Note: Descriptions are shown in the official language in which they were submitted.
USING GASES AND HYDROCARBON RECOVERY FLUIDS CONTAINING
NANOPARTICLES TO ENHANCE HYDROCARBON RECOVERY
Field of the Invention
The present invention relates to improved hydrocarbon recovery methods using
gases
such as carbon dioxide, nitrogen, natural gas, liquified natural gas,
liquified carbon dioxide
and/or mixtures thereof in combination with functionalized materials such as
nanoparticles or
mixtures of nanoparticles.
Background of the Invention
There are approximately 1.7 million active oil and gas wells in the US. At
this point in
time, hundreds of thousands of these oil and gas wells have declined or
depleted to the point of
being marginally economical. As wells age, multiple mechanisms contribute to
the production
decline.
In addition to mechanical failures of a well's infrastructure, the following
formation
damage accelerates the production decline:
- A drop in bottom hole pressure as the well depletes, which decreases
relative
permeability and increases liquified loading
- Fines migration, mechanically induced by flow velocity'
- Scaling, precipitates, paraffins/asphaltenes and clay swelling
- Water or condensate block
- Fracturing (frac) hits
Enhancing well productivity has traditionally been done using stimulation
methods that
increase the permeability of the reservoir rock or lower the oil viscosity.
Matrix acidizing (see:
"Sandstone Matrix Acidizing Knowledge and Future Development", by Mian Umer
Shafiq and
Hisham Ben Mahmud, J. Petrol Explor Prod Technol (2017) 7: 1205-1216), as a
method of
1
Date Recue/Date Received 2021-08-18
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
stimulation, is relatively inexpensive but narrow in scope. Ideal candidates
for this process
typically include wells in formations with a permeability of >10 mD and where
solids plug the
pores near the wellbore and/or at the perforations. The refracturing process
is at the other end of
the spectrum. This can be used to stimulate productivity, but it is a costlier
option and riskier
value proposition, especially for unconventional wells.
Gases and Liquified Gases, such as carbon dioxide, nitrogen, natural gas,
liquified natural
gas and liquified carbon dioxide have a long history of improving relative
permeability,
providing energy and drive in miscible and immiscible recovery applications.
Studies have
shown that Huff'n Puff (hereinafter abbreviated as "HNP") treatments with gas
have achieved
particularly positive results on oil recovery and short-term production
(Figure 2).
Nitrogen-HNP has also shown very beneficial results in field studies carried
out in
suitable formations in the Appalachian Basin (see "Field Case: Cyclic Gas
Recovery for Light
Oil Using Carbon Dioxide/Nitrogen/Natural Gas", written by B.J. Miller and T.
Hamilton-
Smith, SPE 49169, Conference: SPE Annual Technical Meeting and Exhibition,
September
1998). HNP treatments for stimulating well production are usually individual,
cyclic well
treatments comprising three phases: injection, soaking and production.
HNPs also provide important information on injectivity and pressure
communication with
adjacent wells. As a proven, single-well stimulation method, they can
dramatically increase
production from stripper, depleted or low-pressure oil wells. Under certain
conditions, carbon
dioxide and nitrogen can become miscible with crude, lowering its viscosity
and thereby further
enhancing recovery.
Over the years, carbon dioxide, nitrogen, natural gas, liquified natural gas
and liquified
carbon dioxide HNP treatments have been used as an affordable, effective means
of enhancing
recovery. They are an ideal solution for marginal wells in advanced decline
and an effective way
of stimulating reservoirs with poor inter-well communications. More recently,
studies have
shown that HNP injection is a more effective method for enhancing oil
production from shales
than continuous gas flooding (see "Optimization of huff-n-puff gas injection
in shale oil
2
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
reservoirs", written by J.J. Sheng, Petroleum, 2017 and "Gas Selection for
Huff-n-Puff EOR
In Shale Oil Reservoirs Based upon Experimental and Numerical Study", written
by L. Li
and J.J. Sheng, SPE-185066-MS, 2017.)
Treatments can be applied multiple times to a single well to support improved
oil
recovery (TOR) and enhanced oil recovery (E0R). Small volumes of Carbon
Dioxide can
generate significant increases in recoverable reserves and production that
provide quick payback
as a result of that increased production.
Nanoparticles have been at the forefront of research into various applications
in the oil
and gas industry for at least a decade now. Nanoparticles are usually
particles under 100 nm in
size and can be made up of various inorganic materials such as silica, alumina
and oxides of iron.
Nanoparticles can be structured to contain an inner core and an outer shell
(see "Nanofluids
Science and Technology", written by S.K. Das, S.U.S. Choi, W. Yu, and T.
Pradeep, Hoboken,
New Jersey: John Wiley & Sons, Inc Publishing. ISBN 0470074736). Their outer
shell can be
modified to alter their wettability. Nanoparticles (either unmodified or
modified) can then be
dispersed in an aqueous or organic medium such as water, methanol or
isopropanol and
deployed. Nanoparticles are highly versatile and can be designed for specific
applications.
The true mode of action of nanoparticles in a reservoir depends on how they
are designed
and deployed. However, laboratory studies have shown that nanoparticles in
dispersion can align
themselves at the oil, aqueous, solid three-phase contact angle (see
"Spreading of Nanofluids
on Solids", written by D.T.Wasan and Nikolov, Journal of Nature (423): 156-
159, A. 2003.).
The alignment of the nanoparticles in a wedge between oil and rock generates
what is known as
structural disjoining pressure, which helps create a pressure gradient
sufficient to lift an oil
droplet off the surface of the rock. This phenomenon results in increased oil
recovery rates and
has been demonstrated in imbibition and in-core flow tests (see "Spreading of
Nanofluids on
Solids", written by D.T.Wasan and Nikolov, Journal of Nature (423): 156-159,
A. 2003).
In the field, case studies have been reported that exhibit the effectiveness
of nanoparticle
dispersions. In one field trial, a silicon dioxide-based nanoparticle
dispersion was deployed in a
3
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
hydraulic fracturing application (see "Application of Nanofluid Technology to
Improve
Recovery in Oil and Gas Wells", written by P.M. Mcelfresh, D.L. Holcomb and D.
Ector,
Society of Petroleum Engineers. doi:10.2118/154827-MS, 2012, January 1). The
dispersion was
deployed as a pre-pad pill ahead of the pad stage in a fracture job for first
contact with the
reservoir in five wells in the Wolfcamp and Bone Spring formations in the
Permian Basin. Field
results displayed significant increases in initial production of around 20
percent compared with
the type curves. These rates appeared to be sustained for the successful wells
even in the
presence of an offset fracture breakthrough. The results also showed a
decrease in the initial
effective decline rate.
Further references in this area include:
Carpenter, C., Journal of Petroleum Technology, Modelling of Production
Decline
Caused by Fines Migration in Deepwater Reservoirs, February 2018; Eagle Ford
Type Curve,
eia.gov/analysis/studies/usshalegas/pdfiusshaleplays.pdf;
Wei, B., Pu, W., Pang, S., Kong, L., Mechanisms of N2 and CO2 Assisted Steam
Huff-n-
Puff Process in Enhancing Heavy Oil Recovery: A Case Study Using Experimental
and
Numerical Simulation, Conference: Conference: SPE Middle East Oil & Gas Show
and
Conference, January 2017;
Miller, B.J., Hamilton-Smith, T., SPE 49169 "Field Case: Cyclic Gas Recovery
for
Light Oil Using Carbon Dioxide/Nitrogen/Natural Gas", Conference: SPE Annual
Technical
Meeting and Exhibition, September 1998;
Sheng, J.J., Optimization off huff-n-puff gas injection in shale oil
reservoirs,
Petroleum, 2017;
Li, L., Sheng, J.J., Gas Selection for Huff-n-Puff EOR In Shale Oil Reservoirs
Based
upon Experimental and Numerical Study, SPE-185066-MS, 2017;
Palmer, F.S., Landry, R.W., Bou-Mikael, S. SPE 15497, "Design and
Implementation
of Immiscible Carbon Dioxide Displacement Projects (CO2 Huff-Puff) in South
Louisiana",
Conference: SPE Annual Technical Meeting and Exhibition, October 1986;
Das, S.K., Choi, S.U.S., Yu, W., and Pradeep, T. 2008. Nanofluids Science and
Technology. Hoboken, New Jersey: John Wiley & Sons, Inc Publishing. ISBN
0470074736;
Wasan, D.T., and Nikolov, Spreading of Nanofluids on Solids. Journal of Nature
(423):
156-159, A. 2003;
4
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
Mcelfresh, P. M., Holcomb, D. L., & Ector, D. Application of Nanofluid
Technology
to Improve Recovery in Oil and Gas Wells. Society of Petroleum Engineers.
doi:10.2118/154827-MS, 2012, January 1 and
Syfan, F. E., Holcomb, D. L., Lowrey, T. A., Nickerson, R. L., Sam, A. B., &
Ahmad, Y.
