WO2019067478A1 - Using gases and hydrocarbon recovery fluids containing nanoparticles to enhance hydrocarbon recovery - Google Patents
Using gases and hydrocarbon recovery fluids containing nanoparticles to enhance hydrocarbon recovery Download PDFInfo
- Publication number
- WO2019067478A1 WO2019067478A1 PCT/US2018/052736 US2018052736W WO2019067478A1 WO 2019067478 A1 WO2019067478 A1 WO 2019067478A1 US 2018052736 W US2018052736 W US 2018052736W WO 2019067478 A1 WO2019067478 A1 WO 2019067478A1
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- WO
- WIPO (PCT)
- Prior art keywords
- gas
- liquified
- hydrocarbon recovery
- carbon dioxide
- surface functionalized
- Prior art date
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Classifications
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
- E21B43/168—Injecting a gaseous medium
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/62—Compositions for forming crevices or fractures
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/62—Compositions for forming crevices or fractures
- C09K8/66—Compositions based on water or polar solvents
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/164—Injecting CO2 or carbonated water
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
- E21B43/2605—Methods for stimulating production by forming crevices or fractures using gas or liquefied gas
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
- C09K2208/10—Nanoparticle-containing well treatment fluids
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
- C09K8/594—Compositions used in combination with injected gas, e.g. CO2 orcarbonated gas
Definitions
- 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.
- 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.
- 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
- 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.
- HNP Huff n Puff
- 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.
- 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 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 (IOR) and enhanced oil recovery (EOR). 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.
- IOR oil recovery
- EOR enhanced oil recovery
- 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.
- 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.
- Nitrogen, Natural Gas and/or Natural Gas Liquifieds can also be used in waterless fracturing of a suitable hydrocarbon-bearing formation.
- 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 Kleinhofstrasse 1, 80 331 Kunststoff, 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 of hydrocarbons and reducing the water cut from an unde erforming well, preferably using nonaqueous materials.
- the first aspect of the instant claimed invention is a process of stimulating hydrocarbon recovery comprising
- 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, KC1 water, diverters and any other injectant currently used in oil field remediation as part of the treatment.
- injectants selected from the group consisting of fresh water, KC1 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 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.
- 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.
- 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.
- 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.
- 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 (C02 Huff-Puff) in South Louisiana", Conference: SPE Annual Technical Meeting and Exhibition, October 1986. 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.
- FIG. 1 Cumulative oil production for the Austin Chalk wells before and after treatment with N 2 and developmental nanoActiv® HRT Hydrocarbon Recovery Fluid comprising surface functionalized nanoparticles.
- FIG. 1 The three phases of an HNPTM treatment.
- the first aspect of the instant claimed invention is a process of stimulating hydrocarbon recovery comprising
- 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.
- 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).
- the surface functionalized nanoparticles comprise a plurality of hydrophobized nanoparticles.
- the surface functionalized nanoparticles are surface functionalized colloidal silica nanoparticles.
- Brine aqueous salt mixture
- aqueous salt mixture is typically referred to as Brine.
- Brine conditions for different regions and wells vary widely with different downhole conditions and lithologies.
- fluids used downhole must either tolerate briny conditions or have brine-resistant properties.
- 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.
- 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.
- the nanoparticles 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.
- a 10wt% API Brine solution is prepared by dissolving 8wt% NaCl (SigmaAldrich) and 2wt% CaCb (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.
- 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
- Test solutions/surface treated silicasols are tested for Brine resistance by Turbidimetry.
- a calibrated Hach 2100 AN 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
- API brine 8wt% NaCl, 2wt% CaCb
- Test solution concentrations are therefore 10wt% 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.
- 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.
- 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.
- DLS average particle diameter dynamic light scattering
- 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.
- 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.
- 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 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.
- brine resistance of aqueous colloidal silica can be improved over untreated colloidal silica by addition of certain types of organic surface treatment.
- organic surface treatments 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.
- 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.
- 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; wherein all US Patent Applications are herein incorporated by reference, in their entirety.
- 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.
- NanoActiv®HRT products include, but are not limited to:
- OFS CORR PRO - a version containing a sour gas scavenger for reducing
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- micellar dispersion fluid comprising: (a) a terpene-based oil phase that includes less than about 20.0 wt. % d-limonene,
- surfactants selected from the group consisting of anionic surfactants, cationic surfactants, nonionic surfactants and amphoteric surfactants;
- an alcohol selected from the group consisting of Ci-C 8 alcohols, such as, but not limited to ethylene glycol and isopropanol;
- an alcohol cosolvent such as, but not limited to, ethyl-hexyl alcohols
- a functionalized aqueous colloidal silica which must be a brine resistant surface functionalized colloidal silica.
