CN111119824A - Method for improving steam huff and puff later development effect of thickened oil - Google Patents
Method for improving steam huff and puff later development effect of thickened oil Download PDFInfo
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- 230000000694 effects Effects 0.000 title claims abstract description 23
- 238000000034 method Methods 0.000 title claims abstract description 22
- 238000011161 development Methods 0.000 title claims abstract description 17
- 239000004088 foaming agent Substances 0.000 claims abstract description 71
- 239000003921 oil Substances 0.000 claims abstract description 42
- XSQUKJJJFZCRTK-UHFFFAOYSA-N Urea Chemical compound NC(N)=O XSQUKJJJFZCRTK-UHFFFAOYSA-N 0.000 claims abstract description 37
- 239000004202 carbamide Substances 0.000 claims abstract description 37
- 239000007864 aqueous solution Substances 0.000 claims abstract description 33
- 238000002347 injection Methods 0.000 claims abstract description 21
- 239000007924 injection Substances 0.000 claims abstract description 21
- 239000000295 fuel oil Substances 0.000 claims abstract description 16
- 238000004519 manufacturing process Methods 0.000 claims abstract description 14
- 238000011156 evaluation Methods 0.000 claims abstract description 11
- 230000003068 static effect Effects 0.000 claims abstract description 7
- 238000012216 screening Methods 0.000 claims abstract description 6
- 238000002791 soaking Methods 0.000 claims abstract description 5
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 17
- 230000018109 developmental process Effects 0.000 claims description 15
- 239000007788 liquid Substances 0.000 claims description 12
- 239000006260 foam Substances 0.000 claims description 9
- 230000035699 permeability Effects 0.000 claims description 9
- 230000015572 biosynthetic process Effects 0.000 claims description 6
- 230000000638 stimulation Effects 0.000 claims description 6
- 230000033558 biomineral tissue development Effects 0.000 claims description 5
- 238000003756 stirring Methods 0.000 claims description 3
- 239000003795 chemical substances by application Substances 0.000 claims 1
- 238000004090 dissolution Methods 0.000 claims 1
- 238000011084 recovery Methods 0.000 abstract description 8
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 description 8
- 230000008859 change Effects 0.000 description 6
- 239000010779 crude oil Substances 0.000 description 6
- 229910002092 carbon dioxide Inorganic materials 0.000 description 4
- 239000001569 carbon dioxide Substances 0.000 description 4
- 238000005187 foaming Methods 0.000 description 4
- 239000000243 solution Substances 0.000 description 4
- 239000004927 clay Substances 0.000 description 3
- 239000000203 mixture Substances 0.000 description 3
- QGZKDVFQNNGYKY-UHFFFAOYSA-N Ammonia Chemical compound N QGZKDVFQNNGYKY-UHFFFAOYSA-N 0.000 description 2
- VHUUQVKOLVNVRT-UHFFFAOYSA-N Ammonium hydroxide Chemical compound [NH4+].[OH-] VHUUQVKOLVNVRT-UHFFFAOYSA-N 0.000 description 2
- UIIMBOGNXHQVGW-UHFFFAOYSA-M Sodium bicarbonate Chemical compound [Na+].OC([O-])=O UIIMBOGNXHQVGW-UHFFFAOYSA-M 0.000 description 2
- 235000011114 ammonium hydroxide Nutrition 0.000 description 2
- 230000003247 decreasing effect Effects 0.000 description 2
- 238000002474 experimental method Methods 0.000 description 2
- 238000009413 insulation Methods 0.000 description 2
- 238000005065 mining Methods 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 230000035945 sensitivity Effects 0.000 description 2
- 239000013589 supplement Substances 0.000 description 2
- 230000008961 swelling Effects 0.000 description 2
- 238000010793 Steam injection (oil industry) Methods 0.000 description 1
- -1 ammonium ions Chemical class 0.000 description 1
- 150000001768 cations Chemical class 0.000 description 1
- 238000000605 extraction Methods 0.000 description 1
- 239000008398 formation water Substances 0.000 description 1
- 230000015784 hyperosmotic salinity response Effects 0.000 description 1
- 230000006872 improvement Effects 0.000 description 1
- 230000008569 process Effects 0.000 description 1
- 238000005070 sampling Methods 0.000 description 1
- 229910000030 sodium bicarbonate Inorganic materials 0.000 description 1
- 235000017557 sodium bicarbonate Nutrition 0.000 description 1
- 230000000087 stabilizing effect Effects 0.000 description 1
- 239000004094 surface-active agent Substances 0.000 description 1
- 238000012360 testing method Methods 0.000 description 1
- 239000002699 waste material Substances 0.000 description 1
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK 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
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK 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 OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK 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
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Abstract
The invention provides a method for improving the steam huff and puff later-stage development effect of thickened oil, which comprises the following steps: screening matched high-temperature resistant foaming agents through static and dynamic evaluation; determining injection parameters and an injection mode of the high-temperature-resistant foaming agent, and injecting the high-temperature-resistant foaming agent into the well; determining the proportion and the dissolving temperature of urea and aqueous solution to form urea aqueous solution, injecting the urea aqueous solution into a well, and injecting steam to preheat a stratum before injecting the urea aqueous solution; steam is injected into the well, so that the dryness and the quantity of the steam are improved; determining soaking time according to the wellhead temperature of the well; and (5) opening the well and continuously producing until the oil-gas ratio reaches the economic limit of 0.1, and stopping production. The invention solves the problem of low recovery ratio in the later period of heavy oil reservoir exploitation in the prior art.
