CN115232249A - Preparation method of in-situ phase-change gel profile control oil displacement agent - Google Patents
Preparation method of in-situ phase-change gel profile control oil displacement agent Download PDFInfo
- Publication number
- CN115232249A CN115232249A CN202210678224.2A CN202210678224A CN115232249A CN 115232249 A CN115232249 A CN 115232249A CN 202210678224 A CN202210678224 A CN 202210678224A CN 115232249 A CN115232249 A CN 115232249A
- Authority
- CN
- China
- Prior art keywords
- acrylamide
- oil displacement
- control oil
- profile control
- displacement agent
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Pending
Links
- 238000006073 displacement reaction Methods 0.000 title claims abstract description 23
- 238000011065 in-situ storage Methods 0.000 title claims abstract description 10
- 238000002360 preparation method Methods 0.000 title claims abstract description 7
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 19
- 239000003795 chemical substances by application Substances 0.000 claims abstract description 14
- HRPVXLWXLXDGHG-UHFFFAOYSA-N Acrylamide Chemical compound NC(=O)C=C HRPVXLWXLXDGHG-UHFFFAOYSA-N 0.000 claims abstract description 13
- FZGFBJMPSHGTRQ-UHFFFAOYSA-M trimethyl(2-prop-2-enoyloxyethyl)azanium;chloride Chemical compound [Cl-].C[N+](C)(C)CCOC(=O)C=C FZGFBJMPSHGTRQ-UHFFFAOYSA-M 0.000 claims abstract description 9
- ZJCOXZXHUMVTTE-UHFFFAOYSA-N 2-(prop-2-enoylamino)tetradecane-1-sulfonic acid Chemical compound CCCCCCCCCCCCC(CS(O)(=O)=O)NC(=O)C=C ZJCOXZXHUMVTTE-UHFFFAOYSA-N 0.000 claims abstract description 8
- VPJDULFXCAQHRC-UHFFFAOYSA-N prop-2-enylurea Chemical compound NC(=O)NCC=C VPJDULFXCAQHRC-UHFFFAOYSA-N 0.000 claims abstract description 8
- 239000007787 solid Substances 0.000 claims abstract description 8
- KFDVPJUYSDEJTH-UHFFFAOYSA-N 4-ethenylpyridine Chemical compound C=CC1=CC=NC=C1 KFDVPJUYSDEJTH-UHFFFAOYSA-N 0.000 claims abstract description 7
- 239000000843 powder Substances 0.000 claims abstract description 7
- 230000008859 change Effects 0.000 claims abstract description 6
- 238000002156 mixing Methods 0.000 claims abstract description 4
- 238000006243 chemical reaction Methods 0.000 claims description 12
- 238000001035 drying Methods 0.000 claims description 11
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 claims description 8
- 238000001816 cooling Methods 0.000 claims description 8
- 239000003292 glue Substances 0.000 claims description 7
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 claims description 6
- 238000007789 sealing Methods 0.000 claims description 6
- 238000003756 stirring Methods 0.000 claims description 6
- 238000005303 weighing Methods 0.000 claims description 6
- 238000005520 cutting process Methods 0.000 claims description 5
- DWAQJAXMDSEUJJ-UHFFFAOYSA-M Sodium bisulfite Chemical compound [Na+].OS([O-])=O DWAQJAXMDSEUJJ-UHFFFAOYSA-M 0.000 claims description 4
- 239000012153 distilled water Substances 0.000 claims description 4
- 238000010438 heat treatment Methods 0.000 claims description 4
- 229910052757 nitrogen Inorganic materials 0.000 claims description 4
- USHAGKDGDHPEEY-UHFFFAOYSA-L potassium persulfate Chemical compound [K+].[K+].[O-]S(=O)(=O)OOS([O-])(=O)=O USHAGKDGDHPEEY-UHFFFAOYSA-L 0.000 claims description 4
- 235000010267 sodium hydrogen sulphite Nutrition 0.000 claims description 4
- 239000000463 material Substances 0.000 claims description 2
- 238000004321 preservation Methods 0.000 claims description 2
- 229920000536 2-Acrylamido-2-methylpropane sulfonic acid Polymers 0.000 claims 1
- XHZPRMZZQOIPDS-UHFFFAOYSA-N 2-Methyl-2-[(1-oxo-2-propenyl)amino]-1-propanesulfonic acid Chemical compound OS(=O)(=O)CC(C)(C)NC(=O)C=C XHZPRMZZQOIPDS-UHFFFAOYSA-N 0.000 claims 1
- 229920000642 polymer Polymers 0.000 abstract description 8
- DZSVIVLGBJKQAP-UHFFFAOYSA-N 1-(2-methyl-5-propan-2-ylcyclohex-2-en-1-yl)propan-1-one Chemical compound CCC(=O)C1CC(C(C)C)CC=C1C DZSVIVLGBJKQAP-UHFFFAOYSA-N 0.000 abstract description 7
