U.S. patent application number 13/425620 was filed with the patent office on 2012-07-05 for method for intervention operations in subsurface hydrocarbon formations.
This patent application is currently assigned to ILLINOIS INSTITUTE OF TECHNOLOGY. Invention is credited to David L. Holcomb, Alex D. Nikolov, Darsh T. Wasan.
Application Number | 20120168165 13/425620 |
Document ID | / |
Family ID | 41382312 |
Filed Date | 2012-07-05 |
United States Patent
Application |
20120168165 |
Kind Code |
A1 |
Holcomb; David L. ; et
al. |
July 5, 2012 |
METHOD FOR INTERVENTION OPERATIONS IN SUBSURFACE HYDROCARBON
FORMATIONS
Abstract
Nanoparticles are added to a fluid containing a wetting agent to
enhance wetting of solid surfaces in and around the well and
removing a water-block from the well. The wetting agent and
nanoparticles combine to produce a wetting of the surfaces of the
rock that allows recovery of the excess water near the well (water
block).
Inventors: |
Holcomb; David L.; (Golden,
CO) ; Wasan; Darsh T.; (Darien, IL) ; Nikolov;
Alex D.; (Chicago, IL) |
Assignee: |
ILLINOIS INSTITUTE OF
TECHNOLOGY
Chicago
IL
FTS INTERNATIONAL SERVICES, LLC
Fort Worth
TX
|
Family ID: |
41382312 |
Appl. No.: |
13/425620 |
Filed: |
March 21, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
12579947 |
Oct 15, 2009 |
|
|
|
13425620 |
|
|
|
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Current U.S.
Class: |
166/305.1 ;
977/773 |
Current CPC
Class: |
C09K 8/536 20130101;
C09K 8/70 20130101; C09K 8/92 20130101; C09K 8/74 20130101; C09K
2208/10 20130101 |
Class at
Publication: |
166/305.1 ;
977/773 |
International
Class: |
E21B 43/16 20060101
E21B043/16 |
Claims
1. A method for removal of water block around a well, comprising:
providing an aqueous or hydrocarbon fluid; adding nanoparticles and
a wetting agent to the aqueous or hydrocarbon fluid; injecting the
fluid and additives into the well; and producing a fluid from the
well.
2. The method of claim 1 wherein die wetting agent is an
alpha-olefin sulfonate.
3. The method of claim 1 wherein the wetting agent is selected from
the group consisting of ethoxylated nonyl phenol, sodium stearate,
sodium dodecyl sulfate, sodium dodecylbenzene sulfonate,
lauralamine hydrochloride, trimethyl dodecylammonium chloride,
cetyl trimethylammonium chloride, polyoxyethylene alcohol,
alkyphenolethoxylate, Polysorbate 80, propylene oxide modified
polymethylsiloxane, dodecyl betaine, lauramidopropyl betaine,
cocoamido-2-hydroxy-propyl sulfobetaine, alkyl aryl sulfonate,
fluorosurfactants and perfluoropolymers and terpolymers, and castor
bean adducts.
4. The method of claim 3 wherein the alpha-olefin sulfonate has a
carbon number in the range from about 10 to about 14.
5. The method of claim 1 wherein the nanoparticles are added to a
concentration in the range from about 5% to about 20% by
weight.
6. The method of claim 1 wherein the nanoparticles are in the range
of 1-10 nanometers in size.
7. The method of claim 1 wherein the nanoparticles have a
polydispersity less than 20%.
Description
[0001] This application claims the benefit of Provisional
Application Ser. No. 61/196,507, filed Oct. 17, 2008 and U.S.
Non-Provisional application Ser. No. 12/579,947, filed on Oct. 15,
2009.
BACKGROUND OF INVENTION
[0002] 1. Field of the Invention
[0003] This disclosure relates to methods for improving
intervention operations in a subterranean formation containing
hydrocarbons and improving recovery of hydrocarbons from a
subterranean formation. More particularly, a mixture of
nanoparticles and a wetting agent for modifying solid surfaces is
added to an aqueous or hydrocarbon fluid and injected into a
well.