- the Hydrocarbon Recovery Fluid comprises surface functionalized nanoparticles, the fluid comprises:
- surfactants selected from the group consisting of anionic surfactants, cationic surfactants, nonionic surfactants and amphoteric surfactants;
- an alcohol selected from the group consisting of Ci-C 8 alcohols; such as, but not limited to ethylene glycol and isopropanol;
- an alcohol cosolvent such as, but not limited to, ethyl-hexyl alcohols
- a functionalized aqueous colloidal silica which must be a brine resistant surface functionalized colloidal silica.
- Hydrocarbon Recovery Fluids comprising brine resistant silica sols are in the following tables.
- 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.
- 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 functionalized nanoparticle products.
- the gas itself delivers a range of benefits, for example:
- 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
- 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.
- 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 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.
- Table ⁇ 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 ⁇ .
- Hydrocarbon Recovery Fluid comprising surface functionalized nanoparticles
- 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.
- RECHARGE HNPTM is highly flexible and easy to implement: it can be used with all types of wells, including conventional, unconventional and oil and gas wells.
Abstract
A process of stimulating hydrocarbon recovery is described and claimed. This process includes introducing a gas, a liquified gas or a vaporized liquified gas, into an underground formation containing hydrocarbons such as crude oil and gas, permitting said gas to be absorbed by said hydrocarbons, and withdrawing said hydrocarbons containing the gas therein, 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 a vaporized liquified gas.
Description
USING GASES AND HYDROCARBON RECOVERY FLUIDS CONTAINING NANOPARTICLES TO
ENHANCE HYDROCARBON RECOVERY
Cross Reference to Related Patent Applications
This patent application claims priority to US Provisional Patent Application No.
62/563,415, filed on September 26, 2017 and claims priority to U.S. Provisional Patent
Application. No. 62/697,321; filed: July 12, 2018. These Applications are incorporated herein in their entirety.
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 velocity1
- 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
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
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 (IOR) and enhanced oil recovery (EOR). 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
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/pdf/usshaleplays.pdf;
Wei, B., Pu, W., Pang, S., Kong, L., Mechanisms of N2 and C02 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;
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
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
of hydrocarbons and reducing the water cut from an unde erforming well, preferably using nonaqueous 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, KC1 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
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.
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 (C02 Huff-Puff) in South Louisiana", Conference: SPE Annual Technical Meeting and Exhibition, October 1986. Not an example of the instant claimed invention.
Figure 2. Comparisons of oil recovery using C02, N2, and steam FINP 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 N2 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 HNP™ treatment.
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 NaCl, CaCb, KC1, MgCb 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.
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 10wt% API Brine solution is prepared by dissolving 8wt% NaCl (SigmaAldrich) and 2wt% CaCb (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
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 2100 AN 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 30ml.
Twenty-seven grams (27g) of 10% API brine (8wt% NaCl, 2wt% CaCb) are added to the test tube and the mixture inverted three times to mix test solution and brine. Test solution concentrations are therefore 10wt% 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 100NTU 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.
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
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.
Examples— > 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 Glycol 10 10 10 10 10 10
3-(Triethoxysilyl)propyl
Succinic Anhydride 2.9 1.9 1.9
N-(Triethoxysilylpropyl)-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 100.00 100.00 100.00 100.00 100.00 100.00
Examples— > 7 8 9 10 11 12 13
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 Glycol 10 10 10 10 10 10 10-(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-Dimethylaminopropyl)-
Trimethoxysilane 1
3-(Diethylamino)propyl
trimethoxysilane 1
Total 100 100 100 100 100 100 100
Examples— > 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 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
Isobutyl Trimethoxysilane 1
Hexyltrimethoxysilane 1
Decyltrimethoxysilane 1
Isooctyltrimethoxysilane 1
Hexadecyltrimethoxysilane 1
Propyltrimethoxysilane 1
Octyltriethoxysilane 1
Total 100 100 100 100 100 100 100 100
Examples—► 22 23 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
Propylene Glycol 13 8 10 12 10 10 10 10 10
3-(Triethoxysilyl)propyl
Succinic Anhydride 2.9
N-(Triethoxysilylpropyl)- 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
-(Trimethoxysilyl)propyl
Methacrylate 1
Hexamethyl Disiloxane 1
Hexamethyl Disilazane 1
Trimethoxy Methyl
Silane 1
Total 100 100 100 100 100 100 100 100 100