- 239000002994 raw material Substances 0.000 abstract description 7
- 239000007864 aqueous solution Substances 0.000 abstract description 4
- 238000000034 method Methods 0.000 abstract description 4
- 150000003254 radicals Chemical class 0.000 abstract description 4
- 238000010528 free radical solution polymerization reaction Methods 0.000 abstract description 3
- KGIGUEBEKRSTEW-UHFFFAOYSA-N 2-vinylpyridine Chemical compound C=CC1=CC=CC=N1 KGIGUEBEKRSTEW-UHFFFAOYSA-N 0.000 abstract description 2
- 239000000654 additive Substances 0.000 abstract description 2
- 238000000605 extraction Methods 0.000 abstract description 2
- 229920001897 terpolymer Polymers 0.000 abstract description 2
- 238000006116 polymerization reaction Methods 0.000 abstract 1
- 239000008399 tap water Substances 0.000 description 24
- 235000020679 tap water Nutrition 0.000 description 24
- 239000000499 gel Substances 0.000 description 21
- 239000003921 oil Substances 0.000 description 21
- 239000013535 sea water Substances 0.000 description 21
- 239000011435 rock Substances 0.000 description 14
- 239000000243 solution Substances 0.000 description 12
- 239000000523 sample Substances 0.000 description 11
- 239000010779 crude oil Substances 0.000 description 9
- 230000035699 permeability Effects 0.000 description 9
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 7
- 238000011084 recovery Methods 0.000 description 7
- 238000004519 manufacturing process Methods 0.000 description 5
- 239000012488 sample solution Substances 0.000 description 5
- 239000006004 Quartz sand Substances 0.000 description 4
- 238000002347 injection Methods 0.000 description 4
- 239000007924 injection Substances 0.000 description 4
- 230000018044 dehydration Effects 0.000 description 3
- 238000006297 dehydration reaction Methods 0.000 description 3
- 238000004090 dissolution Methods 0.000 description 3
- 238000000518 rheometry Methods 0.000 description 3
- 239000004576 sand Substances 0.000 description 3
- 230000009471 action Effects 0.000 description 2
- 230000000903 blocking effect Effects 0.000 description 2
- 239000011575 calcium Substances 0.000 description 2
- 230000007613 environmental effect Effects 0.000 description 2
- 238000011049 filling Methods 0.000 description 2
- 239000007788 liquid Substances 0.000 description 2
- 239000000203 mixture Substances 0.000 description 2
- 239000002245 particle Substances 0.000 description 2
- OYPRJOBELJOOCE-UHFFFAOYSA-N Calcium Chemical compound [Ca] OYPRJOBELJOOCE-UHFFFAOYSA-N 0.000 description 1
- JLVVSXFLKOJNIY-UHFFFAOYSA-N Magnesium ion Chemical compound [Mg+2] JLVVSXFLKOJNIY-UHFFFAOYSA-N 0.000 description 1
- 239000002390 adhesive tape Substances 0.000 description 1
- 150000001450 anions Chemical class 0.000 description 1
- 230000033558 biomineral tissue development Effects 0.000 description 1
- 229910001424 calcium ion Inorganic materials 0.000 description 1
- 238000004364 calculation method Methods 0.000 description 1
- 125000002915 carbonyl group Chemical group [*:2]C([*:1])=O 0.000 description 1
- 150000001768 cations Chemical class 0.000 description 1
- 239000004568 cement Substances 0.000 description 1
- 239000000084 colloidal system Substances 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 230000009881 electrostatic interaction Effects 0.000 description 1
- 238000005516 engineering process Methods 0.000 description 1
- 239000003822 epoxy resin Substances 0.000 description 1
- 239000012530 fluid Substances 0.000 description 1
- 239000008398 formation water Substances 0.000 description 1
- 238000009472 formulation Methods 0.000 description 1
- 239000011521 glass Substances 0.000 description 1
- 239000000017 hydrogel Substances 0.000 description 1
- 239000001257 hydrogen Substances 0.000 description 1
- 229910052739 hydrogen Inorganic materials 0.000 description 1
