RO134503A2 - Use of gas and hydrocarbon recovery fluids with nanoparticle content for improving hydrocarbon recovery - Google Patents

Abstract

The invention relates to a process for recovering hydrocarbons from underground formations using gases, such as CO2, nitrogen, natural gases, liquefied natural gases, liquefied CO2 and/or mixtures thereof in combination with functionalized materials, such as nanoparticles or mixtures of nanoparticles. According to the invention, the process consists in introducing a gas, a liquefied gas or a vaporized liquefied gas into an underground formation containing hydrocarbons, such as crude oil and gas, which allows the said gas to be absorbed by the said hydrocarbons, followed by extracting the said gas-containing hydrocarbons, wherein a compressed tablet of hydrocarbon recovery fluid comprising surface functionalized nanoparticles is introduced into the underground hydrocarbon-containing formation before, during or after introducing the gas, the liquefied gas or the vaporized liquefied gas .

Description

OFFICE AND STATE FOR INVENTIONS AND TRADEMARKS Patent Application ₁ Filing Date

Cross-reference to related patent applications

This patent application claims priority over U.S. Provisional Patent Application No. 62 / 563,415, filed on September 26, 2017 and claims priority over US provisional patent application No. 62 / 697,321; submitted on: July 12, 2018. These applications are included in this document in full.

FIELD OF THE INVENTION

The present invention relates to improved methods of recovering hydrocarbons using gases such as carbon dioxide, nitrogen, natural gas, liquefied natural gas, liquefied carbon dioxide and / or mixtures thereof in combination with functionalized materials, such as nanoparticles or mixtures of nanoparticles.

Context of the invention

There are approximately 1.7 million active oil and gas wells in the United States. At this point, hundreds of thousands of these oil and gas wells have shrunk or depleted to the point of being marginally profitable. As well as the age of the wells, multiple mechanisms contribute to the decline in production.

In addition to mechanical failures of a well's infrastructure, the following damage to the formation accelerates the decline in production:

- A decrease in pressure at the bottom of the well as it depletes, which decreases relative permeability and increases the liquefied load

- Migrations of particles, mechanically induced by flow velocity ¹

- Detachments, deposits, paraffins / asphaltenes and expandable clay

- Condensed water or block

- Fracture blows (tailcoat) improving the productivity of the well has traditionally been done using stimulation methods that increase the permeability of the accumulation rock or decrease the viscosity of the oil. Matrix acidification (see: “Knowledge and future developments on sandstone matrix acidification” (Sandstone Matrix Acidizing Knowledge and a 2020 00155

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Future Development), by Mian Umer Shafiq and Hisharn Ben Mahmud, J. Petrol Explor Prod Technol (2017) 7: 1205-1216), as a method of stimulation is relatively inexpensive but limited as an area of applicability. Ideal candidates for this process usually include wells in formations with a permeability> 10 mD and in which the dry matter clogs the pores near the well and / or at the holes. The refracting process is at the other end of the spectrum. It can be used to boost productivity, but it is a more expensive option and a riskier proposition, especially for unconventional wells.

Liquefied gases and gases such as carbon dioxide, nitrogen, natural gas, liquefied natural gas and liquefied carbon dioxide have a long history of improving relative permeability, providing energy and training in miscible and immiscible recovery applications. Studies have shown that Huff n Puff treatments (hereinafter referred to as "HNP") with gas have achieved particularly positive results for oil recovery and short-term production (Figure 2).

Nitrogen-HNP has also shown very beneficial results in field studies conducted in appropriate formations in the Appalachian Basin (see "The Field Case: Cyclic Recovery of Light Petroleum Gas Using Carbon Dioxide / Nitrogen / Natural Gas", by BJ Miller and T. Hamilton-Smith, SPE 49169, Conference: Annual Technical Meeting and SPE Exhibition, September 1998). HNP treatments to stimulate well production are usually individual treatments, cyclic treatments for wells, comprising three phases: injection, soaking and production.

HNP also provides important information on injectivity and pressure communication with adjacent wells. As a proven stimulus method for a single well, they can dramatically increase production at depleted, depleted or low pressure oil wells. Under certain conditions, carbon dioxide and nitrogen can become miscible with crude oil, lowering viscosity and therefore further improving recovery.

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Over the years, HNP treatments with carbon dioxide, nitrogen, natural gas, liquefied natural gas and liquefied carbon dioxide have been used as an affordable and effective means of improving recovery. They are an ideal solution for marginal wells in advanced decline and an effective way to stimulate tanks with insufficient inter-well communications. More recently, studies have shown that HNP injection is a more effective method of improving shale oil production than continuous gas flooding (see “Optimizing Huff-n-Puff Gas Injection in Shale Oil Tanks”), by J.J. Sheng, Petroleum, 2017 and “Gas Selection for Huff-n-Puff EOR in Shale Oil Reservoirs Based on an Experimental and Numerical Study,” by L. Li and J.J. Sheng, SPE-185066-MS, 2017.)

Treatments can be applied to a single well several times to support enhanced oil recovery (IOR) and optimized oil recovery (EOR). Small volumes of carbon dioxide can lead to significant increases in recoverable reserves and production that ensure rapid depreciation due to increased production.

Nanoparticles have been at the forefront of research in various applications in the oil and gas industry for at least a decade. Nanoparticles are usually particles below 100 nm and can be made of various inorganic materials, such as silica, alumina and iron oxides. Nanoparticles can be structured to contain an inner core and an outer shell (see "Nanofluid Science and Technology", by SK Das, SUS 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. The nanoparticles (unmodified or modified) can then be dispersed in an aqueous or organic medium, such as water, methanol or isopropanol, and disposed of. Nanoparticles are extremely versatile and can be designed for specific applications.

The true mode of action of nanoparticles in a tank depends on how they are designed and arranged. However, laboratory studies have shown that dispersed nanoparticles can align with the oily, aqueous, solid contact angle of 2020 00155

25/09/2018 three-phase (see “Spread of nanofluids on solids”, by D.T.Wasan and Nikolov, Journal of Nature (423): 156-159, A. 2003.). The alignment of nanoparticles in a taper between oil and rock generates what is known as disjunctive structural pressure, which helps create a pressure gradient sufficient to lift a drop of oil off the surface of the rock. This phenomenon leads to increased oil recovery rates and has been demonstrated in absorption and flow tests (see "Spread of nanofluids on solids", by DTWasan and Nikolov, Journal of Nature (423): 156-159, A. 2003 .).

In the field, case studies have been reported that have shown the efficiency of nanoparticle dispersions. In a field study, a dispersion of silicon dioxide-based nanoparticles was implemented in a hydraulic fracturing application (see: "Applying nanofluidic technology to improve recovery in oil and gas wells" by PM Mcelfresh, DL Holcomb and D. Ector. Societatea Inginerilor Petrolieri, two: 10.2118 / 154827-MS, 2012, January 1). The dispersion was disposed of as a pre-buffer tablet prior to the buffering stage in a fracturing operation for the first contact with the five-well tank of the Wolfcamp and Bone Spring formations in the Permian Basin. Field results showed significant increases in initial production of about 20 percent compared to type curves. These percentages appeared to be maintained for successful wells even in the presence of a compensated fracture discovery. The results also showed a decrease in the initial effective decline rate.