Enhancing Delaware Basin Stimulation Results Using Nanoparticle Dispersion
Technology.
Society of Petroleum Engineers. doi:10.2118/189876-MS, 2018, January 23.
US Patent No. 4,390,068, "Carbon Dioxide Stimulated Oil Recovery Process",
issued
8 June 1983, describes and claims a process of stimulating oil recovery using
carbon dioxide in
the liquified state. The carbon dioxide is introduced into an underground
formation where it
partially dissolves in the crude oil present therein. A back pressure in the
range of atmospheric to
approximately 300 psi is maintained on the formation while the oil containing
carbon dioxide is
withdrawn. The carbon dioxide is thereafter separated from the oil.
U.S. Patent No. 5,381,863, "Cyclic Huff-n-Puff with Immiscible Injection and
Miscible Production Steps" issued 17 January 1995, describes and claims a
method of
recovering hydrocarbons from a reservoir under an active waterflood or water
drive by injecting
a recovery fluid comprising carbon dioxide or nitrogen under immiscible
conditions, allowing
the recovery fluid to soak, and producing the recovery fluid and formation
fluids under
conditionally miscible or miscible conditions after pressure has sufficiently
increased in the
wellbore area.
U.S. Patent No. 7,216,712 "Treatment of Oil Wells" issued 15 May 2007,
describes
and claims a method wherein hydrocarbon solids are removed from an oil well by
feeding into
the oil well a composition comprising at least 40 vol. % dense phase carbon
dioxide and at least
30 vol. % of a Ci C3 alkanol component and optionally one or more surfactants,
under a pressure
of 300 to 10,000 psia and a temperature of 90 F. to 120 F., holding the
composition in the well
to solubilize hydrocarbon solids, and then removing from the well a liquified
composition
comprising solubilized hydrocarbon solids and alkanol. Gases such as Carbon
Dioxide,
Nitrogen, Natural Gas and/or Natural Gas Liquifieds can also be used in
waterless fracturing of a
suitable hydrocarbon-bearing formation.
The article, "Waterless fracturing technologies for unconventional reservoirs-
opportunities for liquified nitrogen", Journal of Natural Gas Science and
Engineering, 35
(2016) 160-174, by Lei Wang et al., describes waterless fracturing
technologies. During the past
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
two decades, hydraulic fracturing has significantly improved oil and gas
production from shale
and tight sandstone reservoirs in the United States and elsewhere. Considering
formation
damage, water consumption and environmental impacts associated with water-
based fracturing
fluids, efforts have been devoted to developing waterless fracturing
technologies because of their
potential to alleviate these issues. Key theories and features of waterless
fracturing technologies,
including Oil-based and Carbon Dioxide energized oil fracturing, explosive and
propellant
fracturing, gelled Liquified Petroleum Gas ("LPG") and alcohol fracturing, gas
fracturing,
Carbon Dioxide fracturing, and cryogenic fracturing are reviewed. Experimental
results are
shown describing the efficacy of liquified nitrogen in enhancing fracture
initiation and
propagation in concrete samples, and shale and sandstone reservoir rocks. In
the laboratory
study, cryogenic fractures generated were qualitatively and quantitatively
characterized by
pressure decay tests, acoustic measurements, gas fracturing and CT scans. The
capacity and
applicable of cryogenic fracturing using liquified nitrogen are demonstrated
and examined. By
properly formulating the technical procedures for field implementation,
cryogenic fracturing
using liquified nitrogen could be an advantageous option for fracturing
unconventional
reservoirs.
The Linde Group, is one of the leading gases and engineering companies in the
world,
working in more than 100 countries worldwide. The Linde Group is located in
Klosterhofstrasse
1, 80 331 Munich, Germany 80331. Since the early 1990s, Linde has deployed
Huff 'n Puff
technology to inject carbon dioxide into depleted wells to incrementally
increase oil production.
Less costly than refracturing, Huff 'n Puff provides the energy to give
hydrocarbons in low-
pressure zones the necessary lift to get them flowing to the wellbore.
Nissan Chemical America Corporation is a leading manufacturer of colloidal
silica and
colloidal electro-conductive oxide solutions. Located at 10333 Richmond
Avenue, Suite 1100,
Houston, TX 77042, Nissan Chemical America Corporation is a wholly owned
subsidiary of
Nissan Chemical Corporation, Ltd. a Japanese company. Nissan Chemical America
Corporation
offers colloidal silica products for sale as well as Hydrocarbon Recovery
Fluids incorporating
colloidal silica products.
Improved oil recovery treatment methods play an increasing role in the oil and
gas
industry, as existing fields become depleted resulting in reduced production.
What would be
desirable are new and modified well stimulation (remediation) methods to
increase the recovery
6
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
of hydrocarbons and reducing the water cut from an underperforming well,
preferably using non-
aqueous materials.
Summary of the Invention
The first aspect of the instant claimed invention is a process of stimulating
hydrocarbon
recovery comprising
(a) introducing a gas, a liquified gas or a vaporized liquified gas, into
an underground
formation containing hydrocarbons;
(b) permitting said gas or a vaporized liquified gas to be absorbed by said
hydrocarbons,
(c) withdrawing said hydrocarbons containing said gas, liquified gas or
vaporized
liquified gas absorbed therein; and
wherein a pill of Hydrocarbon Recovery Fluid comprising surface functionalized
nanoparticles is inserted into the underground formation containing
hydrocarbons, before,
during or after the introduction of the gas, liquified gas or vaporized
liquified gas.
The second aspect of the instant claimed invention is the process of the first
aspect of the
instant claimed invention wherein the injected gas, liquified gas or a
vaporized liquified gas and
Hydrocarbon Recovery Fluid comprising surface functionalized nanoparticles may
also include
one or more injectants, selected from the group consisting of fresh water, KCl
water, diverters
and any other injectant currently used in oil field remediation as part of the
treatment.
The third aspect of the instant claimed invention is the process of the first
aspect of the
instant claimed invention wherein said pill of Hydrocarbon Recovery Fluid
comprising surface
functionalized nanoparticles is inserted into the underground formation
containing hydrocarbons
before the introduction of the gas, liquified gas or a vaporized liquified
gas.
The fourth aspect of the instant claimed invention is the process of the first
aspect of the
instant claimed invention wherein said pill of Hydrocarbon Recovery Fluid
comprising surface
7
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
functionalized nanoparticles is inserted into the underground formation
containing hydrocarbons
during the introduction of the gas, liquified gas or a vaporized liquified
gas.
The fifth aspect of the instant claimed invention is the process of the first
aspect of the
instant claimed invention wherein said pill of Hydrocarbon Recovery Fluid
comprising surface
functionalized nanoparticles is inserted into the underground formation
containing hydrocarbons
after the introduction of the gas, liquified gas, or a vaporized liquified
gas.
The sixth aspect of the instant claimed invention is the process of the first
aspect of the
instant claimed invention wherein said gas is selected from the group
consisting of carbon
dioxide, nitrogen, natural gas, liquified natural gas, liquified carbon
dioxide and/or mixtures
thereof
The seventh aspect of the instant claimed invention is the process of the
first aspect of the
instant claimed invention wherein said gas is carbon dioxide
The eighth aspect of the instant claimed invention is the process of the first
aspect of the
instant claimed invention wherein said gas is nitrogen.
The ninth aspect of the instant claimed invention is the process of the first
aspect of the
instant claimed invention wherein said gas is natural gas.
The tenth aspect of the instant claimed invention is the process of the first
aspect of the
instant claimed invention wherein said gas is liquified natural gas, liquified
carbon dioxide
and/or mixtures thereof.