- 230000005660 hydrophilic surface Effects 0.000 description 1
- 239000011777 magnesium Substances 0.000 description 1
- 229910001425 magnesium ion Inorganic materials 0.000 description 1
- 239000000178 monomer Substances 0.000 description 1
- 230000003472 neutralizing effect Effects 0.000 description 1
- 239000003027 oil sand Substances 0.000 description 1
- 229920002401 polyacrylamide Polymers 0.000 description 1
- 229920000647 polyepoxide Polymers 0.000 description 1
- 239000011148 porous material Substances 0.000 description 1
- 125000002924 primary amino group Chemical group [H]N([H])* 0.000 description 1
- 230000008569 process Effects 0.000 description 1
- 230000002035 prolonged effect Effects 0.000 description 1
- 239000010865 sewage Substances 0.000 description 1
Classifications
-
- C—CHEMISTRY; METALLURGY
- C08—ORGANIC MACROMOLECULAR COMPOUNDS; THEIR PREPARATION OR CHEMICAL WORKING-UP; COMPOSITIONS BASED THEREON
- C08F—MACROMOLECULAR COMPOUNDS OBTAINED BY REACTIONS ONLY INVOLVING CARBON-TO-CARBON UNSATURATED BONDS
- C08F220/00—Copolymers of compounds having one or more unsaturated aliphatic radicals, each having only one carbon-to-carbon double bond, and only one being terminated by only one carboxyl radical or a salt, anhydride ester, amide, imide or nitrile thereof
- C08F220/02—Monocarboxylic acids having less than ten carbon atoms; Derivatives thereof
- C08F220/52—Amides or imides
- C08F220/54—Amides, e.g. N,N-dimethylacrylamide or N-isopropylacrylamide
- C08F220/56—Acrylamide; Methacrylamide
-
- 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
- C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
- C09K8/426—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells for plugging
-
- 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
- C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
- C09K8/44—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing organic binders only
-
- 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
- C09K8/588—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids characterised by the use of specific polymers
Landscapes
- Chemical & Material Sciences (AREA)
- Life Sciences & Earth Sciences (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Organic Chemistry (AREA)
- Engineering & Computer Science (AREA)
- Materials Engineering (AREA)
- Health & Medical Sciences (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Medicinal Chemistry (AREA)
- Polymers & Plastics (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Colloid Chemistry (AREA)
Abstract
The invention belongs to the field of oil field oil extraction additives, and relates to a preparation method of an in-situ phase change gel profile control oil displacement agent. The invention particularly relates to a method for preparing an in-situ phase-change gel profile-control oil displacement agent by taking allyl urea, vinyl pyridine, acryloyloxyethyl trimethyl ammonium chloride, 2-acrylamide-2-methylpropanesulfonic acid, 2-acrylamidotetradecanesulfonic acid and acrylamide as raw materials. The invention takes allylurea, 2-acrylamido tetradecyl sulfonic acid, 2-acrylamide-2-methylpropanesulfonic acid and acrylamide as raw materials, and the mol ratio is 1: 5: 25, and the quadripolymer is prepared by the polymerization of free radical initiated aqueous solution; 4-vinylpyridine, acryloyloxyethyl trimethyl ammonium chloride and acrylamide are used as raw materials, and a terpolymer is prepared by aqueous solution polymerization initiated by free radicals according to the proportion of 1: 5: 25; then mixing the two prepared polymer solid powders according to the proportion of 1: 1 to prepare the variable-phase gel profile-control oil-displacing agent. The profile control oil displacement agent has strong profile control water plugging and oil displacement capabilities and a reliable preparation process.