[0004] 2. Description of Related Art
[0005] Intervention operations in the petroleum production business
include processes
[0006] and compositions to remove unwanted deposits from a wellbore
and stimulate recovery rate of hydrocarbons from geological
formations. Processes to stimulate recovery rate include hydraulic
fracturing, acidizing and injection of surfactant compositions.
[0007] U.S. Pat. No. 7,380,606 discloses a well treatment fluid
that is a microemulsion formed by combining a solvent-surfactant
blend with a carrier fluid. In preferred embodiments, the
solvent-surfactant blend includes a solvent selected from the group
consisting of terpenes and alkyl or aryl esters of short-chain
alcohols. A preferred terpene is d-limonene. The blends may be
added to water- or oil-based carrier fluids to provide a method for
treating an oil or gas well.
[0008] U.S. App. 2008/0194430 discloses use of nanoparticles in a
well treatment fluid consisting of a gelling agent.
[0009] Scientific papers have been published showing the effects of
nanoparticles in a fluid on that fluid's spreading dynamics under
an air bubble or oil drop. For example, "Spreading of nanofluids on
solids," by D. T. Wasan and A. D. Nikolov, Nature 423, May 8, 2003,
p. 156, illustrates with photographs the mechanism for enhanced
nanofluid spreading by nanoparticles and provides calculations of
increased structural disjoining pressure of a film containing
nanoparticles. Various scientific papers have been published
showing the mechanisms of spreading of nanofluid or micellar
solutions, including "New Paradigms for Spreading of Colloidal
Fluids on Solid Surfaces," by A. V, Chengara, A. D, Nikolov and D.
T. Wasan. Adv. Polym Sci (2008) 218: 117-141.
[0010] Existing aqueous- or hydrocarbon-based intervention fluids
and treatments rely on conventional surface energy effects, such as
surface tension, irtterfacial tension, capillary pressure
reduction, solvency, and a mechanical fracturing mechanism.
However, there is a continued need for more effective methods and
processes for improved well stimulation, completion, remediation,
and recovery. In particular, there is a need for treatment fluids
that provide improved wetting of the surfaces of subsurface rocks
by aqueous fluids (or that increase the "disjoining pressure" of
the fluids) so as to allow greater flow of hydrocarbons or
treatment fluids from subsurface formations. There is also a need
for recovery fluids that provide improved wetting of the surfaces
of subsurface rocks, so as to allow greater recovery of
hydrocarbons or treatment fluids from subsurface formations.
3. BRIEF SUMMARY OF THE INVENTION
[0011] Composition and method are provided for treating wellbores
and oil and gas reservoirs so as to enhance flowback of treatment
fluids and removal of wellbore damage caused by paraffin,
asphaltenes, heavy crude, waterblock or other materials.
4. BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS
[0012] FIG. 1 illustrates the mechanism of crude oil displacement
from solid in the presence of nanofluid and wetting agent. FIG. 1a
shows the location of the wedge film and contact angle region. FIG.
1b shows details of the wedge film with the structured
nanoparticles and wetting agent.
[0013] FIG. 2 illustrates the apparatus used for observing
displacement of crude oil from a simulated 2-D pore of a rock. FIG.
2a shows an isometric front view of two spaced-apart glass slides
in a cuvette. FIG. 2b shows a side view with a camera used to
record displacement of oil by aqueous solutions.
[0014] FIG. 3 shows results of crude oil removal from a simulated
2-D pore by aqueous nanofluid test solutions.