Description
Technical Field
The invention relates to the technical field of oil exploitation, in particular to a method for improving the steam huff and puff later-stage development effect of thickened oil.
Background
Steam huff and puff is the main development mode of the current heavy oil reservoir, but the reservoir heterogeneity of the heavy oil reservoir is strong, the steam overburden is serious, and the oil reservoir is unevenly used. Especially in the later period of steam huff and puff, steam is mainly transported along the dominant channel inefficiently, so that the steam waste is serious, the steam swept volume is small, the middle and lower parts of an oil layer cannot be used, and the oil reservoir recovery ratio is low.
Therefore, the exploitation method in the prior art cannot meet the requirement of effective exploitation in the later period of the heavy oil reservoir, so that the problem of low later-period recovery efficiency exists in heavy oil reservoir exploitation.
Disclosure of Invention
The invention mainly aims to provide a method for improving the steam huff and puff later-stage development effect of thickened oil so as to solve the problem of low recovery efficiency in the later stage of thickened oil reservoir exploitation in the prior art.
In order to achieve the aim, the invention provides a method for improving the effect of the later development of thick oil steam huff and puff, which comprises the following steps: screening matched high-temperature resistant foaming agents through static and dynamic evaluation; determining injection parameters and an injection mode of the high-temperature-resistant foaming agent, and injecting the high-temperature-resistant foaming agent into the well; determining the proportion and the dissolving temperature of urea and aqueous solution to form urea aqueous solution, injecting the urea aqueous solution into a well, and injecting steam to preheat a stratum before injecting the urea aqueous solution; steam is injected into the well, so that the dryness and the quantity of the steam are improved; determining soaking time according to the wellhead temperature of the well; and (5) opening the well and continuously producing until the oil-gas ratio reaches the economic limit of 0.1, and stopping production.
Further, when the high-temperature-resistant foaming agent is screened, the compatibility and stability of the high-temperature-resistant foaming agent are evaluated through the foaming volume and half-life period of the foaming agent at a preset temperature under the water mineralization degree of an oil reservoir stratum, and the plugging capability of the high-temperature-resistant foaming agent is evaluated under stratum conditions of different temperatures, oil saturation degrees and permeability rates.
Further, the preset temperature is between 25 ℃ and 300 ℃.
Further, the high-temperature resistant foaming agent is determined by that the foam volume multiple reaches more than 7.0, the half-life period is more than 5 hours, and the resistance factor is more than 20 at the preset temperature.
Further, when the high-temperature-resistant foaming agent is injected into the well, the gas-liquid ratio of the high-temperature-resistant foaming agent and the concentration of the high-temperature-resistant foaming agent are determined, and the injection mode of the high-temperature-resistant foaming agent is determined according to the ground conditions.
Further, determining the gas-liquid ratio of the high-temperature resistant foaming agent to be 1: 2-1: 1, and the mass fraction of the high-temperature resistant foaming agent to be 0.3-0.5%; the injection mode is a mode of stirring to form bubbles.