The eleventh aspect of the instant claimed invention is the process of the
sixth aspect of
the instant claimed invention wherein said gas is a mixture of two or more
gases selected from
the group consisting of carbon dioxide, nitrogen, natural gas, liquified
natural gas, liquified
carbon dioxide and/or mixtures thereof.
8
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
The twelfth aspect of the instant claimed invention is the process of the
first aspect of the
instant claimed invention wherein said process is part of a huff and puff
treatment process.
The thirteenth aspect of the instant claimed invention is the process of the
twelfth aspect
of the instant claimed invention wherein said process is a waterless
fracturing process.
The fourteenth aspect of the instant claimed invention is the process of the
thirteenth
aspect of the instant claimed invention wherein said process is a less water
fracturing process.
The process for stimulating hydrocarbon recovery comprises injection of a gas,
such as
carbon dioxide, nitrogen, natural gas, liquified natural gas, liquified carbon
dioxide and/or
mixtures thereof into an underground formation containing hydrocarbons,
permitting said gas to
flush liquids, such as condensate, water, etc. etc., and debris in the near
well bore area and to
pressurize the well up to 500 psi. In the event the gas is miscible in the
crude oil, the gas will
cause it to swell and reduce viscosity. The stimulation process includes
combining injection of
gas with a pill of Hydrocarbon Recovery Fluid comprising surface
functionalized nanoparticles,
which may be introduced before, during or after the gas.
The surface functionalized nanoparticles have specific unique properties that
enables
hydrocarbon production from micro to nano sized spaces, including those spaces
classified as
voids or fractures. The surface functionalized nanoparticles may cause
wettability alteration of
solid/liquified surfaces facilitating flow. The stimulation process involves
combining gas and
Hydrocarbon Recovery Fluid comprising surface functionalized nanoparticles
which results in a
hydrocarbon production enhancement that is attributable to synergistic
effects.
Brief Description of the Drawings
Figure 1. Example of a production decline curve. Taken from Palmer, F. S.,
Landry,
R W., Bou-Mikael, S SPE 15497, "Design and Implementation of Immiscible Carbon
Dioxide
Displacement Projects (CO2 Huff-Puff) in South Louisiana", Conference: SPE
Annual Technical
Meeting and Exhibition, October 1986. Not an example of the instant claimed
invention.
9
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
Figure 2. Comparisons of oil recovery using CO2, N2, and steam HNP treatments.
Figure taken from Wasan, D.T., and Nikolov, Spreading of Nanofluids on Solids.
Journal of
Nature (423): 156-159, A. 2003. Not an example of the instant claimed
invention.
Figure 3: Nanoparticles aligned at the three-phase contact angle to support
hydrocarbon
recovery (see Wasan et al., 2003). Not an example of the instant claimed
invention.
Figure 4. Cumulative oil production for the Austin Chalk wells before and
after
treatment with N, and developmental nanoActiv HRT Hydrocarbon Recovery Fluid
comprising surface functionalized nanoparticles.
Figure 5. Cumulative BOE production at the Buda wells before and after
treatment with
N2 and developmental nanoActiv HRT Hydrocarbon Recovery Fluid comprising
surface
functionalized nanoparticles.
Figure 6. The three phases of an HNPTM treatment.
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
Detailed Description of the Invention
Throughout this patent application the term "pill" has the following
definition:
Pill- Any relatively small quantity of a special blend of drilling fluid to
accomplish a specific
task that the regular drilling fluid cannot perform. Fluid pills are commonly
prepared for a
variety of special functions Pills are small quantities of drilling fluids and
it is understood that
more than one pill may be added to a hydrocarbon formation
The first aspect of the instant claimed invention is a process of stimulating
hydrocarbon
recovery comprising
(a) introducing a gas, liquified gas or a vaporized liquified gas, into an
underground
formation containing hydrocarbons;
(b) permitting said gas, liquified gas or a vaporized liquified gas to be
absorbed by
said hydrocarbons,
(c) withdrawing said hydrocarbons containing said gas, liquified gas or
vaporized
liquified gas absorbed therein; and
wherein a pill of Hydrocarbon Recovery Fluid comprising surface functionalized
nanoparticles is inserted into the underground formation containing
hydrocarbons, before,
during or after the introduction of the gas, liquified gas or vaporized
liquified gas
The surface functionalized nanoparticles may be made from any suitable
material. Non-
limiting examples of suitable surface functionalized nanoparticle materials
include ceramics,
metals, metal oxides (e.g., silica, titania, alumina, zirconia, vanadyl,
ceria, iron oxide, antimony
oxide, tin oxide, aluminum, zinc oxide, boron, and combinations thereof),
polymers (e.g.,
polystyrene), resins (e.g., silicone resin), and pigments (e.g., chromite
spinel pigments). In some
embodiments, the surface functionalized nanoparticles comprise a plurality of
hydrophobized
nanoparticles. In some embodiments the surface functionalized nanoparticles
are surface
functionalized colloidal silica nanoparticles.
It is generally well known in oilfield applications that subterranean
formations contain
large amounts of water containing dissolved salts such as NaC1, CaCl2, KC1,
MgCl2 and others.
This aqueous salt mixture is typically referred to as Brine. Brine conditions
for different regions
and wells vary widely with different downhole conditions and lithologies. In
general, fluids used
downhole must either tolerate briny conditions or have brine-resistant
properties.
11
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
Colloidal systems in general and aqueous colloidal silica rely primarily upon
electrostatic
repulsion between charged silica particles to avoid unwanted or adverse
phenomena such as
particle agglomeration, flocculation, gelation and sedimentation. This
electrostatic repulsion is
easily disrupted in briny conditions typically found in subterranean
formations. Furthermore,
agglomeration/flocculation/gelation/sedimentation of colloidal silica and
fluids containing
colloidal silica in downhole applications would have the potential to damage
the well or
potentially plug the well entirely. Therefore, application of colloidal silica
in downhole
applications necessitates imparting brine resistant properties to colloidal
silica and fluids
containing colloidal silica before application.
In order not to gel upon exposure to brine (salt water), the nanoparticles
must have a
surface functionalization that stabilizes the colloidal silica. The surface
functionalization of the
colloidal silica allows the colloidal silica to be resistant to the effects of
brine (salt water) and
heat. Surface functionalized colloidal silica are typically referred to as
"brine resistant silica
sols". Hydrocarbon Recovery Fluids comprising surface functionalized colloidal
silica are used,
along with gases described herein to effectuate the further removal of
hydrocarbons from
underperforming wells.
Standard tests for brine stability are disclosed in the following paragraphs:
API Brine by Visual Observation:
A lOwt% API Brine solution is prepared by dissolving 8wt% NaCl (SigmaAldrich)
and
2wt% CaCl2 (Sigma Aldrich) in distilled water. Testing for Brine resistance is
done by placing 1
gram of example silica sol into 10 grams of API Brine Solution. Stability
observations are
performed at standard brine exposure periods of 10 minutes and 24 hours. These
observations
include the clarity and transparency of the silica sol. The results of these
observations are
recorded at these times. Silica sol solutions that are stable to Brine
exposure will remain clear
and transparent/opalescent while unstable examples become visibly hazy and
opaque after brine
exposure.
Artificial Seawater by Visual Observation
Artificial seawater is prepared by dissolving Fritz Pro Aquatics RPM Reef Pro
Mix (Fritz
Industries, Inc.) at 6 wt% in distilled water. Testing for Brine resistance is
done by placing 1
gram of example silica sol into 10 grams of Artificial Seawater. Stability
observations are
performed at standard brine exposure periods of 10 minutes and 24 hours. These
observations
12
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
include the clarity and transparency of the silica sol. The results of these
observations are
recorded at these times. Silica sol solutions that are stable to Brine
exposure will remain clear
and transparent/opalescent while unstable examples become visibly hazy and
opaque after brine
exposure.
API Brine Resistance Test by use of a Turbidimeter
Reference: US EPA 180.1 Determination of Turbidity by Nephelometry
A difference between this test and the US EPA 101.1 test is that in this test,
step 11.2 is
not followed.
Step 11.2 reads as follows: Turbidities exceeding 40 units: Dilute the sample
with one or
more volumes of turbidity-free water until the turbidity falls below 40 units.