Additional references in this area include:

Carpenter, C, Journal of Petroleum Technology, Modeling the Production Decline Caused by Particle Migration in Deepwater Tanks, February 2018; Eagle Ford curve, eia.gov/analysis/studies/usshalegas/pdf/usshaleplays.pdf;

Wei, B., Pu, W., Pang, S., Kong, L., Mechanisms of N2 and CO2 The Huff-n-Puff Steam Assisted Process in Improving Heavy Oil Recovery: A Case Study Using Experimental and Numerical Simulation , Conference: Conference: Oil and Gas Show and Conference, Middle East SPE, January 2017;

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Miller, B.J., Hamilton-Smith, T., SPE 49169 “Field case: Cyclic recovery of light petroleum gas using carbon dioxide / nitrogen / natural gas”, Conference: Annual Technical Meeting and SPE Exhibition, September 1998;

Sheng, J. J., Optimizing 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 on an experimental and numerical study, SPE-185066-MS, 2017;

Palmer, FS, Landry, RW, Bou-Mikael, S. SPE 15497, “Design and Implementation of Immiscible Carbon Dioxide (CO2 Huff-Puff) Transfer Projects in South Louisiana,” Conference: Annual Technical Meeting and SPE Exhibition, October 1986;

Das, S.K., Choi, S.U.S., Yu, W., and Pradeep, T. 2008. Nanofluid science and technology. Hoboken, New Jersey: John Wiley & Sons, Inc. Publishing. ISBN 0470074736;

Wasan, D.T., and Nikolov, The spread of nanofluids on solids. Journal of Nature (423): 156-159, A. 2003;

Mcelfresh, P. M., Holcomb, D. L., & Ector, D. Application of nanofluid technology to improve recovery in oil and gas wells. Society of Petroleum Engineers, two: 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. improving stimulation results in the Delaware Basin using nanoparticle dispersion technology. Society of Petroleum Engineers, two: 10.2118 / 189876-MS, 2018, January 23.

U.S. Pat. No. 4,390,068, "Carbon dioxide-stimulated oil recovery process", issued on June 8, 1983, describes and claims a process for stimulating the recovery of oil using liquid carbon dioxide. Carbon dioxide is introduced into an underground formation, where it partially dissolves in the crude oil present in it. A back pressure in the atmospheric range up to about 300 psi is maintained on the formation, while oil containing carbon dioxide is extracted. Subsequently, carbon dioxide is separated from oil.

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U.S. Pat. no. No. 5,381,863, "Cyclic Huff-n-Puff with Immiscible Injection and Miscible Production Steps" issued on January 17, 1995, describes and claims a method of recovering hydrocarbons from a tank under an active watercourse or by pressure by injecting a recovery fluid containing immiscible carbon dioxide or nitrogen, allowing the recovery fluid to soften and producing recovery fluid and formation fluids under miscible or miscible conditioned conditions, after the pressure has increased sufficiently in the well area .

U.S. Pat. no. 7.216.712 "Treatment of oil wells" issued on May 15, 2007, describes and claims a method in which hydrocarbon solids are removed from an oil well by introducing into the oil well a composition comprising at least 40 vol. % carbon dioxide in dense phase and at least 30 vol. % of a C3 alkanol component and, optionally, one or more surfactants, under a pressure of 300 to 10,000 psia and a temperature of 90 ° F. up to 120 ° F., keeping the composition in the well to solubilize the hydrocarbon solids, then removing from the well a liquefied composition comprising solubilized hydrocarbon solids and alkanol. Gases such as carbon dioxide, nitrogen, natural gas and / or liquefied natural gas can also be used in the fracturing without water of a suitable formation containing hydrocarbons.

The article, “Waterless Fracturing Technologies for Unconventional Liquefied Nitrogen Tank Opportunities,” Journal of Natural Gas Science and Engineering, 35 (2016) 160-174, by Lei Wang et al., Describes waterless fracturing technologies. Over the past two decades, hydraulic fracturing has significantly improved oil and gas production from shale and watertight reservoirs in the United States and elsewhere. Given the damage to the formation, water consumption and environmental impact associated with water-based fracturing fluids, efforts have been made to develop waterless fracturing technologies because of their potential to mitigate these problems. Key theories and characteristics of waterless fracturing technologies are analyzed, including energized oil and carbon dioxide oil fracturing, explosive and propellant gas fracturing by 2020 00155

25/09/20 liquefied petroleum ("LPG") and alcohol fracturing, gas fracturing, carbon dioxide fracturing and cryogenic fracturing. Experimental results describing the effectiveness of liquefied nitrogen in improving the initiation and propagation of fractures in concrete samples and shale and sandstone reservoir rocks are presented. In the laboratory study, the generated cryogenic fractures were characterized qualitatively and quantitatively by pressure decomposition tests, acoustic measurements, gas fracturing and CT scans. The capacity and application of cryogenic fracturing through the use of liquefied nitrogen are demonstrated and examined. By correctly formulating technical procedures for field implementation, cryogenic fracturing using liquefied nitrogen could be an advantageous option for fracturing unconventional tanks.

The Linde Group is one of the most important gas and engineering companies in the world, present in over 100 countries worldwide. The Linde Group is headquartered at Klosterhofstrasse 1.80 331 Munich, Germany, 80331. Since the early 1990s, Linde has implemented Huff * n Puff technology to inject carbon dioxide into depleted wells for incremental increase in oil production. Less expensive than refracting, Huff'n Puff provides the energy to provide hydrocarbons in low-pressure areas with the rising force needed to make them flow into the well.

Nissan Chemical America Corporation is a leading manufacturer of colloidal silica and colloidal electro-conductive oxide solutions. Headquartered in 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 commercial colloidal silica products as well as hydrocarbon recovery fluids containing colloidal silica products.

Improved oil recovery methods are playing an increasingly important role in the oil and gas industry as existing land is depleted, leading to reduced production. What would be desirable are methods of stimulating (remedying) new and modified wells to increase the recovery of 2020 00155

09/25/2018 ^ p hydrocarbons and reducing the water content in crude oil from an underperforming well, preferably using non-hydric materials

Summary of the invention

The first aspect of the present invention is a process for stimulating the recovery of hydrocarbons, comprising (a) introducing a gas, a liquefied gas or a vaporized liquefied gas into an underground formation containing hydrocarbons;

(b) allowing the absorption of that gas or a liquefied and vaporized gas by those hydrocarbons, (c) withdrawal of said hydrocarbons containing that gas, liquefied gas or liquefied vapor gas absorbed therein; and wherein a hydrocarbon recovery fluid tablet comprising surface functionalized nanoparticles is introduced into the hydrocarbon-containing underground formation 15 before, during or after the introduction of the gas, liquefied gas or vaporized liquefied gas.

The second aspect of the present invention is to process the first aspect of the present invention in which the injected gas, the liquefied gas 20 or a vaporized liquefied gas and the hydrocarbon recovery fluid containing surface-functionalized nanoparticles may also include one or more. several injected substances, selected from the group consisting of fresh water, KCI water, derivatives and any other injected substance currently used in the remediation of the oil field as part of the treatment.

The third aspect of the present claimed invention is the processing of the first aspect of the present invention in which the hydrocarbon recovery fluid tablet containing surface-functionalized nanoparticles is introduced into the underground formation containing hydrocarbons before the introduction of liquefied gas. or a vaporized liquefied gas.