Description
Technical Field
The invention belongs to the field of oil field oil extraction additives, and particularly relates to a method for preparing an in-situ phase change gel profile control oil displacement agent by using allyl urea, vinyl pyridine, acryloyloxyethyl trimethyl ammonium chloride, 2-acrylamide-2-methylpropanesulfonic acid, 2-acrylamidotetradecyl sulfonic acid and acrylamide as raw materials.
Background
At present, polymer flooding has become one of important technical means for stable production in middle and later periods of oil fields in east China, and the polymer flooding technology makes great contribution to oil field production increase for years, but a plurality of problems gradually appear, wherein one of the most serious problems is that a large amount of undegraded polyacrylamide appears in produced liquid along with the connection of a production well and a polymer injection well, polymer molecules seriously interfere with crude oil dehydration, great difficulty is brought to sewage treatment, environmental protection cost is increased, and crude oil production is restricted. Therefore, the active polymer gel profile control oil displacement agent capable of self-assembling in situ in an oil layer and phase-change dehydration is developed, and the practical production problem of the oil field can be solved.
The in-situ phase change active gel prepared by taking allyl urea, 4-vinylpyridine, acryloyloxyethyl trimethyl ammonium chloride, 2-acrylamide-2-methylpropanesulfonic acid, 2-acrylamidotetradecylsulfonic acid and acrylamide as raw materials can automatically dehydrate, aggregate and change phase in an oil displacement process in an oil layer, so that no polymer molecule exists in produced liquid, crude oil is easy to dehydrate, and the environmental protection cost is reduced. Wherein 2-acrylamido tetradecyl sulfonic acid is used as an active functional monomer to enable a gel system to have better oil displacement capability; the allyl urea, the 4-vinylpyridine and the acrylamide monomer can enable a gel system to generate intermolecular clustering and assembly through the multiple hydrogen bond action of carbonyl and amino, and the 2-acrylamide-2-methylpropanesulfonic acid and the acryloyloxyethyl trimethyl ammonium chloride generate intermolecular clustering and assembly through the electrostatic interaction of anions and cations, so that a gel phase is converted into a solid gel block in situ in an oil layer after completing an oil displacement task, a profile control and water shutoff action is generated, and the gel system has better profile control, water shutoff and oil displacement capabilities overall.
Disclosure of Invention
Firstly, allyl urea, 2-acrylamido tetradecyl sulfonic acid, 2-acrylamide-2-methylpropanesulfonic acid and acrylamide are taken as raw materials, and a quadripolymer of the four is prepared by free radical initiated aqueous solution polymerization according to the molar ratio of 1: 5: 25; then 4-vinylpyridine, acryloyloxyethyl trimethyl ammonium chloride and acrylamide are taken as raw materials, and a terpolymer of the 4-vinylpyridine, the acryloyloxyethyl trimethyl ammonium chloride and the acrylamide is prepared by free radical initiated aqueous solution polymerization according to the proportion of 1: 5: 25; respectively cutting the prepared colloid into pieces, drying and crushing, then mixing the prepared two polymer solid powders according to the proportion of 1: 1, and dissolving the mixture in water to generate the variable-phase gel profile-control oil-displacing agent. The profile control oil displacement agent has strong profile control water plugging capability and oil displacement capability, and the preparation process is reliable, and the preparation method of the in-situ phase change gel profile control oil displacement agent is provided.