The turbidity of the
original sample is then computed from the turbidity of the diluted sample and
the dilution factor.
For example, if 5 volumes of
turbidity-free water were added to 1 volume of sample, and the diluted sample
showed a
turbidity of
30units, then the turbidity of the original sample was 180 units.
For this work, the actual ("raw") value of turbidity is recorded, whether it
is above, below
or equal to 40.
Test solutions/surface treated silicasols are tested for Brine resistance by
Turbidimetry.
A calibrated Hach 2100AN Turbidimeter is used to measure Turbidity in units of
NTU (Nephelometric Turbidity Units).
Test solution amounts of 3.0 g are placed into standard turbidity test tubes
of
approximately 30m1.
Twenty-seven grams (27g) of 10% API brine (8wt% NaCl, 2wt% CaCl2) are added to
the
test tube and the mixture inverted three times to mix test solution and brine.
Test solution
concentrations are therefore lOwt% in API Brine.
Sample test tubes are inserted into the Turbidimeter and an initial
measurement of
turbidity is taken immediately, followed by a turbidity measurement after 24
hours.
A change in turbidity of more than 10ONTU leads to the conclusion that the
silica sol is not brine stable. Conversely a change in turbidity of less than
100NTU after API
brine exposure leads to the conclusion that the silica sol is brine stable.
13
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
Dynamic Light Scattering Method
Whether the silica particles in the aqueous silica sol are dispersed or
coagulated can be
determined by measuring the average particle diameter by dynamic light
scattering (DLS average
particle diameter) for silica particles of the silica sol in the chemical
fluid.
The DLS average particle diameter represents the average value of secondary
particle
diameter (dispersed particle diameter), and it is said that the DLS average
particle diameter in a
completely dispersed state is about twice the average particle diameter (which
represents the
average value of primary particle diameter in terms of specific surface
diameter obtained through
measurement by nitrogen adsorption (BET method) or Sears' particle diameter).
It then can be
determined that as the DLS average particle diameter increases, the silica
particles in the aqueous
silica sol is more coagulated.
In a case where the Hydrocarbon Recovery Fluid comprising surface
functionalized
nanoparticles has a good resistance to high temperature and salt, the DLS
average particle
diameter after a high temperature and salt resistance test is almost the same
as the DLS average
particle diameter of the chemical fluid. For example, if the ratio of the DLS
average particle
diameter after a high temperature and salt resistance test/the DLS average
particle diameter of
the Hydrocarbon Recovery Fluid comprising surface functionalized nanoparticles
is 1.1 or less, it
shows that the Hydrocarbon Recovery Fluid comprising surface functionalized
nanoparticles
after a high temperature and salt resistance test maintains the similar
dispersion state as that of
the Hydrocarbon Recovery Fluid comprising surface functionalized nanoparticles
However,
when the resistance to high temperature and salt of the Hydrocarbon Recovery
Fluid comprising
surface functionalized nanoparticles is poor, the DLS particle diameter after
a high temperature
and salt resistance test is much larger, showing that the Hydrocarbon Recovery
Fluid comprising
surface functionalized nanoparticles is in a coagulated state.
For the Hydrocarbon Recovery Fluid comprising surface functionalized
nanoparticles if
the ratio of the DLS average particle diameter after a high temperature and
salt resistance test to
the DLS average particle diameter of the Hydrocarbon Recovery Fluid comprising
surface
functionalized nanoparticles is 1.5 or less (ratio of change of average
particle diameter is 50% or
less), the conclusion reached is that the resistance to high temperature and
salt is good. If the
ratio of the DLS average particle diameter after a high temperature and salt
resistance test to the
DLS average particle diameter of the Hydrocarbon Recovery Fluid comprising
surface
14
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
functionalized nanoparticles is 1.1 or less (ratio of change of average
particle diameter is 10% or
less) there is no degradation of silica sol, the conclusion reached is that
the resistance to high
temperature and salt is very good.
After multiple tests of proposed brine resistant silica sols, it has been
discovered that
brine resistance of aqueous colloidal silica can be improved over untreated
colloidal silica by
addition of certain types of organic surface treatment. There are many
different types of organic
surface treatments that can be used What follows are tables showing
formulations for many
acceptable surface-treated colloidal silicas. These brine resistant silica
sols are also known as
"surface functionalized" colloidal silicas.
In the following potential examples, each ingredient that is used to create a
surface
treated colloidal silica, is listed as Parts of Ingredient, per 100 parts of
surface treated colloidal
silica.
ST-025 and ST-32C are commercially available colloidal silicas from Nissan
Chemical
America Corporation, located at 10333 Richmond Avenue, Suite 1100 Houston, TX
77042 or
from Nissan Chemical Corporation, located at 5-1, Nihonbashi 2-Chome, Chuo-ku,
Tokyo 103-
6119, Japan.
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 1 2 3 4 5 6
lngredients1
ST-025 76 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1 11.1
Propylene Glycol 10 10 10 10 10 10
3-(Triethoxysilyl)propyl
Succinic Anhydride 2.9 1.9 1.9
N-(Triethoxysilylpropy1)-0-
Polyethyleneoxide Urethane 2.9
Silane, trimethoxy[3-
(oxiranyl methoxy)propyl] 2.9
3-Ureidopropyl
Triethoxysilane 2.9
2-(3,4 epoxycyclohexyl)-
ethyltrimethoxysilane 1
3-(Trimethoxysilyl)propyl
Methacrylate 1
Total 100.00 100.00 100.00 100.00 100.00 loom
16
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨> 7 8 9 10 11 12 13
lngredients1
ST-025 76 76 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1 11.1 11.1
Propylene Glycol 10 10 10 10 10 10 10
3-(Triethoxysilyl)propyl Succinic
Anhydride 1.9 1.9 1.9 1.9 1.9 1.9 1.9
Hexamethyl Disiloxane 1
Hexamethyl Disilazane 1
Trimethoxy Methyl Silane 1
Trimethoxy Phenyl Silane 1
Vinyl Trimethoxysilane 1
3-(N,N-DimethylaminopropyI)-
Trimethoxysilane 1
3-(Diethylamino)propyl
trimethoxysilane 1
Total 100 100 100 100 100 100 100
17
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 14 15 16 17 18 19 20 21
Ingreclients4
ST-025 _ 76 _ 76 76 _ 76 _ 76 _ 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1 11.1 11.1
11.1
Propylene Glycol 10 10 10 10 10 10 10 10
3-(Triethoxysilyl)propyl
Succinic Anhydride 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9
Trimethoxy(octadecyl)silane 1 _
_
lsobutyl Trimethoxysilane 1
Hexyltrimethoxysilane 1
Decyltrimethoxysilane 1 _ _
Isooctyltrimethoxysilane 1
Hexadecyltrimethoxysilane 1
Propyltrimethoxysilane _ 1 _