The fourth aspect of the present claimed invention is to process the first aspect of the present invention in which the fluid tablet of 2020 00155

25/09/2018, recovery of hydrocarbons containing surface-functionalized nanoparticles is introduced into the underground formation containing hydrocarbons before the introduction of gas, liquefied gas or vaporized liquefied gas.

The fifth aspect of the present invention is the processing of the first aspect of the present invention in which the hydrocarbon recovery fluid tablet containing surface-functionalized nanoparticles is introduced into the underground formation containing hydrocarbons before the introduction of gas, liquefied gas or liquefied gas. a vaporized liquefied gas.

The sixth aspect of the present claimed invention is the processing of the first aspect of the present claimed invention, in which said gas is selected from the group consisting of carbon dioxide, nitrogen, natural gas, liquefied natural gas, liquefied carbon dioxide and / or mixtures thereof. .

The seventh aspect of the present claimed invention is the processing of the first aspect of the present claimed invention in which said gas is carbon dioxide.

The eighth aspect of the present claimed invention is to process the first aspect of the present claimed invention in which said gas is nitrogen.

The ninth aspect of the present claimed invention is the processing of the first aspect of the present claimed invention in which said gas is natural gas.

The tenth aspect of the present claimed invention is to process the first aspect of the present claimed invention in which said gas is liquefied natural gas, liquefied carbon dioxide and / or mixtures thereof.

The eleventh aspect of the present claimed invention is the processing of the sixth aspect of the present claimed invention in which said gas is a mixture of two or more gases selected from the group consisting of 2020 00155

25/09/2018 ^ / £ of carbon dioxide, nitrogen, natural gas, liquefied natural gas, liquefied carbon dioxide and / or mixtures thereof.

J

The twelfth aspect of the present claimed invention is the processing of the first aspect of the present claimed invention in which said process is part of a huff and puff treatment process.

The thirteenth aspect of the present claimed invention is the processing of the eleventh aspect of the present claimed invention, wherein said process is a waterless fracturing process.

The fourteenth aspect of the present claimed invention is in the processing of the thirteenth aspect of the present claimed invention, wherein said process is a waterless fracturing process.

The process of stimulating the recovery of hydrocarbons comprises the injection of a gas such as carbon dioxide, nitrogen, natural gas, liquefied natural gas, liquefied carbon dioxide and / or mixtures thereof into an underground formation * 1 containing hydrocarbons, allowing the gas respectively to eliminate liquids, such as condensation, water, etc. and so on and debris in the nearby drilling area and pressurize the well to 500 psi. If the gas is miscible in crude oil, the gas will cause it to swell and reduce viscosity. The stimulation process includes combining the gas injection with a hydrocarbon recovery fluid tablet comprising surface-functionalized nanoparticles that can be introduced before, during or after the gas.

Surface-functionalized nanoparticles have unique unique properties that allow the production of hydrocarbons from micro to nano-sized spaces, including those spaces classified as voids or fractures. Surface-functionalized nanoparticles can cause changes in the wettability of solid / liquid surfaces that facilitate flow. The stimulation process involves the combination of gas and hydrocarbon recovery fluid, comprising nanoparticles of 2020 00155

25/09/2018 ^ were nationalized on the surface, which leads to an improvement in hydrocarbon production that is attributed to synergistic effects.

Brief description of the drawings

Fig. 1. Example of the productivity decline curve. Taken from Palmer, FS, Landry, RW, Bou-Mikael, S. SPE 15497, “Design and Implementation of Immiscible Carbon Dioxide (C02 Huff-Puff) Transfer Projects in South Louisiana,” Conference: Annual Technical Meeting and SPE exhibition, October 1986. It is not an example of the present claimed invention.

Fjg 2. Comparisons of oil recovery using CO2, N2, and HNP steam treatments. Figure taken from Wasan, D.T., and Nikolov, The spread of nanofluids on solids. Journal of Nature (423): 156-159, A. 2003. It is not an example of the present claimed invention.

Fig 3: Nanoparticles aligned at the three-phase contact angle to support hydrocarbon recovery (see Wasan et al., 2003). It is not an example of the present invention.

Fig. 4. Cumulative oil production for Austin Chalk wells before and after N2 treatment and development of nanoActiv® HRT hydrocarbon recovery fluid containing surface-functionalized nanoparticles.

Fig. 5. BOE cumulative production for Buda wells before and after treatment with N2 and nanoActiv® HRT hydrocarbon recovery fluid for development containing surface-functionalized nanoparticles.

Fig 6. The three phases of an HNP treatment ™.

Detailed description of the invention

During the application of the present patent, the term "tablet" has the following definition: Tablet - Any relatively small amount of a particular mixture of drilling fluid to perform a specific task on which the drilling fluid »2020 00155

25/09/201 ordinary can not meet it. Fluid tablets are commonly prepared for a variety of special functions. Tablets are small amounts of drilling fluids and it is understood that several tablets may be added to a hydrocarbon formation.

The first aspect of the present invention is a process for stimulating the recovery of hydrocarbons, comprising (a) introducing a gas, a liquefied gas or a vaporized liquefied gas into an underground formation containing hydrocarbons;

(b) allowing the absorption of that gas, liquefied gas or liquefied gas vaporized by those hydrocarbons, (c) withdrawal of said hydrocarbons containing that gas, liquefied gas or vaporized liquefied gas absorbed therein; and wherein a hydrocarbon recovery fluid tablet comprising surface-functionalized nanoparticles is introduced into the hydrocarbon-containing underground formation before, during or after the introduction of the gas, liquefied gas or vaporized liquefied gas.

Surface-functionalized nanoparticles can be made of any suitable material. Unlimited examples of surface-functionalized nanoparticle materials include ceramics, metals, metal oxides (eg, silica, titanium, alumina, zirconium, vanadyl, cerium, 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., chromium 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.

In general, in oilfield applications it is well known that underground formations contain large amounts of water containing dissolved salts, such as NaCl, CaCb, KCI, MgCb and others. This aqueous mixture of salt is usually called saline. Saline conditions for different regions and 2020 00155

25/09/2018 wells vary greatly, with different conditions of well bottoms and lithologies. In general, the fluids used on the bottoms of wells must either tolerate salinity conditions or have saline resistance properties.

Colloidal systems in general and aqueous colloidal silica rely mainly on electrostatic repulsion between charged silica particles to avoid undesirable or adverse phenomena such as particle agglomeration, flocculation, gelation and sedimentation. This electrostatic repulsion is slightly disturbed under salinity conditions, which are usually found in underground formations. Furthermore, agglomeration / flocculation / gelation / sedimentation of colloidal silica and colloidal silica-containing liquids in well bottom applications would have the potential to damage the well or clog the well as a whole. Therefore, the application of colloidal silica in applications at the bottom of the well requires the printing of the saline-resistant properties of colloidal silica and fluids containing colloidal silica before application.

In order not to gel when exposed to saline (salt water), the nanoparticles must have a surface functionalization that stabilizes colloidal silica. The functionalization of the colloidal silica surface allows the colloidal silica to be resistant to the effects of saline (salt water) and heat. Surface-functionalized colloidal silica is usually referred to as "saline-resistant silica soils". Hydrocarbon recovery fluids containing surface-functionalized colloidal silica are used together with the gases described herein to effect the subsequent removal of hydrocarbons from underperforming wells.