DETAILED DESCRIPTION OF THE INVENTION
[0015] The present invention utilizes the incorporation of
colloidal particles (nanoparticles) selected from the group
consisting of silicon dioxide, zirconium dioxide, antimony dioxide,
and combinations thereof into the intervention fluid injected into
the subterranean hydrocarbon formation, reservoir or well bore. The
particles range in size from approximately 1 to 100 nanometers
(nm). It is demonstrated that die incorporation of the nanoparticle
compositions into the intervention fluid allows the fluids to
function more effectively by enabling the mechanism of structural
disjoining pressure to be exerted in addition to all of the
mechanisms noted previously, thus improving the results over the
intervention performance of existing fluid types. FIG. 1a
illustrates crude oil on a solid surface, which may be the surface
of a rock grain in a hydrocarbon reservoir. A water-oil contact
angle, .theta., exists at the points of contact of the two liquids
and the solid. A film tension gradient or the spreading force
promoted by the structural disjoining pressure (the structured
nanofluid into wedge film) for displacement of the oil from the
solid surface is illustrated. Nanoparticles tend to structure into
the wedge film between the oil and solid, indicated by an arrow.
FIG. 1b shows details of nanoparticles in the wedge, with adsorbed
wetting agent molecules indicated at the water/solid and water/oil
interfaces. The scientific papers cited below explain the basis for
increased wetting when nanoparticles are present.
[0016] The nanoparticles in the presence of the wetting agent at
concentration much below the critical micelle concentration (CMC)
in aqueous or hydrocarbon are the carrier fluids. A range of
wetting agents may be employed and may be selected from the group
consisting of ethoxylated nonyl phenol, sodium stearate, sodium
dodecyl sulfate, sodium dodecylbenzene sulfonate, lauralamine
hydrochloride, trimethyl dodecylammonium chloride, cetyl
trimethylammonium chloride, polyoxyethylene alcohol,
alkyphenolethoxylate, Polysorbate 80, propylene oxide modified
polymethylsiloxane, dodecyl betaine, lauramidopropyl betaine,
cocoamido-2-hydroxy-propyl sulfobetaine, alkyl aryl sulfonate,
fluorosurfactants and perfluoropolymers and terpolymers, and castor
bean adducts.
[0017] The use of a variety of nanoparticles dispersed in water,
oil or other solvent bases provides a mechanism to enable a lifting
force or structural disjoining pressure to improve well
intervention results arising from poor or incomplete fluid recovery
from the hydrocarbon formation, reservoir or well bore after any
well intervention procedure is performed. These interventions
include, but are not limited to, drilling, cementing, enhanced oil
recovery, water flooding, stimulation, completion or remediation.
Such nanopartiele dispersions may be mixed into any well
intervention fluid to improve removal efficiency.
[0018] Further, the nanoparticle dispersions may be placed onto the
solid materials used for well interventions, including, but not
limited to, materials used as propping agents or scouring agents
within the oil and/or gas formation during well intervention
procedures. The nanopartiele dispersions of the present invention
also may be utilized with water pumped into a water flood injection
well to facilitate improved oil and gas recovery.
[0019] Nanoparticles in the range of 1-50 nanometers may be mixed
with carbon dioxide, nitrogen or like suitable gases to form
intervention fluids. These gases, carbon dioxide (CO.sub.2) and/or
nitrogen (N.sub.2) may be mixed with water containing various
concentrations (0.1-20.0% by volume) surfactants described above
and nanoparticles including a wetting agent in the size range of
5-50 nanometers at a concentration of 0.1-3.0% by weight in aqueous
based fluids, such as water or mineral acids, to form a foamed or
non-foamed intervention fluid for enhanced/improved oil recovery,
water flooding, stimulations (acidizing and fracturing),
remediation (damage removal), completion, cementing or drilling in
oil and gas reservoirs.
[0020] Improved recovery of oil, gas, and water from a hydrocarbon
producing reservoir or well may be achieved by adding
colloidal/nanoparticle dispersions at concentrations between
approx. 0.1% and approx. 20.0% by volume to a well intervention
fluid selected from the group consisting of water, oil, hydrocarbon
solvents, bio-based alcohols, glycols, and glycol-ether based
solvents to form a colloidal/nanoparticle (CNP) intervention fluid.
