as lost circulation
additives include, but are not necessarily limited to,
nanoparticles physically or chemically bonded to porous or
non-porous microparticles (particle size greater than 100 nm),
which may impart some properties of the nanoparticles onto the
microparticles. Functional groups on nano-sized particles expected
to be useful to prevent lost circulation include, but are not
necessarily limited to, nano-silica, nano-alumina, nano-zinc oxide,
nano-boron, nano-iron oxide, zeolites carbonates, piezoelectric
crystals, pyroelectric crystals and combinations thereof (again
please see U.S. Pat. No. 7,559,369 and U.S. Patent Application
Publication No. 2009/0312201 A1), as well as encapsulated
nanoparticles. It is expected that the proportions of such
nanoparticles useful to improve lost circulation may range from
about 5 to about 100,000 ppm; alternatively from about 5 to about
50,000 ppm.
[0057] In another non-restrictive embodiment nanoparticles may be
used to encapsulate or otherwise incorporate a gel-forming
additive. Suitable nanoparticles include, but are not necessarily
limited to, nano-silica, nano-barium sulfate, nano-magnesium oxide,
nano-iron oxide, nano-copper oxide, nano-zinc oxide, nano-alumina,
nano-boron, carbon black, nano-graphene, carbon nanotube,
ferromagnetic nanoparticles, nanoplatelets, surface-modified
nanoparticles, halloysite clay nanotubes, polymer-based degradable
nanoparticles, nanocapsules multistimuliresponsive nanospheres,
core/shell nanoparticles and combination thereof. The nanoparticles
present in the fluid may contain encapsulated or incorporated a gel
forming additive including but not limited to polyacrylamide,
crosslinking agents, in situ crosslinkable polymer, superabsorbent
polymers and the like that are released by applying a triggering
mechanism which includes but is not necessary limited to changes of
pH, temperature, electrolyte type or concentration, or application
of a magnetic or electromagnetic field. Once triggered, the
encapsulated gel forming additive would be released and be
permitted to function, for instance to be active to form gel with
increased volume on contact with water, hydrate and expand in the
presence of formation water, thus plugging the pores and blocking
water movement. Such materials would conversely dehydrate and
shrink when they contacted oil, hence allowing the oil to flow
preferential to any water flow. Generally, such an application
where oil is permitted to selectively flow while formation water is
inhibited or prevented may be termed "water shutoff".
[0058] Shallow water flow problems associated with deep water
drilling may also be addressed using nanoparticles. Due to their
small size, these particles may easily pass through the pores and
inter-granular boundaries of the shallow water flow sand zone and
the porous and permeable matrix of the shallow water flow sand.
Thus, engineered nanoparticles with gluing, sealing, filling and
cementation properties are expected to increase the inter-granular
bond strength, reduce porosity and permeability of the near
wellbore formations with a drastic increase in tearing and shearing
resistance of the particles in the shallow water flow zone. Such
engineered nanoparticles would be expected to reduce the matrix
flow potential of the shallow water flow zone due to effective
sealing of the near-wellbore zone. Due to the inter-particle
bonding and matrix strengthening effect of the nano fluid to the
near-wellbore shallow water flow zone, it is also expected to
improve the borehole and sea bed equipment stability used in
offshore drilling and production. However, in one non-limiting
embodiment the drilling fluids or completion fluids have an absence
of cement nanoparticles.
[0059] These properties of nanoparticles may also be understood to
consolidate unconsolidated formations to form bonded networks of
particles within the formation to create an integrated ring of rock
mass around the borehole wall. Such a nanoparticle-enhanced rock
cylinder in the near wellbore region may tolerate much higher
in-situ stresses to avoid collapse as well as undesirable
fracturing of the formation.
[0060] The invention will now be illustrated with respect to
certain examples which are not intended to limit the invention in
any way but simply to further illustrate it in certain specific
embodiments.
[0061] EXAMPLE 1
[0062] Although different from the methods described herein, the
effectiveness of adding latex nanoparticles to water based muds in
controlling pore pressure transmission and therefore enhancing near
wellbore region tolerance to higher in-situ stresses and wellbore
strengthening are reported in U.S. Pat. No. 6,703,351 incorporated
herein by reference in its entirety. The drilling fluids as
described herein do not require and have an absence of a
precipitating agent recited in U.S. Pat. No. 6,703,351.
[0063] Shown in FIG. 1 is a graph comparison of the pore pressure
transmission performances for two water-based fluid systems with
and without added nanoparticles (Formulation A and B respectively).
The formulations are set out in Table I. The experiment simulates
downhole rock stress and overbalance fluid pressure conditions and
it shows the effectiveness of the added nanoparticles in
controlling pore pressure transmission and therefore enhancing near
wellbore region tolerance to higher in-situ stresses and wellbore
strengthening.
TABLE-US-00001 TABLE 1 Formulations of Water-Based Fluid Systems
with and without Added Nanoparticles Products Formulation A
Formulation B Water, bbl (liters) 0.81 (129) 0.81 (129) Viscosifier
Agent, lb/bbl (grams/liter) 0.5 (1.4) 0.5 (1.4) Shale control
agent/Viscosifier, lb/bbl 0.5 (1.4) 0.5 (1.4) (grams/liter) Fluid
loss control agent, lb/bbl 4 (11.4) 4 (11.4) (grams/liter) Shale
stabilizer, lb/bbl (grams/liter) 5 (14.3) 5 (14.3) Antiflocculat,
lb/bbl (grams/liter) 2 (5.7) 2 (5.7) NaCl, lb/bbl (grams/liter) 73
(209) 73 (209) Nanoparticles with an average size -- 3 of 300 nm,
vol %
[0064] In the foregoing specification, the invention has been
described with reference to specific embodiments thereof, and has
been suggested as effective in providing effective methods and
compositions for improving drilling fluids and completion fluids
used in drilling and completing subterranean reservoirs and
formations. However, it will be evident that various modifications
and changes may be made thereto without departing from the broader
spirit or scope of the invention as set forth in the appended
claims. Accordingly, the specification is to be regarded in an
illustrative rather than a restrictive sense. For example, specific
combinations of components and/or reaction conditions for forming
the nanoparticles, whether modified to have particular shapes or
certain functional groups thereon, but not specifically identified
or tried in a particular drilling or completion fluid to improve
the properties therein, are anticipated to be within the scope of
this invention. Further, specific combinations of fluids,
nanoparticles, surfactants and other components different than
those described or exemplified are expected to be within the scope
of the methods and compositions herein, as set encompassed in the
appended claims.
[0065] The present invention may suitably comprise, consist or
consist essentially of the elements disclosed and may be practiced
in the absence of an element not disclosed. For instance, the
drilling fluid may consist of or consist essentially of the base
fluid and nanoparticles, as further defined in the claims.
Alternatively, the drilling fluid may consist of or consist
essentially of the base fluid, the nanoparticles and a surfactant,
as further defined in the claims. In each of these examples, the
drilling fluid may contain conventional additives.
[0066] The words "comprising" and "comprises" as used throughout
the claims is to be interpreted as meaning "including but not
limited to".
* * * * *
References