Detailed Description
Example 1
(1) Weighing 0.02mol of allyl urea, 0.02mol of 2-acrylamidotetradecyl sulfonic acid, 0.1molof 2-acrylamide-2-methylpropanesulfonic acid and 0.5mol of acrylamide, adding into a 200mL reaction bottle, adding 100mL of distilled water, stirring, dispersing and dissolving, adjusting the pH value to 6.8 by using 40% sodium hydroxide, introducing nitrogen for 15 minutes, respectively dropwise adding a 2mL0.5% potassium persulfate solution and a 1mL0.5% sodium bisulfite solution, sealing the reaction bottle, heating to 38 ℃, carrying out heat preservation reaction for 3 hours to obtain a transparent glue block, cooling to room temperature, cutting into small blocks, drying at 85 ℃ in a drying oven for 12 hours, taking out, naturally cooling to room temperature in the drying oven, crushing, and storing in a sealed bag for later use;
(2) Weighing 0.02mol 4-vinylpyridine, 0.1mol acryloyloxyethyl trimethyl ammonium chloride and 0.5mol acrylamide, adding the weighed materials into a 200mL reaction bottle, adding 100mL distilled water, stirring, dispersing and dissolving, adjusting the pH value to 7.0 by using 30% HCl, introducing nitrogen for 15 minutes, respectively dropwise adding a 2mL0.5% potassium persulfate solution and a 1mL0.5% sodium bisulfite solution, sealing the reaction bottle, heating to 40 ℃, preserving heat for reaction for 3 hours to obtain a light yellow transparent glue block, cooling to room temperature, cutting into small blocks, drying at 85 ℃ in a drying oven for 12 hours, taking out, naturally cooling to room temperature in a dryer, crushing, and storing in a sealed bag for later use;
(3) The solid powder stored in the sealed bag obtained in (1) of example 1 and the solid powder stored in the sealed bag obtained in (2) of example 1 were put into a blender together, mixed for 10 minutes, taken out, and stored in a sealed bag.
Example 2
1.5g of the solid powder sample prepared in example 1 (3) was weighed out and dispersed in tap water and sea water, respectively, and dissolved by stirring at a rotation speed of 100 rpm. Measuring the solution viscosity at different dissolution times by using a BROOKFILDDV-III + type rheometer at the temperature of 25 ℃; the viscosities of sample solutions of different concentrations were prepared and measured separately with tap water and seawater. The results are shown in tables 1 and 2.
TABLE 1 viscosity of tap water solution of sample of example 1 at different dissolution times
TABLE 2 viscosity of the solutions of the samples of example 1 at different concentrations (temperature: 60 ℃, shear rate: 170 s-1)
The experimental results show that, at the same concentration, the solution viscosity of the sample in example 1 (3) prepared from tap water is much higher than that of the sample prepared from seawater, and the dissolution rate of the sample in the tap water is slightly higher than that in the seawater.
Example 3
With the time being prolonged, the gel of the sample in the example 1 (3) is changed into white sol, namely initial setting; the sol particles are aggregated and gradually separated from water until the aggregate volume is not increased any more, and a stable gel block is generated, namely the final setting. Tap water and seawater sol appearance and gel block completion time of samples of different concentrations were observed and measured at three temperatures of 30 ℃,60 ℃ and 90 ℃, respectively, and the results are shown in tables 3, 4 and 5.
TABLE 3 initial setting and final setting times (temperature: 30 ℃ C.) for different concentrations of the samples
TABLE 4 initial setting and final setting times (temperature: 60 ℃ C.) for different concentrations of the samples
TABLE 5 initial setting and final setting times (temperature: 90 ℃ C.) for different concentrations of the samples
The result shows that the initial setting time and the final setting time of the sample tap water solution are both smaller than those of the seawater solution; the higher the temperature, the shorter the initial setting and final setting times, whether in tap water or seawater; in addition, the lower the sample concentrations in tap water and seawater at the three temperatures, the shorter the initial setting and final setting times.
Example 4
Respectively weighing 50.0g of a rubber block sample generated by neutralizing a tap water solution and a seawater solution, respectively preparing rubber strips with the dimensions of 5cm x 1cm x 1cm, and standing for 24h; and respectively measuring the tensile force and the elongation at break of the two adhesive tapes by using a tension meter. The results are shown in Table 6.
TABLE 6 Strength of rubber Block (25 deg.C)
The results show that the breaking tension and the maximum elongation of the rubber mass generated in tap water are large. Due to Ca in seawater 2+ 、Mg 2+ The strength and flexibility of the glue block generated in the seawater by the participation of the plasma are lower than those of the glue block generated in the tap water.
Example 5
The samples of example 1 (3) were each tested for rheology at 90 ℃ of the resulting cement masses in tap water and seawater using an RS150 rheometer, and the results are shown in tables 7 and 8.