This CNP intervention fluid may then be injected into the reservoir
or well to be treated to interact with well bore contaminants,
reservoir injection fluids, and produced fluids so as to
differentiate the CNP intervention fluid from the targeted fluid.
Again, it has been demonstrated that the structural disjoining
pressure (respectively the film tension) gradient by the structured
nanoparticles improves the intervention operation.
[0021] The present invention improves oil, gas, and water recovery
when
[0022] colloidal/nanoparticles ranging in size between 1-200 nm are
added as additives in the range of approximately 0.1% to approx.
20% by volume to a wetting agent to form a colloidal/nanoparticle
dispersion. The dispersion is then added at concentrations of
approx. 0.05% to approx. 30% by volume to a carrier fluid selected
from the group consisting of water-based and hydrocarbon-based oil
well stimulation, completion, remediation and recovery fluids to
form a mixed treatment fluid. This mixed treatment fluid is then
injected into a reservoir or well as an improved intervention
treatment fluid.
[0023] A preferred nanoparticle dispersion for the well
intervention fluid is an aqueous dispersion of 8.0 to 15.0 nm
silicon dioxide particles, and an anionic charged wetting agent
mixed in the water carrying the nanoparticles at 0.1-2.0% by
weight, which is an anionic member surfactant from the group
described above and the aqueous dispersion is at a pH=7.0+/-1.0.
The percentage nanoparticles in the dispersion ranges between
approximately 5% and approximately 30% by weight in the water and
surfactant mixture.
[0024] The composition of a wetting agent-nanoparticle fluid for
application in well intervention or recovery processes may be
selected for a particular hydrocarbon reservoir by placing a drop
of crude oil from that reservoir in a nanofluid (i.e., nanoparticle
dispersion in a liquid) and forming a three-phase contact region
between a solid and the oil-nanofluid phases. Particles inside the
wedge film between the crude oil and the solid form a 2-D layered
structure (caused by the entropic effect), as shown in the paper
"Spreading of Nanofluids on Solids," D. T. Wasan and A. D. Nikolov,
Nature 423, 156-159 (2003). Theory predicts that the pressure
(i.e., the structural disjoining pressure) normal to the solid
surface is higher near the tip of the wedge film, which causes the
nanofluid to spread over the solid surface, detaching the oil drop
from the solid surface. The magnitude of this pressure depends on
the effective particle volume fraction, particle size and
polydispersity, and particle charge.
[0025] The preferred nanofluid formulation comprises nanoparticles,
a wetting agent (surfactant) and a solvent. The nanoparticles
contribute to the structural disjoining pressure, while the wetting
agent reduces the contact angle and may contribute to dispersion of
the nanoparticles. In order to enhance oil and gas removal from a
rock by an aqueous fluid, the nanofluid composition may be
optimized using a multi-step process as follows:
[0026] First, select the nanoparticles, such as silica, polymers,
metal oxides, metals and other inorganic materials, based on the
reservoir characteristics. For example, for a sandstone reservoir,
silica particles are preferred. Nanoparticles are preferably
spherical, less polydisperse, low cost, have good suspension
stability in both aqueous and non-aqueous solvents under a wide
range of pH, with a charge varying from a slightly positive value
to a negative value, and are commercially available.
[0027] Preferably, the nanofluid is formulated to produce a high
osmotic pressure (e.g., higher than about 200 Pa for a 10 vol %
nanofluid). A nanofluid with a high osmotic pressure results in a
higher structural disjoining pressure. Preferably, the
nanoparticles have low polydispersity in size. (High polydispersity
results in a decreased value of the structural disjoining
pressure.) For example, calculations indicate that a 20%
polydispersity in particle size can result in a 30% decrease in the
structural disjoining pressure. But, a higher volume fraction of
nanofluid yields higher structural disjoining pressure. Therefore,
preferably the nanofluid formulation is formulated by using
nanoparticles with less than 20% polydispersity, but with a high
volume fraction (for example, 30 effective volume percent or
higher)
[0028] Preferably, the wetting characteristics of the solid surface
are enhanced by using an appropriate amount of a wetting agent in
order to maximize the role of structural force resulting from the
confinement of the nanoparticles in the wedge film.