The standard tests for saline stability are set out in the following paragraphs:

AP brine by visual observation:

A 10wt% API saline is prepared by dissolving 8wt% NaCl (SigmaAIdrich) and 2wt% CaCb (Sigma Aldrich) in distilled water. Testing the resistance to saline is done by placing 1 gram of silica soil sample in 10 grams of API saline. Stability observations are made at standard 10-minute and 24-hour saline exposure periods. These observations include the clarity and 1> ’» of 2020 00155 25/09/2018 the transparency of silica soil. The results of these observations are recorded during these periods. Silica soil solutions that are stable upon exposure to saline will remain clear and transparent / opalescent, while unstable examples become visibly blurry and opaque after exposure to saline.

Artificial seawater by visual observation:

Artificial seawater is prepared by dissolving Fritz Pro Aquatics RPM Reef Pro Mix (Fritz Industries, Inc.) to 6 wt% in distilled water. Testing the resistance to saline is done by placing 1 gram of silica soil sample in 10 grams of artificial sea water. Stability observations are made at standard 10-minute and 24-hour saline exposure periods. These observations include the clarity and transparency of silica soil. The results of these observations are recorded during these periods. Silica soil solutions that are stable upon exposure to saline will remain clear and transparent / opalescent, while unstable examples become visibly blurry and opaque after exposure to saline.

API saline resistance test when using a turbidimeter Reference: US EPA 180.1 Determination of turbidity by nephelometry

One 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 exceed 40 units: Dilute the sample with one or more volumes of water without turbidity until the turbidity falls below 40 units. The turbidity of the initial sample is then calculated from the turbidity of the diluted sample and the dilution factor. For example, if 5 volumes of water without turbidity were added to 1 volume of sample, and the diluted sample showed a turbidity of units, then the turbidity of the original sample was 180 units.

For this paper, the actual ("gross") value of turbidity is recorded, regardless of whether it is above, below or equal to 40.

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Test solutions / surface-treated silica soils are tested with turbidimetry for salinity resistance.

A Hach 2100 AN calibrated turbidimeter is used to measure turbidity in NTUs (nephelometric turbidity units).

The amounts of 3.0 g of test solution are placed in standard turbidity tubes of approximately 30 ml.

Twenty-seven grams (27g) of 10% API saline (8wt% NaCl, 2wt% CaCb) is added to the test tube and the mixture is inverted three times to mix the test solution and the saline solution. Test solution concentrations are »> 1 11 therefore 10wt% in API saline.

The test samples are introduced into the turbidimeter and an initial measurement of turbidity is performed immediately, followed by a measurement of turbidity after 24 hours.

A turbidity change greater than 100NTU leads to the conclusion that the silica soil is not stable in saline. Conversely, a change in turbidity of less than 100NTU after exposure to API saline leads to the conclusion that the silica soil is stable in saline.

Dynamic light diffusion method

If the silica particles in the aqueous silica soil are dispersed or coagulated, it can be determined by measuring the average particle diameter by dynamic light diffusion (average DLS particle diameter) for the silica particles of the silica soil in the chemical fluid.

The average diameter of DLS particles is the average value of the secondary diameter of particles (diameter of dispersed particles) and it is said that the average diameter of DLS particles in a completely dispersed state is approximately 2020 00155

25/09/2018 ^ _o twice the average particle diameter (which is the average value of the primary particle diameter in terms of the specific surface diameter obtained by measuring nitrogen absorption (BET method) or Sears particle diameter). It can then be determined that as the average diameter of the DLS particles increases, the silica particles in the aqueous silica soil become more coagulated.

if the hydrocarbon recovery fluid comprising surface-functionalized nanoparticles has good resistance to high temperatures and salt, the average diameter of the DLS particles after a high temperature and salt resistance test is almost the same as the average diameter of the DLS particles of the fluid chemical. For example, if the ratio of the average DLS particle diameter after a high temperature test to the salt resistance / average DLS particle diameter of the hydrocarbon recovery fluid comprising surface-functionalized nanoparticles is 1.1 or less, it shows that the fluid for the recovery of hydrocarbons comprising surface-functionalized nanoparticles, after a test of high temperature and salt resistance, maintain the dispersion state similar to that of the hydrocarbon recovery fluid, which comprises surface-functionalized nanoparticles. However, when the resistance to high temperatures and salt of the hydrocarbon recovery fluid containing surface-functionalized nanoparticles is weak, the diameter of DLS particles after a test of resistance to high temperatures and salt is much higher, showing that the Recovery of hydrocarbons containing surface-functionalized nanoparticles is in a coagulated state.

For the hydrocarbon recovery fluid containing surface-functionalized nanoparticles, if the ratio of the average diameter of DLS particles after a high temperature resistance test to the average diameter of DLS particles of the hydrocarbon recovery fluid comprising surface-functionalized nanoparticles is 1.5 or less (the change ratio of the average particle diameter is 50% or less), the conclusion reached is that the resistance to high temperatures and salt is good. If the ratio of the average DLS particle diameter after a high temperature resistance test to 2020 00155

25/09/2018 / / salt at the average diameter of the DLS particles of the hydrocarbon recovery fluid comprising surface-functionalized nanoparticles is 1.1 or less (the ratio of change of the average particle diameter is 10% or less) , there is no degradation of silica soil, the conclusion reached is that the resistance to high temperatures and salt is very good.

After several proposed tests of saline-resistant silica soils, it was found that the saline resistance of aqueous colloidal silica can be improved over untreated colloidal silica by adding certain types of organic surface treatment. There are many different types of organic surface treatments that can be used. The following are tables showing technologies for the preparation of the substance for many acceptable surface-treated colloidal silicas. These saline-resistant silica soils 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 the ingredient, per 100 parts of surface-treated colloidal silica.

ST-025 and ST-32C are commercially available colloidal silicas from Nissan Chemical America Corporation, headquartered at 10333 Richmond Avenue, Suite 1100 Houston, TX 77042 or from Nissan Chemical Corporation, headquartered in 5-1, Nihonbashi 2- Chome, Chuo-ku, Tokyo 103-6119, Japan.

Exemple- » 1 2 3 4 5 6 ingredients; ST-025 76 76 76 76 76 76 Deionized water 11.1 11.1 11.1 11.1 11.1 11.1 propylene 10 10 10 10 10 10 Succinic anhydride 3 (triethoxysilyl) propyl 2.9 1.9 1.9

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N- (triethoxysilylpropyl) -0Uretan polyethylene oxide 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 100.00 100.00 100.00 100.00 100.00 100.00

Example— »Ingredient], ST-025 7 76 8 76 9 76 10 76 11 76 12 76 13 76 Deionized water 11.1 11.1 11.1 11.1 11.1 11.1 11.1 propylene 10 10 10 10 10 10 10 Succinic anhydride 3- (triethoxysilyl) propyl 1.9 1.9 1.9 1.9 1.9 1.9 1.9 Hexamethyl disiloxane 1 Hexamethyl disilazan 1 Trimethoxy methyl silane 1 Trimethoxy phenyl silane 1 I came trimethoxysilane 1 3- (N, N-dimethylaminopropyl) trimethoxysilane 1 3 (diethylamino) propyl trimethoxysilane 1

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Total 100 100 100 100 100 100 100