_ _ _ _
Octyltriethoxysilane 1
Total 100 100 100 100 100 100 100 100
18
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 22 23 24 25 26 27 28 29 30
ST-025 70 80 75 72 76 76 76 76 76
Deionized water 14.1 19.1 11.1 13.1 11.1 11.1 11.1 11.1 11
Propylene Glycol 13 8 10 12 10 10 10 10 10
3-(Triethoxysilyl)propyl
Succinic Anhydride 2.9
N-(TriethoxysilylpropyI)-
O-Polyethyleneoxide
Urethane 2.9 1.9 1.9 1.9 1.9 1.9
Silane, trimethoxy[3-
(oxiranyl
methoxy)propyl] 3.9
3-Ureidopropyl
Triethoxysilane 2.9
2-(3,4 epoxycyclohexyl)-
ethyltrimethoxysilane 1
3-(Trimethoxysilyl)propyl
Methacrylate 1
Hexamethyl Disiloxane 1
Hexamethyl Disilazane 1
Trimethoxy Methyl
Silane 1
Total 100 100 100 100 100 100 100 100 100
19
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 31 32 33 34 35 36 37
lngredients4
ST-025 76 76 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1 11.1 11.1
Propylene Glycol 10 10 10 10 10 .. 10 .. 10
N-(TriethoxysilylpropyI)-
O-Polyethyleneoxide
Urethane 1.9 1.9 1.9 1.9 1.9 1.9 1.9
Trimethoxy Phenyl Silane 1
Vinyl Trimethoxysilane 1
3-(N,N-
DimethylaminopropyI)-
Trimethoxysilane 1
3-(Diethylamino)propyl
trimethoxysilane 1
Trimethoxy-
(octadecyl)silane 1
Isobutyl Trimethoxysilane 1
Hexyl-trimethoxysilane 1
Total 100 100 100 100 100 100 100
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 38 39 40 41 42
Ingrec1ients=1
ST-025 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1
Propylene Glycol 10 10 10 10 10
N-
(Triethoxysilylpropy1)-
0-Polyethyleneoxide
Urethane 1.9 1.9 1.9 1.9 1.9
Decyl-
trimethoxysilane 1
Isooctyl-
trimethoxysilane 1
Hexadecyl-
trimethoxysilane 1
Propyl-
trimethoxysilane 1
Octyl-triethoxysilane 1
Total 100.00 100.00 100.00 100.00 100.00
21
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨> 43 44 45 46 47 48 49 50 51
ST-025 76 76 70 80 76 76 76 76 76
Deionized water 10 9 16.1 11.1 11.1 11.1 11.1 11.1
11
Propylene Glycol 11.1 12.1 11 6 10 10 10 10 10
3-(Triethoxysilyppropyl
Succinic Anhydride 2.9
N-(Triethoxysilylpropy1)-
0-Polyethyleneoxide
Urethane 2.9
Silane, trimethoxy[3-
(oxiranyl
methoxy)propyl] 2.9 1.9 1.9 1.9 1.9 1.9
3-Ureidopropyl
Triethoxysilane 2.9
2-(3,4 epoxycyclohexyl)-
ethyltrimethoxysilane 1
3-(Trimethoxysilyl)propyl
Methacrylate 1
Hexamethyl Disiloxane 1
Hexamethyl Disilazane 1
Trimethoxy Methyl
Silane 1
Total 100 100 100 100 100 100 100 100 100
22
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 52 53 54 55 56 57 58
ST-025 76 76 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1 11.1 11.1
Propylene Glycol 10 10 10 10 10 10 10
Silane, trimethoxy[3-
(oxiranyl methoxy)propyl] 1.9 1.9 1.9 1.9 1.9 1.9 1.9
Trim ethoxy Phenyl Silane 1
Vinyl Trimethoxysilane 1
3-(N,N-
Dimethylaminopropy1)-
Trimethoxysilane 1
3-(Diethylamino)propyl
trimethoxysilane 1
Trimethoxy(octadecyl)silane 1
Isobutyl Trimethoxysilane 1
Hexyltrimethoxysilane 1
Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00
23
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨> 59 60 61 62 63
ST-025 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1
Propylene Glycol 10 10 10 10 10
Silane, trimethoxy[3-
(oxiranyl methoxy)propyl] 1.9 1.9 1.9 1.9 1.9
Decyltrimethoxysilane 1
lsooctyltrimethoxysilane 1
Hexadecyltrimethoxysilane 1
Propyltrimethoxysilane 1
Octyltriethoxysilane 1
Total 100.00 100.00 100.00 100.00 100.00
24
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 64 65 66 67 68 69 70 71 72 73
Ingredients
ST-025 76 76 76 76 76 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1 11.1 11.1 11.1
11 11.1
Propylene Glycol 10 10 10 10 10 10 10 10 10 10
3-(Triethoxysilyl)propyl
Succinic Anhydride 1.45
N-
(Triethoxysilylpropy1)-
0-Polyethyleneoxide
Urethane 1.45 2.9
Silane, trimethoxy[3-
(oxiranyl
methoxy)propyl] 2.9
3-Ureidopropyl
Triethoxysilane 2.9 1.9 1.9 1.9 1.9 1.9 1.9
2-(3,4
epoxycyclohexyl)-
ethyltrimethoxysilane _ 1 _
3-
(Trimethoxysilyl)propyl
Methacrylate _ _ 1
Hexamethyl Disiloxane 1
Hexamethyl Disilazane 1
Trimethoxy Methyl
Silane 1
Trimethoxy Phenyl
Silane 1
Total 100 100 100 100 100 100 100 100 100 100
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
Examples¨> 74 75 76 77 78 79 80 81
Ingredients4
ST-025 76 76 76 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1 11.1 11.1
11.1
Propylene Glycol 10 10 10 10 10 10 10 10
3-Ureidopropyl
Triethoxysilane 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9
Vinyl Trimethoxysilane 1
3-(N,N-
Dimethylaminopropy1)-
Trimethoxysilane 1
3-(Diethylamino)propyl
trimethoxysilane 1
Trimethoxy(octadecyl)silan
e 1
lsobutyl Trimethoxysilane 1
Hexyltrimethoxysilane 1
Decyltrimethoxysilane 1
Isooctyltrimethoxysilane _ 1
Hexadecyltrimethoxysilane _
Propyltrimethoxysilane
Octyltriethoxysilane
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
Total 0 0 0 0 0 0 0 0
26
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨> 82 83 84
Ingredientssi,
ST-025 76 76 76
Deionized water 11.1 11.1 11.1
Propylene Glycol 10 10 10
3-Ureidopropyl
Triethoxysilane 1.9 1.9 1.9
Hexadecyltrimethoxysilane 1
Propyltrimethoxysilane 1
Octyltriethoxysilane 1
Total 100.00 100.00 100.00
27
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 85 86 87 88 89
Ingredier
ST-025 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1
Ethylene Glycol 10 10 10 10 10
3-
(Triethoxysilyl)propyl
Succinic Anhydride 2.9 1.9
N-
(Triethoxysilylpropy1)-
0-Polyethyleneoxide
Urethane 2.9
Silane, trimethoxy[3-
(oxiranyl
methoxy)propyl] 2.9
3-Ureidopropyl
Triethoxysilane 2.9
2-(3,4
epoxycyclohexyl)-
ethyltrimethoxysilane 1
3-
(Trimethoxysilyl)propy
I Methacrylate
Hexamethyl Disiloxane
Hexamethyl Disilazane
100.0
Total loo.00 loo.00 loo.00 10000
28
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 90 91 92
Ingredier
ST-025 76 76 76
Deionized water 11.1 11.1 11.1
Ethylene Glycol 10 10 10
3-
(Triethoxysilyl)propyl
Succinic Anhydride 1.9 1.9 1.9
3-
(Trimethoxysilyppropy
I Methacrylate 1
Hexamethyl Disiloxane 1
Hexamethyl Disilazane 1
Total 100.00 100.00 100.00
29
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
Examples¨) 93 94 95 96 97 98 99
1ngredients4
ST-025 76 76 76 76 76 76 76
Deionized water 11.1 _ 11.1 11.1 11.1 _ 11.1 11.1 _
11.1
Ethylene Glycol 10 10 10 10 10 10 10
3-
(Triethoxysilyl)propyl
Succinic Anhydride 1.9 1.9 1.9 1.9 1.9 1.9 1.9
Trimethoxy Methyl
Silane 1
Trimethoxy Phenyl
Silane _ 1
Vinyl
Trimethoxysilane 1
Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 100 101 102 103 104 105
ST-025 76 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1 11.1
Ethylene Glycol 10 10 10 10 10 10
3-(Triethoxysilyl)propyl
Succinic Anhydride 1.9 1.9 1.9 1.9 1.9 1.9
Hexyltrimethoxysilane 1
Decyltrimethoxysilane .. 1
lsooctyltrimethoxysilane 1
Hexadecyltrimethoxysilane 1
Propyltrimethoxysilane 1
Octyltriethoxysilane 1
Total 100.00 100.00 100.00 100.00 100.00 100.00
31
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 106 107 108 109 110 111 112
ST-025 78 74 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1 11.1 11.1
Ethylene Glycol 8 12 10 10 10 10 10
3-(Triethoxysilyl)propyl
Succinic Anhydride 1.45
N-(Triethoxysilylpropy1)-