[0029] Basic principles of formulating nanofluids for improved
wetting are described in scientific papers, such as: "Spreading of
Nanofluids on Solids," D. T. Wasan and A. D. Nikolov, Nature 423,
156-159 (2003); "New Paradigms for Spreading of Colloidal Fluids on
Solid Surfaces," Chengara, A. V., Nikolov, A. D., Wasan, D. T.,
Advances in Polymer Science Vol. 218, Narayanan, R. and Berg J.
Eds., Springer-Verlag 117-142 (2008); and "Spreading of Nanofluids
Driven by the Structural Disjoining Pressure Gradient," A.
Chengara, A. D, Nikolov, D. T. Wasan, A, Trokhymchuk and D.
Henderson, J. Colloid Interface Sci., 280, 192-201 (2004), which
are incorporated by reference herein in their entirety for all
purposes.
[0030] To apply the principles to improving an intervention process
or recovery process in a hydrocarbon reservoir, the following steps
can be used:
[0031] 1. Use a hybrid surface force apparatus, referred to as the
capillary force balance, in conjunction with reflected light
interference microscopy to measure the photo current versus time
interferogram of a thinning nanofluid (see, for example, FIG. 5 in
"Dispersion Stability Due to Structural Contributions to the
Particle Interaction as Probed by Thin Liquid Film Dynamics," A. D.
Nikolov and D. T. Wasan, Langmuir. 8, 2985-2994 (1992)). Count the
number of stepwise thickness transitions and calculate the
effective volume fraction of the dispersed nanopartiele phase (see
for example FIG. 6 of the paper).
[0032] 2. Determine the effective nanopartiele size (i.e. with
hydration layers, electrical double layers, or grafted polymers)
based on the vertical distance between the thicknesses transitions
(see FIG. 5 of the paper). The time for the thickness transitions
to occur provides information about the particle
polydispersity.
[0033] 3. Observe the nanoparticle dispersion stability, which may
be performed using a Kossel diffraction method based on the
principle of back-light scattering, to characterize the nanofluid
microstructure and dispersion stability. (See "Particle Structure
and Stability of Colloidal Dispersions as Probed by the Kossel
Diffraction Technique," W. Xu, A. D. Nikolov, D. T., Wasan, A.
Gonsalves, and R. Borwankar, J. Colloid interface Sci. 191, 471-481
(1997). The colloidal interparticle interaction impacts the
rheology of the nanofluid dispersion. The structure formation and
nanofluid stability for both nano- and poly-disperse systems can be
characterized using this experimental technique.
[0034] 4. Determine the wettability of a solid surface
representative of reservoir rock and the microscopic contact angle
using combined differential and common reflected-light
interferometric techniques for the simultaneous monitoring of the
nanofluid film (i.e., the wedge film)--meniscus profile, the
three-phase contact angle dynamics, and the wetting film thickness
transitions of the nanofluid on the solid surface. The particular
advantage of the differential interferometric method is the ability
to measure the film thickness profile in turbid and non-transparent
liquids, and in a highly curved film-meniscus surface at both
smooth and rough solid surfaces (such as a sandstone). The distance
between the interference patterns and their areas of interference
is used to calculate the local radii of the film curvature, which
in conjunction with the interfacial tension data, allows to
calculation of the capillary pressure.
[0035] The osmotic pressure of the nanofluid and the film
structural disjoining pressure may be predicted from the
experimental measurements and published theory.