Exemple- » 14 15 16 17 18 19 20 21 Ingredients! 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 10 10 10 10 10 10 10 10 Succinic anhydride 3 (triethoxysilyl) propyl 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 T rimethoxy (octadecyl) silane 1 Isobutyl trimethoxysilane 1 Hexiltrimetoxisilan 1 Deciltrimetoxisilan 1 Isooctiltrimetoxisilan 1 Hexadeciltrimetoxisilan 1 propyltrimethoxysilane 1 octyltriethoxysilane 1 Total 100 100 100 100 100 100 100 100

Exemple- » 22 2. 3 24 25 26 27 28 29 30 ingredients; 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 11.1 propylene 13 8 10 12 10 10 10 10 10 Succinic anhydride 3 (triethoxysilyl) propyl 2.9 Urethane Polyethylene N-oxide N (triethoxysilylpropyl) 2.9 1.9 1.9 1.9 1.9 1.9

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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

Exemple- » 31 32 33 34 35 36 37 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 propylene 10 10 10 10 10 10 10 Urethane Polyethylene N-oxide N (triethoxysilylpropyl) 1.9 1.9 1.9 1.9 1.9 1.9 1.9 Trimethoxy phenyl silane 1 I came trimethoxysilane 1 3- (N, N-dimethylaminopropyl) trimethoxysilane 1

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3- (diethylamino) propyl trimethoxysilane 1 Trimethoxy (octadecyl) silane 1 Isobutyl trimethoxysilane 1 Hexyl-trimethoxysilane 1 Total 100 100 100 100 100 100 100

Examples ^ 38 39 40 41 42 Ingredients! ST-025 76 76 76 76 76 Deionized water 11.1 11.1 11.1 11.1 11.1 propylene 10 10 10 10 10 Urethane Polyethylene N-oxide N (triethoxysilylpropyl) 1.9 1.9 1.9 1.9 1.9 Deciltrimetoxisilan 1 Izooctiltrimetoxisilan 1 Hexadeciltrimetoxisilan 1 propyltrimethoxysilane 1 Octyl-triethoxysilane 1 Total 100.00 100.00 100.00 100.00 100.00

Exemple- » 43 44 45 46 47 48 49 50 51

Ingredients!

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

»2020 00155 25/09/2018

propylene 11.1 12.1 11 6 10 10 10 10 10 Succinic anhydride 3 (triethoxysilyl) propyl 2.9 Urethane Polyethylene N-oxide N (triethoxysilylpropyl) 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

Example> 52 53 54 55 56 57 58

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 propylene 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

25/09/2018>) a 2020 00155

Trimethoxy phenyl silane 1 I came trimethoxysilane 1 3- (N, N-dimethylaminopropyl) trimethoxysilane 1 3- (diethylamino) propyl trimethoxysilane 1 T rimethoxy (octadecyl) silane 1 Isobutyl trimethoxysilane 1 Hexiltrimetoxisilan 1 Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00

Exemple- * 59 60 61 62 63 Ingredients! ST-025 76 76 76 76 76 Deionized water 11.1 11.1 11.1 11.1 11.1 propylene 10 10 10 10 10 Silane, trimethoxy [3 (oxiranyl methoxy) propyl] 1.9 1.9 1.9 1.9 1.9 Deciltrimetoxisilan 1 Isooctiltrimetoxisilan 1 Hexadeciltrimetoxisilan 1 propyltrimethoxysilane 1 octyltriethoxysilane 1 Total 100.00 100.00 100.00 100.00 100.00

Exemple- * 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 10 10 10 10 10 10 10 10 10 10

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Succinic anhydride 3 (triethoxysilyl) propyl 1.45 Urethane Polyethylene N-oxide N (triethoxysilylpropyl) 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 T rimethoxy phenyl silane 1 Total 100 100 100 100 100 100 100 100 100 100

Example »74 75 76 77 78 79 80 81

Ingredients]

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 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

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I came trimethoxysilane 1 3- (N, N- Dimethylaminopropyl) trimethoxysilane 1 3- (diethylamino) propyl trimethoxysilane 1 T rimethoxy (octadecyl) silane 1 Isobutyl trimethoxysilane 1 Hexiltrimetoxisilan 1 Deciltrimetoxisilan 1 1 sooctiltri methoxysil n 1 Hexadeciltrimetoxisilan propyltrimethoxysilane octyltriethoxysilane Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00

Exemple- * 82 83 84 ingredients; ST-025 76 76 76 Deionized water 11.1 11.1 11.1 propylene 10 10 10 3-ureidopropyl triethoxysilane 1.9 1.9 1.9 Hexadeciltrimetoxisilan 1 propyltrimethoxysilane 1 octyltriethoxysilane 1 Total 100.00 100.00 100.00

Exemple- * 85 86 87 88 89

ingredients;

ST-025 76 76 76 76 76 Deionized water 11.1 11.1 11.1 11.1 11.1 ethylene 10 10 10 10 10

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Succinic anhydride 3 (triethoxysilylpropyl) propyl 2.9 1.9 Urethane Polyethylene N-oxide N (triethoxysilylpropyl) 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 Hexamethyl disiloxane Hexamethyl disilazan Total 100.00 100.00 100.00 100.00 100.00

Exemple- » 90 91 92 Ingredients! ST-025 76 76 76 Deionized water 11.1 11.1 11.1 ethylene 10 10 10 Succinic anhydride 3 (triethoxysilylpropyl) propyl 1.9 1.9 1.9 3- (Trimethoxysilyl) propyl methacrylate 1 Hexamethyl disiloxane 1 Hexamethyl disilazan 1 Total 100.00 100.00 100.00

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Exemple- » 93 94 95 96 97 98 99 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 10 10 10 10 10 10 10 Succinic anhydride 3 (triethoxysilylpropyl) propyl 1.9 1.9 1.9 1.9 1.9 1.9 1.9 Trimethoxy methyl silane 1 Trimethoxy phenyl silane I came trimethoxysilane 1 Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00

Exemple- » ingredients; 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 10 10 10 10 10 10 Succinic anhydride 3- (Triethoxysilyl) propyl 1.9 1.9 1.9 1.9 1.9 1.9 Hexiltrimetoxisilan 1 Deciltrimetoxisilan 1 Isooctiltri metoxis ilan 1 Hexadeciltrimetoxisilan 1 propyltrimethoxysilane 1 octyltriethoxysilane 1 Total 100.00 100.00 100.00 100.00 100.00 100.00

Exemple- » 106 107 108 109 110 111 112 ingredients; 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

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ethylene 8 12 10 10 10 10 10 Succinic anhydride 3 (triethoxysilyl) propyl 1.45 Urethane Polyethylene N-oxide N (triethoxysilylpropyl) 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

Exemple- » 113 114 115 116 117 118 ingredients; ST-025 76 76 76 76 76 76 Deionized water 11.1 11.1 11.1 11.1 11.1 11.1 ethylene 10 10 10 10 10 10 Urethane Polyethylene N-oxide N (triethoxysilylpropyl) 1.9 1.9 1.9 1.9 1.9 1.9 Hexamethyl disilazan 1 Trimethoxy methyl silane 1 Trimethoxy phenyl silane 1

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I came trimethoxysilane 1 3- (N, N-dimethylaminopropyl) trimethoxysilane 1 3- (diethylamino) propyl trimethoxysilane 1 Total 100.00 100.00 100.00 100.00 100.00 100.00