Examples—► 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 Glycol 10 10 10 10 10 10 10
N-(Triethoxysilylpropyl)- 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-
Dimethylaminopropyl)- 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
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 Glycol 10 10 10 10 10
N-
(Triethoxysilylpropyl)- O-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
Examples—► 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
Propylene Glycol 11.1 12.1 11 6 10 10 10 10 10
3-(Triethoxysilyl)propyl
Succinic Anhydride 2.9
N-(Triethoxysilylpropyl)- O-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
-(Trimethoxysilyl)propyl
Methacrylate 1
Hexamethyl Disiloxane 1
Hexamethyl Disilazane 1
Trimethoxy Methyl
Silane 1
Total 100 100 100 100 100 100 100 100 100
Examples—► 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 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 Phenyl Silane 1
Vinyl Trimethoxysilane 1
3-(N,N-
Dimethylaminopropyl)- 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
Examples— > 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 Glycol 10 10 10 10 10
Silane, trimethoxy[3- (oxiranyl methoxy)propyl] 1.9 1.9 1.9 1.9 1.9
Decyltrimethoxysilane 1
Isooctyltrimethoxysilane 1
Hexadecyltrimethoxysilane 1
Propyltrimethoxysilane 1
Octyltriethoxysilane 1
Total 100.00 100.00 100.00 100.00 100.00
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-
(Triethoxysilylpropyl)- O-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
Examples—► 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 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-
Dimethylaminopropyl)- Trimethoxysilane 1
3-(Diethylamino)propyl
trimethoxysilane 1
Trimethoxy(octadecyl)silan
e 1
Isobutyl 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
Examples— > 82 83 84
Ingredients^
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
Examples— > 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 Glycol 10 10 10 10 10
3-
(Triethoxysilyl)propyl
Succinic Anhydride 2.9 1.9
N-
(Triethoxysilylpropyl)- O-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
1 Methacrylate
Hexamethyl Disiloxane
Hexamethyl Disilazane
100.0
Total 100.00 100.00 100.00 100.00 0
Examples— > 90 91 92
Ingredients^
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-
(Trimethoxysilyl)propy
1 Methacrylate 1
Hexamethyl Disiloxane 1
Hexamethyl Disilazane 1
Total 100.00 100.00 100.00
Examples—► 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 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
Examples— > 100 101 102 103 104 105
Ingredients^
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
Isooctyltrimethoxysilane 1
Hexadecyltrimethoxysilane 1
Propyltrimethoxysilane 1
Octyltriethoxysilane 1
Total 100.00 100.00 100.00 100.00 100.00 100.00
Examples—► 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
Ethylene Glycol 8 12 10 10 10 10 10
3-(Triethoxysilyl)propyl
Succinic Anhydride 1.45
N-(Triethoxysilylpropyl)- O-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
-(Trimethoxysilyl)propyl
Methacrylate 1
Hexamethyl Disiloxane 1
Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00
Examples— > 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 Glycol 10 10 10 10 10 10
N-
(Triethoxysilylpropyl)- 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-
Dimethylaminopropyl)- Trimethoxysilane 1
3-
(Diethylamino)propyl
trimethoxysilane 1
Total 100.00 100.00 100.00 100.00 100.00 100.00
Examples—► 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 Glycol 10 10 10 10 10 10 10 10
N-
(Triethoxysilylpropyl)- 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
e 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
Examples-» | 127 | 128 | 129 | 130 | 131 | 132 | 133
Ingredients^
ST-025 76 76 78 74 76 76 76
Deionized water 11.1 9.1 9.1 12.1 11.1 11.1 11.1
Ethylene Glycol 10 12 10 10 10 10 10
(Triethoxysilyl)propyl
Succinic Anhydride 1.45
N-
(Triethoxysilylpropyl)- O-Polyethyleneoxide
Urethane 1.45
Silane, trimethoxy[3- (oxiranyl
methoxy)propyl] 1.45 1.45 1.9 1.9 1.9
3-Ureidopropyl
Triethoxysilane 1.45 1.45
2-(3,4
Epoxycyclohexyl)- ethyltrimethoxysilane 1.45
(Trimethoxysilyl)propyl 1.45
Methacrylate
Hexamethyl Disiloxane
Hexamethyl Disilazane
Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00
Examples—► 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 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
Trimethoxy Phenyl Silane 1
Vinyl Trimethoxysilane 1
3-(N,N-
Dimethylaminopropyl)- Trimethoxysilane 1
3-(Diethylamino)propyl
trimethoxysilane 1
Trimethoxy(octadecyl)silane 1
Isobutyl Trimethoxysilane 1
Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00
Examples— > 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 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
Isooctyltrimethoxysilane 1
Hexadecyltrimethoxysilane 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 Glycol 15 14 13 12 10 10 10
3-
(Triethoxysilyl)propyl
Succinic Anhydride 2.9
N-
(Triethoxysilylpropyl)- O-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
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
Trimethoxy Phenyl Silane 1
Vinyl Trimethoxysilane 1
3-(N,N-
Dimethylaminopropyl)- 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
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
Total (g) 100 100 100 100 100
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; wherein all US Patent Applications are herein incorporated by reference, in their entirety.
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 nanoActiv®HRT 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 H2S
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:
(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
(f) 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
(f) 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.
Examples-* A B C D
Supplier Chemistry Ingredients-!'