[0036] Simple laboratory tests are conducted, preferably using
crude oil. A drop of crude oil is placed on a flat glass surface in
air and a nanofluid is introduced, which displaces air. A
three-phase contact line shrinks due to the lowering of the
interfacial tension between the oil and the nanofluid, and a wedge
film is formed between the oil and the glass surface. The nanofluid
penetrates between the oil and the glass surface. The formation of
the nanofluid film is seen as a bright region in reflected light
interferometry. The nanoparticle concentration in the film
increases compared to that in the bulk-meniscus. As a result of the
increase in nanoparticle concentration, the disjoining pressure
increases significantly at a wedge thickness corresponding to one
particle diameter. As a result of the pressure increase, the
oil-nanofluid interface moves forward, and the nanofluid spreads on
the solid surface, detaching the oil drop. Both the role of varying
pH and electrolyte (i.e. salinity) on the separation of an oil drop
from the glass surface in the oil detachment process is observed by
conducting a series of such experiments.
[0037] The second test method used an optical technique to monitor
crude oil removal from a two-dimensional glass pore model. A
schematic of the optical layout to monitor the crude oil removal
from the model is shown in FIG. 2. FIG. 2a illustrates two flat,
rectangular, optically smooth glass surfaces 10 that were used to
form a 2-D glass pore cell (area=2 cm.sup.2). The glass surface was
cleaned with a potassium dichromate acid solution, washed with
deionized water, and then dried at a room temperature of 25.degree.
C. for 24 hours. The 2-D pore was designed to mimic crude oil
trapped in the reservoir, allowing for the observation of the crude
oil removal dynamics. A drop of crude oil from the San Andres
formation (near Goldsmith, Tex.) was placed on the top of one of
the glass surfaces 10. The second glass surface was placed on the
top of the first. The two glass surfaces with crude between were
pressed together by two magnets (not shown), forming a 2-D glass
pore-filled with crude. The 2-D glass pore cell filled with crude
was kept at room temperature for 24 hours. The pore gap varied from
5 to 0.5 .mu.m, depending on the magnet's strength. In the
following experiments, the gap was about 2 .mu.m.
[0038] In some experiments, two identical 2-D glass pores filled
with crude were prepared and vertically placed in a separate
rectangular glass cuvette 12 containing the solution to be tested
for wetting to displace oil. A side view of slides 10 in cuvette 12
is shown in FIG. 2b. Video camera 14, having lens 16, was used to
record time-lapse photographs of displacement of the oil between
the slides. In other experiments, a Berea sandstone piece with the
shape of a parallelepiped with dimensions of 5 cm.times.1
cm.times.1 cm was saturated with the San Andres crude oil. The
sandstone piece was placed in a vertical position in a cuvette. The
sandstone was saturated with the crude oil by placing a layer of
the San Andres crude at the bottom part of the cuvette and allowing
capillary force to move the crude to the top of the sandstone
piece. The amount of crude impregnated inside the core was
estimated to be about 0.82 ml. In order for the crude to adhere to
the sandstone surfaces, the piece was soaked for two days inside a
closed glass vial before it was exposed to the fluid formulations
described below.
[0039] Solutions to be tested for their ability to displace crude
oil from the 2-D glass pores and the Berea sandstone piece were
prepared. The solutions were: [0040] Solution 1--Surfactant
solution of alpha-olefin sulfonate, ethylene glycol, isopropanol,
nonyl phenol and nonionic fluorochemical surfactant, a solvent
d-limonene, in a dilute solution of KCl [0041] Solution 2--Solution
1, plus 10% by volume silica nanoparticles having an average size
of 19 nm (Nalco 1130 from Nalco Chemical). [0042] Solution 3--A
commercially available blend of ricinoleate, d-limonene and
isopropyl alcohol microemulsion in a dilute solution of KCl.