Exemple- * 119 120 121 122 123 124 125 126 Ingredients! 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 10 10 10 10 10 10 10 10 Urethane Polyethylene N-oxide N (triethoxysilylpropyl) 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 T rimethoxy (octadecyl) silane 1 Isobutyl trimethoxysilane 1 Hexiltrimetoxisilan 1 Deciltrimetoxisilan 1 Isooctiltrimetoxisilan 1 Hexadeciltrimetoxisilan 1 propyltrimethoxysilane 1 octyltriethoxysilane 1 Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00

Exemple- * 127 128 129 130 131 132 133 134 Ingredients! 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 10 12 10 10 10 10 10 10 Succinic anhydride (Triethoxysilylpropyl) propyl 1.45

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Urethane Polyethylene N-oxide N (triethoxysilylpropyl) 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 3- (trimethoxysilyl) piOpil methacrylate 1.45 1 Hexamethyl disiloxane 1 Hexamethyl disilazan 1 Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00

Exemple- » 135 136 137 138 139 140 141 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 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 Trimethoxy phenyl silane 1 I came trimethoxysilane 1 3- (N, N-dimethylaminopropyl) trimethoxysilane 1 3- (diethylamino) propyl trimethoxysilane 1 T rimethoxy (octadecyl) silane 1 Isobutyl trimethoxysilane 1 Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00

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Exemple- » 142 143 144 145 146 147 Ingredients! ST-025 76 76 76 ^^ 76 76 76 Deionized water 11.1 11.1 11.1 11.1 11.1 11.1 ethylene 10 10 10 10 10 10 Silane, trimethoxy [3 (oxiranyl methoxy) propyl] 1.9 1.9 1.9 1.9 1.9 1.9 Hexiltrimetoxisilan 1 Deciltrimetoxisilan 1 Isooctiltrimetoxisilan 1 Hexadeciltrimetoxisilan 1 propyltrimethoxysilane 1 octyltriethoxysilane 1 Total 100.00 100.00 100.00 100.00 100.00 100.00

Examples 148 149 150 151 152 153 154 ingredients 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 15 14 13 12 10 10 10 Succinic anhydride 3 (triethoxysilylpropyl) propyl 2.9 Urethane Polyethylene N-oxide N (triethoxysilylpropyl) 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

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3- (Trimethoxysilyl) propyl methacrylate 1 Hexamethyl disiloxane 1 Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00

Exemple- » 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 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 disilazan 1 Trimethoxy methyl silane 1 Trimethoxy phenyl silane 1 I came trimethoxysilane 1 3- (N, N-dimethylaminopropyl) trimethoxysilane 1 3- (diethylamino) propyl trimethoxysilane 1 T rimethoxy (octadecyl) silane 1 Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00

Exemple- » 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 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

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Hexiltrimetoxisilan 1 Deciltrimetoxisilan 1 Isooctiltrimetoxisilan 1 Hexadeciltrimetoxisila n 1 propyltrimethoxysilane 1 octyltriethoxysilane 1 Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00

Description Exemple- » ingredients; 169 170 171 172 173 174 175 Colloidal silica 25 gr% silica solids from Nissan Chemical America ST-O-25 52.68 50 51 25 Alkaline colloidal silica from Nissan Chemical Company, Japan ST-32C 59.28 48 45 25 Deionized water 36.05 27.97 40 41.5 38.5 43 35 propylene 8 7.5 8.5 ethylene 8.06 9.85 7.5 10 Silane, trimethoxy [3 (oxiranyl methoxy) own |] 3.21 2.9 2.5 2.5 3 3.5 5 Total (g) 100 100 100 100 100 100 100

Saline-resistant silica soils and hydrocarbon recovery fluids containing surface-functionalized nanoparticles, where the surface-functionalized nanoparticles are saline-resistant silica soils, can be found in U.S. Pat. Nr. 15 / 946,252; filed on April 5, 2018, entitled "Saline-resistant silica soils"; U.S. Patent Application Nr. 15 / 946.338, filed on April 5, 2018, entitled “Micellar solutions of 2020 00155

25/09/2018 for the treatment of hydrocarbons of the formation ”; U.S. Patent Application Nr. 16 / 129,688; filed on: September 12, 2018, entitled “Chemical fluids for the recovery of crude oil”, an application claiming priority over Japanese patent application no. JP 2017-175511; and U.S. Patent Application Nr. 16 / 129,705; filed on: September 12, 2018, entitled “Chemical fluids for the recovery of crude oil”, an application claiming priority over Japanese patent application no. JP 2017-175511; wherein all U.S. patent applications are incorporated herein by reference, in their entirety.

When selecting / using a fluid that will be used in the treatment of an oil and / or gas well, it is important that the fluid has an appropriate combination of additives and components to achieve the required end-use specific application characteristics. A main objective among many aspects of the formation's hydrocarbon treatment is to optimize the recovery of oil and / or gas from the formation. However, in part because fluids used during the operation of an oil and / or gas well are often used to perform a series of tasks simultaneously, achieving the required to optimum characteristics of the hydrocarbon recovery fluid containing nanoparticles functionalized by surface is always difficult.

Additional commercially available compositions suitable for hydrocarbon recovery fluid include the nanoActiv® HRT product line from Nissan Chemical America Corporation, located at 10333 Richmond Avenue, Suite 1100 Houston, TX 77042. These products, including development products that are in During the test, they use nano-sized particles in a colloidal dispersion, which allows the fluid to function causing a diffusion-driven Brownian motion mechanism known as disjunctive pressure to produce long-term efficiency in recovering hydrocarbons in tanks. conventional and unconventional. »>

Commercially available nanoActiv®HRT products include, but are not limited to:

a. HRT BIO / G - an ecological version of 2020 00155

25/09/2018 £

b. OFS CORR PRO - a version containing a sulfur gas treatment system to reduce corrosion of iron pipe due to H2S

c. HRT-78 - a version formulated for high temperatures

d. CPD-60 - a version containing a hydroxysultain surfactant

e. CPD-37 - the original version that was originally sold

f. HRT-53 - economical commercial product, very efficient

g. HRT-53 C - another version of HRT-53C with a more dilute composition

Additional hydrocarbon recovery fluids containing mixtures of functionalized colloidal silica, suitable for this invention, include a chemical solution for the recovery of crude oil which is excellent in terms of resistance to high temperatures and salt, characterized in that it contains a silane compound. , an aqueous silica soil having an average particle size of about 3 nm to about 200 nm.

In a specific situation regarding the hydrocarbon recovery fluid containing surface-functionalized nanoparticles, the aqueous silica soil contains silica particles in which at least part of the silane compound is bound to the surface of at least part of the silica from the soil.

In another embodiment regarding the hydrocarbon recovery fluid containing surface functionalized nanoparticles, the silane compound is at least one compound selected from the group consisting of a silane conjugating agent having at least one organic functional group selected from the group formed from a vinyl group, an ether group, an epoxy group, a news group, a methacryl group, an acrid 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 containing surface-functionalized nanoparticles, the aqueous silica soil is present in an amount of from about 0.1% by mass to about 20% by mass, the total mass of the chemical solution for the recovery of crude oil, in terms of solid silica content.