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 AlkyI 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
Examples— > E F G H
Supplier Chemistry Ingredients-!'
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 MM E 50 3.70
Sodium Trideceth
Stepan Sulfate Cedepal TD 407 4.00
Total 100.00 100.00 100.00 100.00
Examples— > 1 J K L
Supplier Chemistry Ingredients^
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 B 5.00
Croda Ethoxylated Castor Oil Etocas 35 LQ MH 5.00
Total 100.00 100.00 100.00 100.00
Examples— > M N 0
Supplier Chemistry Ingredients^
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 AlkyI Olefin Sulfonate BioTerge AS-40 5.00
Total 100.00 100.00 100.00
Examples— > p | Q | R | S | T | U | V | W
Supplier Ingredients^
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.
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 functionalized 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 HNP™ 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 HNP™ 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 (X following highlights the current screening criteria:
Table a Well screening criteria for RECHARGE HNPT M
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,
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.
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 β.
High Correlation Between Dosage and Yield
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 HNP™ 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 HNP™ 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
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. All patents, patent applications, and references cited anywhere in this disclosure are incorporated by reference in their entirety.
Claims
1. A process of stimulating hydrocarbon recovery comprising
(a) introducing a gas, a liquefied gas or vaporized liquified gas, into an underground formation containing hydrocarbons;
(b) permitting said gas to be absorbed by said hydrocarbons,
(c) withdrawing said hydrocarbons containing said gas, liquefied 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, liquefied gas or a vaporized liquified gas.
2. The process of Claim 1 wherein the injected gas, liquified gas or 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.
3. The process of Claim 1 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.
4. The process of Claim 1 wherein said pill of Hydrocarbon Recovery Fluid comprising surface functionalized nanoparticles is inserted into the underground formation containing hydrocarbons during the introduction of the gas, liquified gas or a vaporized liquified gas.
5. The process of Claim 1 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 process of Claim 1 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 process of Claim 1 wherein said gas is carbon dioxide.
The process of Claim 1 wherein said gas is nitrog
The process of Claim 1 wherein said gas is natural
The process of Claim 1 wherein said gas is liquified natural gas or liquified carbon dioxide.
11. 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, liquified natural gas, liquified 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 less water fracturing process.
Priority Applications (6)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| UAA202002157A UA125829C2 (en) | 2017-09-26 | 2018-09-25 | Using gases and hydrocarbon recovery fluids containing nanoparticles to enhance hydrocarbon recovery |
| MX2020002954A MX2020002954A (en) | 2017-09-26 | 2018-09-25 | Using gases and hydrocarbon recovery fluids containing nanoparticles to enhance hydrocarbon recovery. |
| RU2020112767A RU2759431C1 (en) | 2017-09-26 | 2018-09-25 | Use of gases and liquids for extracting hydrocarbons containing nanoparticles for increasing hydrocarbon extraction |
| ROA202000155A RO134503A2 (en) | 2017-09-26 | 2018-09-25 | Use of gas and hydrocarbon recovery fluids with nanoparticle content for improving hydrocarbon recovery |
| PL433562A PL433562A1 (en) | 2017-09-26 | 2018-09-25 | Using gases and hydrocarbon recovery fluids containing nanoparticles to enhance hydrocarbon recovery |
| CA3076007A CA3076007C (en) | 2017-09-26 | 2018-09-25 | Using gases and hydrocarbon recovery fluids containing nanoparticles to enhance hydrocarbon recovery |
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Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| WO2021136954A1 (en) | 2019-12-31 | 2021-07-08 | Total Se | Nanofluid for fines migration reduction and enhanced oil recovery, method of preparation and uses |
| CN113604208A (en) * | 2021-08-04 | 2021-11-05 | 宁波锋成先进能源材料研究院有限公司 | Nano fluid system and preparation method and application thereof |
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Cited By (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| WO2021136954A1 (en) | 2019-12-31 | 2021-07-08 | Total Se | Nanofluid for fines migration reduction and enhanced oil recovery, method of preparation and uses |
| US11753579B2 (en) | 2019-12-31 | 2023-09-12 | Totalenergies Onetech | Nanofluid for fines migration reduction and enhanced oil recovery, method of preparation and uses |
| CN113604208A (en) * | 2021-08-04 | 2021-11-05 | 宁波锋成先进能源材料研究院有限公司 | Nano fluid system and preparation method and application thereof |
Also Published As
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| RU2759431C1 (en) | 2021-11-12 |
| PL433562A1 (en) | 2021-08-02 |
| MX2020002954A (en) | 2020-08-17 |
| CA3076007C (en) | 2022-09-06 |
| UA125829C2 (en) | 2022-06-15 |
| CA3076007A1 (en) | 2019-04-04 |
| RO134503A2 (en) | 2020-10-30 |
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