[0043] A 2-D glass pore, made up by glass slides 10, as illustrated
in FIG. 2, was filled with San Andres crude oil and kept at room
temperature for 24 hours in order for the crude to adhere to the
glass surface. The gap between the slide surfaces of the 2-D pore
was adjusted to 2.+-.0.5 .mu.m. The slides were held together with
magnets. The cells filled with the crude were then vertically
placed in rectangular glass cuvette 12. The cuvette was filled with
Solution 1 with 0.7% KCl. The crude oil removal dynamics were
monitored and recorded with video camera 14, having lens 16. The
efficiency of the crude oil removal from the total 2-D area after
24 hours was only about 5%. This experiment revealed that even if
both the surface and interfacial tensions were reduced, Solution 1
did not perform well because the adhesion of crude oil to the glass
surface was not reduced.
[0044] The same oil removal experiment was repeated, except this
time Solution 2 was used with reservoir produced water and/or 2%
KCl in the cuvette. After 24 hours the efficiency of crude removal
from the 2-D glass pore was about 95%.
[0045] The same oil removal experiment was repeated, except this
time Solution 3 was used with 0.3% KCl. Crude oil removal dynamics
was observed and a video recorded. First, the crude oil trapped in
the corners of the apparatus was released in the form of crude oil
droplets flowing up. Then the crude trapped inside the 2-D pore
began to be released. Finally, the crude at the edge of the 2-D
pore was displaced. A recorded video clearly shows that more oil in
the form of droplets was removed faster by the Solution 2 than by
Solution 3. Results are plotted in FIG. 3. The difference in the
degree of crude oil removal became more pronounced over time,
Solution 2 removed more crude oil. The shape of the two curves
follows a logarithmic trend. After two hours, the rate of crude
removal by Solution 2 was two-times faster than that by Solution 3.
After 90 minutes, Solution 2 removed 75% of the crude from the 2-D
pore, while Solution 3 removed only 30% of the crude. After 24
hours, the percent of crude removal by Solution 2 was 95% while
that for Solution 3 was only 78%.
[0046] A set of experiments was performed using thin specimens of
Berea sandstone that were partially saturated with the crude oil by
allowing crude oil to imbibe into dry specimens. The specimen was
then contacted with a nanofluid inside a cuvette as described above
and results were recorded by video.
[0047] The video clips show crude oil removal dynamics from Berea
sandstone. The cuvette filled with Solution 3 with 0.4% KCl was
milky and non-transparent, preventing observation of crude oil
separation from the sandstone. However, crude oil accumulated at
the air/aqueous solution surface could be observed. Crude oil
removal from the rock in Solution 2 after 5, 10, and 30 minutes was
video recorded. Small crude droplets (e.g. 0.008-0.015 cm) were
continuously released from the pores of the sandstone and could be
seen all over the core surface. As crude was released from the
pores and the oil droplets reached a size at which the buoyancy
force overcomes the capillary force which keeps the droplet
attached to the pore, the droplets detached and rose. In order to
demonstrate that the buoyancy force is responsible for the droplet
detachment, the vial with the core sample was gently shaken,
detaching hundreds of droplets. In some cases, twenty or more
droplets were released from one pore. The process of droplet
formation and release from the sandstone pore for the case of
Solution 2 was recorded in a video clip. The micrograph video
depicts the time frequency and the drop sizes of the crude oil
droplets released from the pores. Knowing the initial amount of the
crude impregnated into the sandstone sample, the number average of
the pore per square centimeter, and the size of the released
droplets, one can estimate the oil volume released from the core.
Using this approach, one can predict the efficiency of crude
removal from different rock samples and optimize the removal
process, Preferably, data from several runs (e.g. four to five)
would be analyzed.