TABLE 7 rheology of tap water
TABLE 8 rheology of seawater gel blocks
| Shear rate, 1/s | Viscosity, pa.s |
| 1.0 | 3.66 |
| 1.3 | 3.54 |
| 1.6 | 3.43 |
| 2.0 | 3.31 |
| 2.5 | 3.22 |
| 3.2 | 3.15 |
| 3.9 | 3.01 |
| 5.0 | 2.91 |
| 6.3 | 2.82 |
| 7.9 | 2.73 |
| 10.0 | 2.65 |
| 12.6 | 2.58 |
| 15.8 | 2.51 |
| 20.0 | 2.44 |
| 25.0 | 2.38 |
| 31.6 | 2.33 |
| 39.8 | 2.29 |
| 50.0 | 2.25 |
| 63.0 | 2.21 |
| 79.0 | 2.18 |
| 100 | 2.16 |
| 126 | 2.13 |
| 158 | 2.11 |
| 200 | 2.10 |
| 251 | 2.08 |
| 316 | 2.07 |
| 398 | 2.06 |
| 501 | 2.05 |
| 631 | 2.04 |
| 794 | 2.04 |
| 1,000 | 2.03 |
The results show that the shear viscosity of the two rubber blocks is reduced along with the increase of the shear strength at the temperature of 90 ℃, but the viscosity is both more than 2Pa.s, and the viscosity of the tap water rubber block is higher than that of the seawater rubber block.
Example 6
The plugging rate of the high-permeability rock core is an important index for measuring the effect of the profile control oil displacement agent on the rock core profile control, and means that the percentage of the water phase permeability of the rock core is reduced before and after plugging under the same condition, and is expressed by eta; the residual resistance coefficient is the ratio of the water phase permeability of the profile control oil displacement agent before and after injection, and represents the capability of the profile control oil displacement agent in reducing the core permeability, and is represented by RRF.
The calculation formulas of the plugging rate and the residual resistance coefficient are respectively as follows:
in the formula:
eta-plugging rate (%);
k0-core permeability (DC) before plugging;
k-core permeability (DC) after plugging.
In the formula:
RRF-residual drag coefficient;
k0-core permeability (DC) before plugging;
k-core permeability (DC) after plugging.
A sand filling pipe with the length of 30cm and the inner diameter of 2cm is adopted, the sand filling pipe is composed of quartz sand with 40-60 meshes (simulating a high permeable layer) and 100-200 meshes (simulating a low permeable layer), and the quartz sand is cemented and cured by epoxy resin. Measuring basic parameters of the sand-filled pipe core, such as: length, cross-sectional diameter, pore volume, porosity, and the like; assembling a test flow; injecting tap water at a constant flow rate (1.0 mL/min), and measuring the water phase permeability K0 before the rock core is treated; the sample gel of example 1 (3) in the configuration of 0.5% tap water was then back-injected with 0.5PV followed by the simulated formation water with a mineralization of 20000ppm of 0.2PV. The alternating slug injection was repeated three times as described above for the injection method. Then, sealing two ends of the rock core tightly, and standing for 72 hours at the temperature of 60 ℃; and (3) placing the processed rock core on a rock core flow tester, and measuring breakthrough pressure P and water phase permeability K after plugging. Calculating the plugging rate, the residual resistance coefficient and the breakthrough pressure gradient P'. The samples were dissolved in seawater and their plugging capacity was measured in the same manner as described above. The results are shown in tables 9, 10 and 11.
TABLE 9 blocking Rate and coefficient of residual resistance of the tap Water gel (60 ℃ C.)
TABLE 10 sea water gel blocking Rate and residual drag coefficient (60 ℃ C.)
TABLE 11 core breakthrough pressures for tap water and marine hydrogel (60 deg.C)
The results show that the two gels have higher plugging rate on the high-permeability core, and the plugging capability of the tap water gel on the high-permeability core is obviously superior to that of the seawater gel. The reason is that the glue block generated in tap water has good water retention property and strong adhesion to a hydrophilic surface, and under the same condition, the glue block generated in seawater has poor toughness, weak adhesion and small volume due to the existence of calcium and magnesium ions, and shows that the plugging rate to a rock core is low and the breakthrough pressure is small.