0-Polyethyleneoxide
Urethane 1.45 1.45 1.9 1.9 1.9
Silane, trimethoxy[3-
(oxiranyl
methoxy)propyl] 1.45 1.45
3-Ureidopropyl
Triethoxysilane 1.45 1.45
2-(3,4 epoxycyclohexyl)-
ethyltrimethoxysilane 1.45 1
3-(Trimethoxysilyl)propyl
Methacrylate 1
Hexamethyl Disiloxane 1
Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00
32
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 113 114 115 116 117 118
lngredients4=
ST-025 76 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1 11.1
Ethylene Glycol 10 10 10 10 10 10
N-
(TriethoxysilylpropyI)-
O-Polyethyleneoxide
Urethane 1.9 1.9 1.9 1.9 1.9 1.9
Hexamethyl Disilazane 1
Trimethoxy Methyl
Silane 1
Trimethoxy Phenyl
Silane 1
Vinyl Trimethoxysilane 1
3-(N,N-
DimethylaminopropyI)-
Trimethoxysilane 1
3-
(Diethylamino)propyl
trimethoxysilane 1
Total 100.00 100.00 100.00 100.00 100.00 100.00
33
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples-4 119 120 121 122 123 124 125 126
Ingredients4,
ST-025 76 76 76 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1 11.1 11.1
11.1
Ethylene Glycol 10 10 10 10 10 10 10 10
N-
(TriethoxysilylpropyI)-
O-Polyethyleneoxide
Urethane 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9
Trimethoxy(octadecyl)
silane 1
Isobutyl
Trimethoxysilane .. 1
Hexyltrimethoxysilane 1
Decyltrimethoxysilane 1
Isooctyltrimethoxysila
ne 1
Hexadecyltrimethoxys
ilane 1
Propyltrimethoxysilan
1
Octyltriethoxysilane 1
100.0 100.0 100.0 100.0 100.0 100.0
Total 0 100.00 0 0 0 100.00 0 0
34
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 127 128 129 130 131 132 133 134
Ingredients.I=
ST-025 76 76 78 74 76 76 76 76
Deionized water 11.1 9.1 9.1 12.1 11.1 11.1 11.1 11.1
Ethylene Glycol 10 12 10 10 10 10 10 10
3-
(Triethoxysilyl)propyl
Succinic Anhydride 1.45
N-
(Triethoxysilylpropy1)-
0-Polyethyleneoxide
Urethane 1.45
Silane, trimethoxy[3-
(oxiranyl
methoxy)propyl] 1.45 1.45 1.9 1.9 1.9 1.9
3-Ureidopropyl
Triethoxysilane 1.45 1.45
2-(3,4
Epoxycyclohexyl)-
ethyltrimethoxysilane 1.45 1
3-
(Trimethoxysilyl)propyl 1.45
Methacrylate 1
Hexamethyl Disiloxane 1
Hexamethyl Disilazane 1
Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 135 136 137 138 139 140 141
lngredients'4,
ST-025 76 76 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1 11.1 11.1
Ethylene Glycol 10 10 10 10 10 10 10
Silane, trimethoxy[3-
(oxiranyl methoxy)propyl] 1.9 1.9 1.9 1.9 1.9 1.9 1.9
Trimethoxy Methyl Silane 1
Trim ethoxy Phenyl Silane 1
Vinyl Trimethoxysilane 1
3-(N,N-
Dimethylaminopropy1)-
Trimethoxysilane 1
3-(Diethylamino)propyl
trimethoxysilane 1
Trimethoxy(octadecyl)silane 1
lsobutyl Trimethoxysilane 1
Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00
36
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 142 143 144 145 146 147
ST-025 76 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1 11.1
Ethylene Glycol 10 10 10 10 10 10
Silane, trimethoxy[3-
(oxiranyl methoxy)propyl] 1.9 1.9 1.9 1.9 1.9 1.9
Hexyltrimethoxysilane 1
Decyltrimethoxysilane 1
lsooctyltrimethoxysilane 1
Hexadecyltrimethoxysilane 1
Propyltrimethoxysilane 1
Octyltriethoxysilane 1
Total 100.00 100.00 100.00 100.00 100.00 100.00
37
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 148 149 150 151 152 153 154
lngreclients4
ST-025 76 76 76 76 76 76 76
Deionized water 6.1 7.1 8.1 9.1 11.1 11.1 11.1
Ethylene Glycol 15 14 13 12 10 10 10
3-
(Triethoxysilyl)propyl
Succinic Anhydride -- 2.9
N-
(Triethoxysilylpropy1)-
0-Polyethyleneoxide
Urethane 2.9
Silane, trimethoxy[3-
(oxiranyl
methoxy)propyl] 2.9
3-Ureidopropyl
Triethoxysilane 2.9 1.9 1.9 1.9
2-(3,4
epoxycyclohexyl)-
ethyltrimethoxysilane 1
3-
(Trimethoxysilyl)propyl
Methacrylate 1
Hexamethyl Disiloxane 1
Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00
38
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 155 156 157 158 159 160 161
Ingredients.
ST-025 76 76 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1 11.1 11.1
Ethylene Glycol 10 10 10 10 10 10 10
3-Ureidopropyl
Triethoxysilane 1.9 1.9 1.9 1.9 1.9 1.9 1.9
Hexamethyl Disilazane 1
Trimethoxy Methyl Silane 1
Trim ethoxy Phenyl Silane 1
Vinyl Trimethoxysilane 1
3-(N,N-
DimethylaminopropyI)-
Trimethoxysilane 1
3-(Diethylamino)propyl
trimethoxysilane 1
Trimethoxy(octadecyl)silane 1
Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00
39
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) 162 163 164 165 166 167 168
Ingredients
ST-025 76 76 76 76 76 76 76
Deionized water 11.1 11.1 11.1 11.1 11.1 11.1 11.1
Ethylene Glycol 10 10 10 10 10 10 10
3-Ureidopropyl
Triethoxysilane 1.9 1.9 1.9 1.9 1.9 1.9 1.9
Isobutyl Trimethoxysilane 1
Hexyltrimethoxysilane 1
Decyltrimethoxysilane 1
Isooctyltrimethoxysilane 1
Hexadecyltrimethoxysilane 1
Propyltrimethoxysilane 1
Octyltriethoxysilane 1
Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
Examples¨* 169 170 171 172 173 174 175
Description In redients,i,
Colloidal silica 25
wt% silica solids
available from
Nissan Chemical
America ST-0-25 52.68 50 51 25
Alkaline Colloidal
Silica from Nissan
Chemical Company,
Japan ST-32C 59.28 48 45 25
Dcionized water 36.05 27.97 40 41.5 38.5 43 35
Propylene
Glycol _ 8 7.5 _ 8.5
Ethylene Glycol 8.06 9.85 7.5 10
111.1 Silane,
trimethoxyp-
(oxiranyl
methoxy)propyfl 3.21 2.9 2.5 2.5 3 3.5 5
Total (g) 100 100 100 100 100 100 100
41
Brine resistant silica sols and hydrocarbon recovery fluids comprising surface
functionalized nanoparticles, where the surface functionalized nanoparticles
are brine resistant
silica sols, can be found in U.S. Patent Application. No. 15/946,252; filed
April 5, 2018, entitled
"Brine Resistant Silica Sols"; U.S. Patent Application No. 15/946,338, filed
April 5, 2018,
entitled "Hydrocarbon Formation Treatment Micellar Solutions"; U.S. Patent
Application No.
16/129,688; filed: September 12, 2018, entitled "Crude Oil Recovery Chemical
Fluids",
which application claims priority to Japanese Patent Application No. JP 2017-
175511; and U.S.
Patent Application No. 16/129,705; filed: September 12, 2018, entitled "Crude
Oil Recovery
Chemical Fluid", which application claims priority to Japanese Patent
Application No. JP 2017-
175511.
When selecting/using a fluid to be used in the treatment of an oil and/or gas
well, it is
important for the fluid to have the right combination of additives and
components to achieve the
necessary characteristics of the specific end-use application. A primary goal
amongst many
aspects of hydrocarbon formation treatment is to optimize recovery of oil
and/or gas from the
formation. However, in part because the fluids utilized during the operation
of an oil and/or gas
well are often utilized to perform a number of tasks simultaneously, achieving
necessary to
optimal characteristics of the Hydrocarbon Recovery Fluid comprising surface
functionalized
nanoparticles is always challenging.
Additional commercially available compositions suitable for the Hydrocarbon
Recovery
Fluid include the nanoActiv HRT product line available from Nissan Chemical
America
Corporation, located at 10333 Richmond Avenue, Suite 1100 Houston, TX 77042.