[0048] After 20 hours Solution 3 became transparent and
observations on crude oil droplet release from the sandstone were
made, along with observations in Solution 2. The observations of
crude oil removal dynamics clearly reveal that in both cases the
crude oil is continuously released from the pores by droplets
detaching from the pores. The droplets released from the rock in
the presence of Solution 3 rose and formed a stable oil-in-water
emulsion layer at the air-aqueous interface, while the droplets
released from the rock's pores in the presence of Solution 2 rose
to the top and formed a continuous oil layer. The amount of crude
released from the rock samples was estimated by measuring the
amount of the crude left inside the rock. After 24 hours'
treatment, the rock samples were taken from the solution, dried at
room temperature for several days until the weight became constant,
and then measured. For the sample treated with Solution 2, 91.+-.5%
of the crude was released and for the sample treated with Solution
3, 80.+-.5% of the crude was released. Results also showed that
Solution 2 performance at a dilution ratio of 0.6% KCl and 0.4% KCl
after 24 hours was respectively 97% and 95%.
[0049] In summary, Solution 2, the nanofluid, performed
substantially better than Solution 2, the microemulsion additive
blend.
[0050] In a different type of experiment, 1-inch diameter and
1-inch long cores with about 20 md permeability, from a heavy
oil-producing formation in Wyoming, were used to test for
hydrocarbon recovery. The cores were saturated with the heavy
oil-having an API gravity of 10.94. A dispersion of 44% aqueous
nanofluid with 56% xylene was flowed through the first core. A
nonionic surfactant/water/xylene solution was flowed through the
second core. The volume of each fluid was 100 mL. Recovered oil
solvated with the xylene was measured by absorbance at 410 nm
wavelength using a DR5000 VIS spectrometer. The core tested with
the dispersion of nanofluid and xylene recovered 89.9% more of the
heavy oil than the nonionic surfactant/water/xylene solution
recovered. This demonstrates the effect of the nanoparticles in
increasing oil recovery.
[0051] The enhanced wetting of solids by solutions containing
monodisperse nanoparticles, as provided by the phenomenon
illustrated in FIG. 1, can be applied in various processes to
remove solids or liquid that block flow of hydrocarbons into or out
of a well. These processes have been generally identified above.
Specific processes include: paraffin or heavy hydrocarbon removal,
water block removal and solids removal. Other well stimulation
processes are more successful if treatment fluid used in the
process is more effectively removed by using the enhanced wetting
provided by nanoparticles. These processes include hydraulic
fracturing, both proppant and acid, and matrix acidizing, both
carbonate and sandstone. Field examples of two of these processes
are discussed below.
EXAMPLE 1
[0052] A well producing from the Sprayberry formation in Chaves
County, New Mexico was treated with 272 gallons of surfactant and
nanoparticles for paraffin remediation. The solution included 15%
alpha-olefin sulfonate, ethoxylated nonyl phenol, d-limonene and
20% by weight 11 nm nanoparticles. The production rate from the
well after the treatment was increased for a total of about 90
days. Surfactant/solvent treatments in the field result in
increased production for only about 30 days.
EXAMPLE 2
[0053] A well in Scurry County, Texas was treated with 150 gallons
of surfactant and nanoparticles for paraffin remediation, using the
solution described above. A time was allowed for the treatment
solution to act. The well was then produced. The oil production
rate doubled and the total fluid production rate increased from 90
to 140 barrels of fluid per day.
EXAMPLE 3
[0054] A well in Harrison County, Texas was hydraulically fractured
in the Travis Peak formation. A total of 1450 gallons of wetting
agent and nanoparticle solution was added to the fracturing fluid.
The volume of water recovered during cleanup of the well was more
than 80% of the volume of water injected during the treatment; this
is significantly higher than the volume of load water typically
recovered using microemulsion additives or surfactants alone in the
fracturing fluid. Higher water recovery after a fracturing
treatment typically results in higher hydrocarbon fluid
production.
[0055] Although the present invention has been described with
respect to specific details, it is not intended that such details
should be regarded as limitations on the scope of the invention,
except to the extent that they are included in the accompanying
claims.
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