Example 7
Weighing 1800g of quartz sand (the particle size is 0.3-0.6 mm) and 200g of crude oil, preserving heat for 24 hours in a drying oven at 80 ℃, and then fully stirring and mixing the crude oil and the quartz sand uniformly for later use; 2000g of the above oil sand was charged from the upper end of a core barrel (diameter. Times. Length: 2.5 cm. Times.10 cm), and compacted with an organic glass rod while charging. Then, covering, sealing and fixing the simulated rock core, putting the simulated rock core into a thermostat, and keeping the temperature at 60 ℃ overnight; preparing a sample solution with the concentration of 0.5% in the (3) example 1 by using tap water and seawater respectively; firstly, the simulated rock core is introduced into a displacement device, and is displaced by hot water of 60 ℃ in a constant-temperature water bath of 60 ℃ (the displacement speed is 3 mL/min) until no crude oil flows out, the displaced crude oil is collected, dehydrated and weighed; then 50mL of 0.5% sample solution is injected into the rock core, the rock core is statically reacted for 72h at 60 ℃, then the rock core is displaced by tap water or seawater, and the displaced fluid is weighed after dehydration. The recovery enhancement after 60 ℃ hot water flooding after the treatment of the sample of example 1 was calculated. The results are shown in tables 12 and 13.
TABLE 12 displacement recovery enhancement after 0.5% treatment of the sample solution (tap water formulation) of example 1 (3)
| Viscosity of crude oil (60 ℃), mPa.s | Hot water flooding recovery ratio% | An increase in recovery ratio after treatment% |
| 4503 | 63.7 | 19.5 |
| 9774 | 52.3 | 18.0 |
| 13608 | 45.5 | 16.3 |
| 18905 | 41.8 | 14.7 |
TABLE 13 displacement recovery enhancement after treatment of 0.5% sample solution (seawater make-up) from example 1 (3)
| Viscosity of crude oil (60 ℃), mPa.s | Hot water drive recovery ratio of% | An increase in recovery ratio after treatment% |
| 4503 | 62.9 | 15.9 |
| 9774 | 52.2 | 13.4 |
| 13608 | 46.0 | 12.0 |
| 18905 | 42.5 | 11.5 |
Claims (1)
1. The preparation method of the in-situ phase change gel profile control oil displacement agent is characterized by comprising the following steps:
(1) Weighing 0.02mol of allylurea, 0.02mol of 2-acrylamidotetradecyl sulfonic acid, 0.1mol of 2-acrylamido-2-methylpropanesulfonic acid and 0.5mol of acrylamide, adding into a 200mL reaction bottle, adding 100mL of distilled water, stirring, dispersing and dissolving, adjusting the pH value to 6.8 by using 40% sodium hydroxide, introducing nitrogen for 15 minutes, respectively dropwise adding a 2mL0.5% potassium persulfate solution and a 1mL0.5% sodium bisulfite solution, sealing the reaction bottle, heating to 38 ℃, carrying out heat preservation reaction for 3 hours to obtain a transparent rubber block, cooling to room temperature, cutting into small blocks, drying at the temperature of 85 ℃ in a drying box for 12 hours, taking out, naturally cooling to room temperature in a dryer, crushing, and storing in a sealed bag for later use;
(2) Weighing 0.02mol 4-vinylpyridine, 0.1mol acryloyloxyethyl trimethyl ammonium chloride and 0.5mol acrylamide, adding the weighed materials into a 200mL reaction bottle, adding 100mL distilled water, stirring, dispersing and dissolving, adjusting the pH value to 7.0 by using 30% HCl, introducing nitrogen for 15 minutes, respectively dropwise adding a 2mL0.5% potassium persulfate solution and a 1mL0.5% sodium bisulfite solution, sealing the reaction bottle, heating to 40 ℃, preserving heat for reaction for 3 hours to obtain a light yellow transparent glue block, cooling to room temperature, cutting into small blocks, drying at 85 ℃ in a drying oven for 12 hours, taking out, naturally cooling to room temperature in a dryer, crushing, and storing in a sealed bag for later use;
(3) Adding the solid powder stored in the sealed bag obtained in the step (1) and the solid powder stored in the sealed bag obtained in the step (2) into a blender, mixing for 10 minutes, taking out, and storing in the sealed bag.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN202210678224.2A CN115232249A (en) | 2022-05-11 | 2022-05-11 | Preparation method of in-situ phase-change gel profile control oil displacement agent |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN202210678224.2A CN115232249A (en) | 2022-05-11 | 2022-05-11 | Preparation method of in-situ phase-change gel profile control oil displacement agent |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CN115232249A true CN115232249A (en) | 2022-10-25 |