These
products, including developmental products that are currently being trialed,
use nanosized
particles in a colloidal dispersion, which allows the fluid to work by causing
a Brownian-motion,
diffusion-driven mechanism known as disjoining pressure to produce long
efficacy in the
recovery of hydrocarbons in conventional and unconventional reservoirs.
Current commercially available nanoActiveHRT products, include, but are not
limited
to:
a. HRT BIO/G ¨ am environmentally friendly version
b. OFS CORR PRO ¨ a version containing a sour gas scavenger for reducing
corrosion of iron piping due to H25
42
Date Recue/Date Received 2021-08-18
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
c. HRT-78 ¨ a version formulated for high temperatures
d. CPD-60 ¨ a version containing a hydroxysultaine surfactant
e. CPD-37 ¨ the original version that was first sold
f. HRT-53-economical, high performing commercial product
g. HRT-53 C-another version of HRT-53C with a more dilute composition
Additional Hydrocarbon Recovery Fluids comprising functionalized colloidal
silica
mixtures suitable for this invention include a crude oil recovery chemical
solution which is
excellent in resistance to high temperature and salt, characterized by
containing a silane
compound, an aqueous silica sol having an average particle size of from about
3nm to about 200
nm.
In an embodiment of the Hydrocarbon Recovery Fluid comprising surface
functionalized
nanoparticles, the aqueous silica sol contains silica particles in which at
least a part of the silane
compound is bonded on the surface of at least a part of the silica particles
in the sol.
In another embodiment of the Hydrocarbon Recovery Fluid comprising surface
functionalized nanoparticles, the silane compound is at least one compound
selected from the
group consisting of a silane coupling agent having at least one organic
functional group selected
from the group consisting of a vinyl group, an ether group, an epoxy group, a
styryl group, a
methacryl group, an acryl group, an amino group and an isocyanurate group, an
alkoxysilane
group, a silazane group and a siloxane group.
In another embodiment of the Hydrocarbon Recovery Fluid comprising surface
functionalized nanoparticles, aqueous silica sol is present in an amount of
from about 0.1% by
mass to about 20% by mass, based on the total mass of the crude oil recovery
chemical solution,
in terms of silica solid content.
In another embodiment of the Hydrocarbon Recovery Fluid comprising surface
functionalized nanoparticles, the silane compound is present in a ratio of 0.1
to 3.0 of silane
compound based on the mass of silica solid content of the aqueous silica sol.
In another embodiment of the Hydrocarbon Recovery Fluid comprising surface
functionalized nanoparticles, the surfactants are present in an amount of from
about 2% by mass
to about 50% by mass, based on the total mass of the crude oil recovery
chemical solution.
Additional Hydrocarbon Recovery Fluids comprising containing surface
functionalized
colloidal silica mixtures suitable for this invention include a micellar
dispersion fluid
comprising:
43
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
(a) a terpene-based oil phase that includes less than about 20.0 wt. % d-
limonene,
(b) one or more surfactants selected from the group consisting of anionic
surfactants,
cationic surfactants, nonionic surfactants and amphoteric surfactants;
(c) an alcohol selected from the group consisting of CI-C8 alcohols, such
as, but not
limited to ethylene glycol and isopropanol;
(d) an alcohol cosolvent, such as, but not limited to, ethyl-hexyl
alcohols;
(e) water; and
a functionalized aqueous colloidal silica, which must be a brine resistant
surface
functionalized colloidal silica.
In another embodiment of a Hydrocarbon Recovery Fluid, which is a Micellar
Dispersion, the Hydrocarbon Recovery Fluid comprises surface functionalized
nanoparticles, the
fluid comprises:
(a) an oil fluid that is not a terpene,
(b) one or more surfactants selected from the group consisting of anionic
surfactants,
cationic surfactants, nonionic surfactants and amphoteric surfactants;
(c) an alcohol selected from the group consisting of CI-C8 alcohols; such
as, but not
limited to ethylene glycol and isopropanol;
(d) an alcohol cosolvent; such as, but not limited to, ethyl -hexyl
alcohols;
(e) water, and
a functionalized aqueous colloidal silica, which must be a brine resistant
surface
functionalized colloidal silica.
Examples of potentially suitable Hydrocarbon Recovery Fluids comprising brine
resistant
silica sols are in the following tables.
44
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨+ A
Supplier Chemistry Ingredientssl,
Any of Surface Treated
NCAC Examples 1-175 Silicasol 79.00 84.50 84.00
84.00
NaOH (1%) 10.00 10.00 9.00 9.50
Akzo
Nobel Nonionic Ethylan 1206 0.40 0.40 0.40
0.40
Stepan Nonionic BioSoft N91-6 0.50 0.50 1.00
1.00
Stepan Alkyl Olefin Sulfonate BioTerge AS-40 5.5
Cocamidopropyl
Stepan Sultaine Petrostep SB 4.60 4.60
Lauramidopropyl
Stepan Betaine Amphosol LB 5.60
Cocamidopropyl
Stepan Betaine PetroStep CG-50 5.10
Total 100.00 100.00 100.00 100.00
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨>
Supplier Chemistry Ingredients4,
Any of Surface Treated
NCAC Examples 1-175 Silicasol 84.90 84.60 83.6 83.00
NaOH (1%) 10.00 10.00 10 9.50
Akzo
Nobel Nonionic Ethylan 1206 0.40 0.40 0.4
Evonik Nonionic Surfynol 420 0.50
Stepan Nonionic BioSoft N91-6 1.00 1.00 1.00
1.00
Alkyl Olefin
Stepan Sulfonate BioTerge AS-40 5 6.00
Stepan Blended Betaine PetroStep MME 50 3.70
Sodium Trideceth
Stepan Sulfate Cedepal TD 407 4.00
Total 100.00 100.00 100.00 100.00
46
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
Examples¨)
Supplier Chemistry Ingredients40
Any of
NCAC Examples 1-175 Surface Treated Silicasol 84.00
84.00 84.00 84.00
NaOH (1%) 10.00 10.00 10.00 10.00
Stepan Nonionic BioSoft N91-6 0.50 1.00 1.00
1.00
Stepan Alkyl Olefin Sulfonate BioTerge AS-40 5.5
Croda Ethoxylated Castor Oil Etocas 200 SO MV 5.00
Croda Ethoxylated Castor Oil Etocas 29 LQ RB 5.00
Croda Ethoxylated Castor Oil Etocas 35 LQ MH 5.00
Total 100.00 100.00 100.00 100.00
47
GA 03076007 2020-03-16
WO 2019/067478
PCT/US2018/052736
Examples¨) M N 0
Supplier Chemistry Ingredients40
Any of
NCAC Examples 1-175 Surface Treated Silicasol 84.00
84.00 84.00
NaOH (1%) 10.00 10.00 10.00
Evonik Nonionic Surfynol 420 5
Stepan Nonionic BioSoft N91-6 1.00 1.00 1.00
Stepan Alkyl Olefin Sulfonate BioTerge AS-40
5.00
Total 100.00 100.00 100.00
48
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
Examples¨) P Ct R S T U VW
Supplier Ingredients4.
Brine Resistant
Silica Sol made
from ST-32C
available from .. Surface
Nissan Chemical Treated
Corporation Ltd. Silicasol 21 20.5 16.5 14.4
Brine Resistant
Silica Sol made
from ST-025
available from
Nissan Chemical Surface
America Treated
Corporation Silicasol 42 37.4 33.5 29.4
Dipentene (oil
phase) available
from Vertec VertecBio
Biosolvents DLR 0.5 1.05 1 1.1 0.5 1.05 1 1.1
Methyl Soyate VertecBio
(oil phase) Gold 11 11.5 12 12.5 11 11.5 12 12.5
Water Any Source 9 6 7 8 9 8 7 6
Isopropanol Any Supplier 10 11 12 13 13 12 11 10
Alkyl Olefin
Sulfonate, 40%
Actives available
from Solvay AOS-40 39 40 41 40 15 20 25 30
Nonionic
surfactant
available from
AkzoNobel Ethylan 1206 9.5 10 10.5 11 9.5 10 10.5 11
Total 100 100 100 100 100 100 100 100
The gas is selected from the group consisting of carbon dioxide, nitrogen,
natural gas,
liquified natural gas, liquified carbon dioxide and/or mixtures thereof. The
motility of the gas is
used to distribute the nanoparticles more effectively and push them deeper
into the formation,
allowing the gas and nanoparticles to maximize their production enhancement
capabilities
Successful treatment enhances production for six months or more thanks to the
effective
penetration and residual value of the nanoparticles. This process is extremely
flexible and can
therefore be used with all types of wells, including conventional,
unconventional and oil and gas
wells.