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25/09/2018 in another concrete situation regarding the hydrocarbon recovery fluid containing surface-functionalized nanoparticles, the silane compound is present in a ratio of 0.1 to 3.0 mass-based silane compound the solid silica content of the aqueous silica soil.

In another embodiment with respect to the hydrocarbon recovery fluid containing surface-functionalized nanoparticles, surfactants are present in an amount of from about 2% by mass to about 50% by mass, based on the total mass of the solution. chemical crude oil recovery.

Additional hydrocarbon recovery fluids containing surface functionalized colloidal silica mixtures suitable for this invention include a micellar dispersion fluid comprising:

(a) a terpene-based oily phase comprising less than about 20,0 gr. % 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-Ce alcohols such as, but not limited to, ethylene glycol and isopropanol;

(d) a cosolvent alcohol, such as, but not limited to, ethyl-hexyl alcohols;

(e) water; and (f) a functionalized aqueous colloidal silica, which shall be a surface-functionalized, saline-resistant colloidal silica.

In another embodiment with respect to the hydrocarbon recovery fluid, which is a micellar dispersion, the hydrocarbon recovery fluid comprises surface-functionalized nanoparticles, the fluid comprises:

(a) an oily fluid other than a terpene, of 2020 00155

25/09/2018 rfy (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 C 1 -C 6 alcohols; such as, but not limited to, ethylene glycol and isopropanol;

(d) a cosolvent alcohol; such as, but not limited to, ethyl-hexyl alcohols;

(e) water; and (f) a functionalized aqueous colloidal silica, which must be a surface-functionalized, saline-resistant colloidal silica.

Examples of potentially suitable hydrocarbon recovery fluids containing saline-resistant silica soils are presented in the following tables.

Sample-► A B C D Supplier Chemistry Ingredients]. NCAC Any of the examples 1175 Surface treated silica soil 79,00 84.50 84,00 84,00 NaOH (1%) 10.00 10.00 9.00 9.50 Akzo Nobel nonionic Ethyl 1206 0.40 0.40 0.40 0.40 Stepan nonionic BioSoftN91- 6 0.50 0.50 1.00 1.00 Stepan Alkyl olefin sulfonate BioTerge AS-40 5.5 Stepan Sultain cocamidopropyl Petrostep SB 4.60 4.60 Stepan Betaine lauramidopropyl Amphosol LB 5.60 Stepan Cocamidopropyl betaine PetroStep YC-50 5.10

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Total

100.00 100.00 100.00 100.00

Exemple- * E F G H Supplier Chemistry Ingredients! NCAC Any of examples 1-175 Silica soil surface treated 84.90 84.60 83.6 83,00 NaOH (1%) 10.00 10.00 10 9.50 Akzo Nobel nonionic Ethyl 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 Stepan Alkyl olefin sulfonate BioTerge AS-40 5 6.00 StepanB borrowed betaine PetroStep MM E50 3.70 Stepan Sulfate thirteen of sodium Cedepal TD 407 4.00 Total 100.00 100.00 100.00 100.00

Exemple- * I J K IT Supplier Chemistry Ingredients! NCAC Any of examples 1-175 Silica soil treated at surface 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

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Stepa η 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 Oil of ethoxylated castor oil Etocas 35 LQ MH 5.00 Total 100.00 100.00 100.00 100.00

Exemple- » M N A Supplier Chemistry ingredients; NCAC Any of the examples 1175 Silica soil treated at surface 84,00 84,00 84,00 NaOH (1%) 10.00 10.00 10.00 Evonik nonionic Surfynol 420 5 Stepan nonionic BioSoftN91- 6 1.00 1.00 1.00 Stepan Alkyl olefin sulfonate BioTerge AS- 40 5.00 Total 100.00 100.00 100.00

Supplier Example— »Ingredient; P 21 Q 20.5 R 16.5 S 14.4 T u V w Silica soil resistant to Silica soil surface treated

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saline solution made of ST-32C, available from Nissan Chemical Corporation Ltd. Silica soil resistant to saline solution made of ST-025, available from Nissan Chemical America Corporation Silica soil surface treated 42 37.4 33.5 29.4 dipentene (oily phase) available from Vertec Biosolvents VertecBio DLR 0.5 1.05 1 1.1 0.5 1.05 1 1.1 Methyl soyate VertecBio Gold 11 11.5 12 12.5 11 11.5 12 12.5

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(oily phase) The water Any source 9 6 7 8 9 8 7 6 isopropanol Any supplier 10 11 12 13 13 12 11 10 Olefin sulfonate Alkyl, 40% active available from Solvay AOS-40 39 40 41 40 15 20 25 30 Nonionic surfactant available from AkzoNobel Ethyl 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, liquefied natural gas, liquefied carbon dioxide and / or mixtures thereof. Gas motility is used to more efficiently distribute nanoparticles and push them deeper into the formation, allowing gas and nanoparticles to maximize their capacity to improve production. Successful treatment improves production for six months or more due 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 wells and oil and gas wells.

The first generation of nanoActiv® HRT nanoparticles is specially designed to be used in combination with carbon dioxide, nitrogen, natural gas, liquefied natural gas, liquefied carbon dioxide and / or mixtures thereof. The first generation of 2020 00155 25/09/2018.

/ nanoparticles nanoActiv® HRT is not designed to function properly with steam. It is not necessary or desirable for the steam to be used in combination with the first generation of patented nanoActiv® HRT technology. Steam remains a potential gas for use in combination with future generations of hydrocarbon recovery fluids comprising surface-functionalized nanoparticle products.

The gas itself offers a number of benefits, for example:

• Stimulation of the pressure well, mobilization of oil or gas in the well;

• removal of debris, particles and other materials (removal of the well membrane);

• Inflation and reduction of oil viscosity, facilitating the mobilization of oil when it is miscible;

• Moving oil or gas in the tank, mobilizing it to the well; si>

• Modification of wettability characteristics, elimination of fluids that cause blockages near the drilling area, changing their wettability to a more neutral wet state.

RECHARGE HNP ™ is the trade name for a prescribed, simple and flexible well remediation treatment consisting of the three Huff n Puff phases: injection, soaking and production. Due to the synergies between nanoActiv® development hydrocarbon recovery fluids containing surface-functionalized nanoparticle products and gas, softening times can be dramatically reduced compared to traditional HNP treatments. Depending on the type of formation, the history of the well and the problems identified, a specific treatment plan is prescribed.

The RECHARGE HNP ™ treatment comprises a three-phase process consisting of:

1) screening of candidate wells,

2) specification and prescription of treatment and

3) implementation of treatment.

a 2020 00155 25/09/2018.

7?

It also includes monitoring post-treatment production for up to 180 days to determine the most appropriate treatment for the next stage. Wells must be screened and analyzed to ensure that the correct treatment is applied. This is vital to ensure that treatment 5 has the desired effect on productivity.