Family
ID=83669092
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CN202210678224.2A Pending CN115232249A (en) | 2022-05-11 | 2022-05-11 | Preparation method of in-situ phase-change gel profile control oil displacement agent |
Country Status (1)
| Country | Link |
|---|---|
| CN (1) | CN115232249A (en) |
-
2022
- 2022-05-11 CN CN202210678224.2A patent/CN115232249A/en active Pending
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| US11015109B2 (en) | Particulate profile control agent self-adaptive to size of formation pore throat and preparation method thereof | |
| CN112457838B (en) | Novel acid-resistant and salt-resistant shrinking and swelling agent and preparation method thereof | |
| CN104974724A (en) | Underground gel-forming blocking agent suitable for medium-high temperature high-salt low-permeability reservoirs and preparation method therefor | |
| CN104927816B (en) | A kind of organic profile control agent and preparation method thereof and purposes | |
| CN109369848A (en) | A kind of functional form temperature-resistant anti-salt plugging agent and preparation method thereof | |
| CN109971443B (en) | Three-phase foam channeling sealing agent, preparation method thereof and thickened oil exploitation plugging adjusting method | |
| CN105368423A (en) | Chromium-free composite resin gel-type profile control agent for oil exploitation and preparation method and application thereof | |
| CN111909306B (en) | Double-aqueous-phase PAM/AMPS nano microsphere latex as well as preparation method and application thereof | |
| CN114574180A (en) | Delayed-gelling composite leakage-stopping liquid and preparation method thereof | |
| CN112980407A (en) | Temperature-controllable gel plugging agent and preparation method and application thereof | |
| CN105153361B (en) | A kind of part branched moiety cross-linked polymer oil-displacing agent and preparation method thereof | |
| CN103980872A (en) | Environmental-friendly gel plugging agent applicable to low-temperature oil pool and applications of gel plugging agent | |
| CN111808585B (en) | Slow-crosslinking temperature-resistant salt type high-strength gel and preparation method and application thereof | |
| CN106947454B (en) | Oil displacement system and method for high-permeability oil reservoir | |
| CN115232249A (en) | Preparation method of in-situ phase-change gel profile control oil displacement agent | |
| CN107218009A (en) | A kind of low-permeability sandstone oil reservoir chromium aluminium ion compounding profile control agent and its application method | |
| CN106543383B (en) | A kind of poly- silicon of water-soluble nano/polymer gel oil displacement agent and preparation method thereof | |
| CN111574992A (en) | Nano-phase permeability improver for acidizing and fracturing as well as preparation method and application of nano-phase permeability improver | |
| CN111518532A (en) | Staged fracturing temporary plugging agent for horizontal well and preparation method thereof | |
| CN115505070A (en) | High-temperature-resistant expansion fiber resin plugging material, preparation method thereof and application thereof in leak prevention and plugging of well cementation cement slurry | |
| CN106467733B (en) | Cross linked amphoteric polymeric microballoon-hydrophobic associated polymer profile control agent and its application | |
| CN113943399B (en) | Self-aggregation self-suspension proppant and preparation method and application thereof | |
| CN112094629B (en) | Plugging agent suitable for fractured oil reservoir | |
| CN111961156B (en) | Preparation method of sand-inhibiting water-plugging agent for mussel foot-like protein polymer oil well | |
| CN103242538B (en) | Water-soluble mesh cucurbituril polymer and preparation method thereof |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| PB01 | Publication | ||
| PB01 | Publication | ||
| SE01 | Entry into force of request for substantive examination | ||
| SE01 | Entry into force of request for substantive examination |