49
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
The first generation of nanoActiv HRT nanoparticles are designed specifically
to be
used in combination with carbon dioxide, nitrogen, natural gas, liquified
natural gas, liquified
carbon dioxide and/or mixtures thereof. The first generation of nanoActiv HRT
is not designed
to work well with Steam. Steam is not required or desirable to be used in
combination with the
first generation of nanoActiv HRT patent pending technology. Steam remains a
potential gas
for use in combination with future generations of Hydrocarbon Recovery Fluids
comprising
surface functional ized nanoparticle products.
The gas itself delivers a range of benefits, for example:
= Stimulating the well with pressure, mobilizing oil or gas to the
wellbore;
= Removing debris, fines and other matter (removing the well skin);
= Swelling and reducing the viscosity of the oil, facilitating mobilization
of oil when
miscible;
= Displacing oil or gas in the reservoir, mobilizing to the wellbore; and
= Altering wettability characteristics, removing fluids causing blockages
near the wellbore
area by changing their wettability to a more neutral wet state.
RECHARGE HNPTM is the tradename for a prescribed, simple, flexible remediation
treatment for wells consisting of the three Huff' n Puff phases: injection,
soaking and production.
Thanks to the synergies between the developmental nanoActiv Hydrocarbon
Recovery Fluids
comprising surface functionalized nanoparticle products and the gas, the soak
times can be
dramatically reduced compared with traditional HNP treatments. Depending on
the type of
formation, well history and identified issues, a specific treatment plan is
prescribed.
RECHARGE HNPTM treatment comprises a three-phase process of
1) screening the well candidates,
2) specifying and prescribing the treatment, and
3) implementing the treatment.
This also includes monitoring post-treatment production up to 180 days to
determine the
most suitable next-stage treatment. Wells must be screened and analyzed to
ensure the correct
treatment is applied. This is vital to ensuring the treatment has the desired
effect on productivity.
Table 11 following highlights the current screening criteria:
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
Production Good initial production (IF ) with gradual decline
curve that indicates
continuouswell depletion, wettability issues
CUrrent production <10-20% of IPand preferably >5-10 BCFD 01 20 mscfd
Reid data V.ell performance should be on par with other wells in
the field: thief
zones and extensive fractures need to be understood
Treatments Acid and other chemical treatments may negatively
impact properties of
nanoActiv
VVell equipment To be in good mechanical condition. Pumps, linings,
gaskets. Ensure
pressure tested or assurance for pressure treating levels.
VVater Too high content of salts (e.g. KO) and TDSmay
negatively impact
nanoActiv
VVater cut <80% (N2), <90% ((¨P) ideal, may go higher with
greatertreatment
dosages
Net Pay Zone <100 ft (30 m) vertical to optimize 60-90 days pay-
back.
Porosity Porosity! >8% conventional. >4% unconventional
oii at gravity <30 API, 032 preferred
Avoid asphaltenes precipitation conditions
Table a Well screening criteria for RECHARGE HNPTM
EXAMPLE
This example describes work done in combining nitrogen and a developmental
nanoActiv Hydrocarbon Recovery Fluid product comprising brine resistant
silicasol
nanoparticles, sodium hydroxide, one anionic surfactant and one nonionic
surfactant in the
Austin Chalk and Buda formations.
This case study focuses on a number of aged, depleted wells (some shut-in) in
the Buda
and Austin Chalk formations in Central Texas (USA). These wells are horizontal
open-hole
completions. Prior to this work, the operator of the wells initially injected
small amounts of N2
into each well (60 tons per well) to try to improve productivity.
A developmental nanoActiv Hydrocarbon Recovery Fluid product previously
described
is used in combination with nitrogen as a way of achieving better, longer-
lasting results.
The process for treatment of each well is as follows:
1) A fresh water pill is introduced to the well formation,
2) The developmental nanoActiv Hydrocarbon Recovery Fluid is introduced into
the
well formation,
3) then nitrogen is introduced into the well formation,
51
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
4) Steps 2) and 3) are repeated in sequence at least four more times.
Field Treatment Program
Five wells are treated with various amounts of developmental nanoActiv
Hydrocarbon
Recovery Fluid comprising surface functionalized nanoparticles along with a
constant volume of
60 tons of Nitrogen per well.
The well candidates, Nitrogen volumes and stages of injection are chosen by
the operator.
The following is a summary of the well treatment for each of the identified
wells:
. Buda Well A ¨ totals: 500 gallons fresh water pill, 2500 gallons
developmental
nanoActiv , 60 tons Nitrogen
. Buda Well B ¨ totals: 500 gallons fresh water pill, 2500 gallons
developmental
nanoActiv , 60 tons Nitrogen
= Buda Well C ¨ totals: 500 gallons fresh water pill, 3000 gallons
developmental
nanoActiv , 60 tons Nitrogen
. Austin Chalk Well A ¨ totals: 500 gallons fresh water pill, 7500 gallons
developmental
nanoActiv , 60 tons Nitrogen
= Austin Chalk Well B ¨ totals: 500 gallons fresh water pill, 7500 gallons
developmental
nanoActiv , 60 tons Nitrogen
After monitoring productivity for 180 days after treatment and thoroughly
analyzing the
production results, several observations are recorded. All five wells respond
to the treatment.
Looking at the dosage of treatment relative to the treatment area, there is a
direct, one-to-one
correlation between dosage and treatment response. The areas that receive the
higher doses of
gas and nanoparticles produce better results.
The responses of four of the five wells, two in Austin Chalk and two in Buda,
are shown
in Figures 4 and 5. The fifth well receives the lowest treatment dosage (45
percent lower than the
highest dosage) and initially the only response observed on this well is
excess water removal.
After approximately 160 days of production and excess water removal, a 20
percent uptick in
average daily oil production is recorded.
52
GA 03076007 2020-03-16
WO 2019/067478 PCT/US2018/052736
In addition to the direct correlation between the dosage applied to the wells
and their
responses (improvement in hydrocarbon production expressed as a percentage),
there is also a
direct correlation between the dosage and the duration of the treatment
response. This can be
seen in Table 13.
High Correlation Between Dosage and Yield
Treatment production Dosage of treatment Well response
response (days) (ranking) (ranking)
Buda, Well A 90 3 4
Buda, Well B 180 1 1
Austin Chalk, Well A 90 4 3
Austin Chalk, Well B 180 2 2
Table 13 Correlation between the treatment dosage Nitrogen and developmental
nanoActv
Hydrocarbon Recovery Fluid comprising surface functionalized nanoparticles) in
the Austin
Chalk and Buda wells and the well production response and the duration of the
response.
RECHARGE HNPTM is a multi-spectrum, proprietary remediation treatment for
wells
with a range of production problems. Combining the properties of gas and
nanoparticles creates a
unique, synergistic treatment that addresses several potential production
issues simultaneously,
while being less cost-intensive than alternative solutions. The extended scope
is extremely useful
because wells often experience a combination of issues that lead to a decline
in productivity or,
in many cases, operators do not know the full extent of the downhole problems
Successful treatments enhance production by six months or more, thus reducing
periodicity of repeated treatments. RECHARGE HINPTM is highly flexible and
easy to
implement: it can be used with all types of wells, including conventional,
unconventional and oil
and gas wells.
While the foregoing disclosure discusses illustrative aspects and/or
embodiments, it
should be noted that various changes and modifications could be made herein
without departing
from the scope of the described aspects and/or embodiments as defined by the
appended claims.
Furthermore, although elements of the described aspects and/or embodiments may
be described
or claimed in the singular, the plural is contemplated unless limitation to
the singular is explicitly
53
stated. Additionally, all or a portion of any aspect and/or embodiment may be
utilized with all or
a portion of any other aspect and/or embodiment, unless stated otherwise.
54
Date Recue/Date Received 2021-08-18