Table a below highlights the current screening criteria:

Production * Good initial production (IP) with gradual decline curve indicating continuous well depletion, moisture problems Current <10-20% of IP and preferably <5-10 ΒΟΡΟ or 20mscfd Field data The performance of the well should be the same as other wells in the field; Extensive sampling areas and fractures must be understood treatments Acid and other chemical treatments have a negative impact on the properties of nanoActiv® Well equipment Be in good mechanical condition. Pumps, linings, gaskets. Ensure the pressure tested or guaranteed pressure treatment levels. The water Excessive salt content (eg, KCI) and TDS may adversely affect nanoActiv® Content of * water in crude oil <80% (N2), <90% (CO2) ideally, may be higher at higher treatment dosages Net productive area <100 ft (30m) vertically to optimize 60-90 days damping. Porosity Porosity /> 8% conventional,> 4% unconventional Oil Crude oil y <30 API, preferred CO2 Avoid precipitation conditions of asphalts

io

Table of Well Screening Criteria for RECHARGE HNP ™ 2020 00155

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EXAMPLE

This example describes the work done in combining nitrogen and a nanoActiv® development product, a hydrocarbon recovery fluid containing saline-resistant silica nanoparticles, sodium hydroxide, an anionic surfactant and a nonionic surfactant in Austin Chalk formations. and Buddha.

This case study focuses on a number of old, depleted wells (some closed) in the Buda and Austin Chalk formations in Central Texas (USA). These wells are horizontal executions with open holes. Prior to this work, the well operator initially injected small amounts of N2 into each well (60 tonnes per well) to try to improve productivity.

A nanoActiv® development product, the hydrocarbon recovery fluid described above, is used in combination with nitrogen as a way to get better and longer lasting results.

The process of treating each well is as follows:

1) A freshwater tablet is inserted into the well formation,

2) The nanoActiv® development product, the hydrocarbon recovery fluid, is introduced into the well formation,

3) then nitrogen is introduced into the well formation,

4) Steps 2) and 3) are repeated in sequence at least four times.

Field treatment program

Five wells are treated with different amounts of nanoActiv® hydrocarbon recovery fluid, which contains surface-functionalized nanoparticles, along with a constant volume of 60 tons of nitrogen per well.

The wells, nitrogen quantities and injection stages are chosen by the operator.

and 2020 00155

The following is a summary of the treatment for each of the identified wells:

• Buda well A - totals: 500 gallon tablet of fresh water, 2500 gallons of nanoActiv® development, 60 tons of nitrogen • Buda well B - totals: 500 gallon tablet of fresh water, 2500 gallons of nanoActiv® development , 60 tons of nitrogen • Buda well C - totals: 500 gallon tablet of fresh water, 3000 gallons of nanoActiv®, 60 tons of nitrogen • Austin Chalk well A - totals: tablet of 500 gallons of fresh water, 7500 gallons of nanoActiv ®, 60 tons of nitrogen • Austin Chalk well B - totals: 500 gallon tablet of fresh water, 7500 gallons of nanoActiv®, 60 tons of nitrogen

After monitoring productivity for 180 days after treatment and detailed analysis of production results, several observations are recorded. All five wells respond to treatment. Analyzing the treatment dose in relation to the treatment area, there is a direct correlation, one by one, between the dose and the response to treatment. Areas that receive higher doses of gas and nanoparticles produce better results.

The responses of four of the five wells, two from Austin Chalk and two from Buda, are shown in Figures 4 and 5. The fifth well receives the lowest treatment dose (45% lower than the highest dose) and initially the only one. observed response to this well is the elimination of excess water. After about 160 days of production and the elimination of excess water, there is a 20% increase in average daily oil production.

In addition to the direct correlation between the dose applied to the wells and their responses (improvement in hydrocarbon production expressed as a percentage), there is also a direct correlation between dose and duration of treatment response. This can be seen in Table β.

High correlation between dose and yield 1>

a 2020 00155 25/09/2018

Production response to treatment (days) Treatment dosage (classification) Well answer (classification) 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 β Correlation between treatment dose nitrogen and nanoActiv® development

Hydrocarbon recovery fluid containing surface functionalized nanoparticles) in the Austin Chalk and Buda wells and the production response of the respective well the duration of the response.

RECHARGE HNP ™ is a patented, multi-spectrum remedial treatment for wells with a number of production problems. The combination of gas and nanoparticle properties creates a unique, synergistic treatment that simultaneously addresses several potential production issues, while being less expensive than alternative solutions. The extended range is extremely useful, as wells often face a combination of problems that lead to a decrease in productivity or, in many cases, operators are not fully aware of the problems with the bottom of the well.

Successful treatments increase production by six months or more, thus reducing the frequency of repeated treatments. RECHARGE HNP ™ is extremely flexible and easy to implement: it can be used with all types of wells, including conventional, unconventional wells and oil and gas wells.

While the foregoing disclosure deals with illustrative matters and / or concrete situations, it should be noted that various changes and modifications may be made here without departing from the scope of the aspects described and / or the concrete situations defined by the appended claims. Moreover, although the elements of the aspects of 2020 00155

25/09/2018 described and / or concrete situations can be described or claimed in the singular, the plural is taken into account if the limitation to the singular is not explicitly specified. in addition, all or part of any concrete aspect and / or situation may be used with all or part of any other concrete aspect and / or situation, unless otherwise provided. All patents, patent applications and references cited anywhere in this disclosure are incorporated for reference in their entirety.

Claims (14)

1. A process for stimulating the recovery of hydrocarbons, comprising (a) the introduction of a gas, liquefied gas or vaporized liquefied gas into an underground formation containing hydrocarbons; (b) allowing the absorption of that gas by those hydrocarbons; (c) withdrawal of said hydrocarbons containing that gas, liquefied gas or vaporized liquefied gas absorbed therein; and wherein a hydrocarbon recovery fluid tablet comprising surface functionalized nanoparticles is introduced into the hydrocarbon-containing underground formation before, during or after the introduction of the gas, liquefied gas or vaporized liquefied gas. The process of Claim 1, wherein the injected gas, the liquefied gas or the liquefied gas vaporized and the hydrocarbon recovery fluid comprising surface-functionalized nanoparticles may also include one or more injected substances, selected from the group consisting of fresh water, water KCI, derivatives and any other injectable substance currently used in oil field remediation as part of treatment. The process of claim 1 wherein the hydrocarbon recovery fluid tablet comprising surface functionalized nanoparticles is introduced into the underground formation containing hydrocarbons prior to the introduction of the gas, liquefied gas or vaporized liquefied gas. The process of claim 1 wherein the hydrocarbon recovery fluid tablet comprising surface functionalized nanoparticles is introduced into the underground formation containing hydrocarbons during the introduction of the gas, liquefied gas or vaporized liquefied gas. The process of Claim 1 wherein the hydrocarbon recovery fluid tablet comprising surface functionalized nanoparticles is introduced in 2020 00155 25/09/2018 49 underground formation containing hydrocarbons after the introduction of gas, liquefied gas or a vaporized liquefied gas. The process of Claim 1 wherein the gas is selected from the group consisting of carbon dioxide, nitrogen, natural gas, liquefied natural gas, liquefied carbon dioxide and / or mixtures thereof. The process of Claim 1 wherein said gas is carbon dioxide. The process of Claim 1 wherein said gas is nitrogen. The process of Claim 1 wherein said gas is natural gas. The process of Claim 1 wherein said gas is liquefied natural gas or liquefied carbon dioxide. The process of claim 6 wherein said gas is a mixture of two or more gases selected from the group consisting of carbon dioxide, nitrogen, natural gas, liquefied natural gas, liquefied carbon dioxide and / or mixtures thereof. The process of Claim 6, wherein said process is part of a huff and puff treatment process. The process of Claim 12 wherein said process is a waterless fracturing process. The process of Claim 13 wherein said process is a waterless fracturing process.