Further, the ratio of urea to aqueous solution is 1:2, the dissolving temperature is in the range of 50 ℃ to 60 ℃, and steam is injected for 1 day to preheat the stratum before the urea aqueous solution is injected.
Further, steam is injected into the well, and the steam quality of the steam is greater than or equal to 70%.
Further, the injection amount of the steam is increased by 10% compared with the previous round.
Further, opening the well after the temperature of the well head is reduced to be below 80 ℃.
By applying the technical scheme of the invention, the high-temperature-resistant foaming agent and the urea aqueous solution are injected into the well, the high-temperature-resistant foaming agent can prevent steam from entering along a high-permeability channel, the steam swept volume is enlarged, the steam utilization rate is improved, the urea aqueous solution can reduce the interfacial tension of crude oil and improve the oil-water fluidity ratio, and thus the recovery ratio of later exploitation of a heavy oil reservoir is improved.
Drawings
The accompanying drawings, which are incorporated in and constitute a part of this application, illustrate embodiments of the invention and, together with the description, serve to explain the invention and not to limit the invention. In the drawings:
FIG. 1 is a flow chart illustrating a method of improving the effect of late stage development of thickened oil steam stimulation in the present invention;
FIG. 2 shows the change in drag factor for different oil saturations for the foam of the present invention;
FIG. 3 shows the change in drag factor for different permeabilities of the foamable composition of the present invention;
FIG. 4 shows the change in drag factor at different temperatures for the foamable compositions of the present invention.
Detailed Description
It should be noted that the embodiments and features of the embodiments in the present application may be combined with each other without conflict. The present invention will be described in detail below with reference to the embodiments with reference to the attached drawings.
It is noted that, unless otherwise indicated, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this application belongs.
In the present invention, unless specified to the contrary, use of the terms of orientation such as "upper, lower, top, bottom" or the like, generally refer to the orientation as shown in the drawings, or to the component itself in a vertical, perpendicular, or gravitational orientation; likewise, for ease of understanding and description, "inner and outer" refer to the inner and outer relative to the profile of the components themselves, but the above directional words are not intended to limit the invention.
In order to solve the problem of low later-stage recovery efficiency of a heavy oil reservoir in the prior art, the invention provides a method for improving the later-stage development effect of heavy oil steam huff and puff development.
The following first describes the details of the heavy oil reservoir applied to the method of the present embodiment as follows:
the heavy oil reservoir of the embodiment comprises 15 huff-and-puff wells, the average thickness of the oil layer is 10.2 meters, the average porosity of the oil layer is 22.9 percent, the average permeability of the oil layer is 300 millidarcy, the viscosity of crude oil at 20 ℃ is 1372.8 centipoises, the medium-strength water sensitivity is realized, the average value of the permeability variation coefficient is 1.31, the permeability breakthrough coefficient is 2.38, and the heavy oil reservoir is a medium-strength heterogeneous reservoir. The average production is 4 rounds, the cycle oil production is exponentially decreased along with the increase of the rounds, and the decreasing rate is 23.7 percent. At present, the daily oil production of a single well is 0.85 ton, the comprehensive water content is 94 percent, the water recovery rate is only 68 percent, the integral extraction degree is 15.8 percent, and the oil production is in the middle and later stages of steam huffing and puff.
As shown in fig. 1, the method for improving the effect of the later development of the thick oil steam huff and puff development comprises the following steps: screening matched high-temperature resistant foaming agents through static and dynamic evaluation; determining injection parameters and an injection mode of the high-temperature-resistant foaming agent, and injecting the high-temperature-resistant foaming agent into the well; determining the proportion and the dissolving temperature of urea and aqueous solution to form urea aqueous solution, injecting the urea aqueous solution into a well, and injecting steam to preheat a stratum before injecting the urea aqueous solution; steam is injected into the well, so that the dryness and the quantity of the steam are improved; determining soaking time according to the wellhead temperature of the well; and (5) opening the well and continuously producing until the oil-gas ratio reaches the economic limit of 0.1, and stopping production.
In the invention, when the high-temperature-resistant foaming agent is screened, the compatibility and stability of the high-temperature-resistant foaming agent are evaluated through the foaming volume and half-life period of the foaming agent at a preset temperature under the water mineralization degree of an oil reservoir stratum, and the plugging capability of the high-temperature-resistant foaming agent is evaluated under stratum conditions of different temperatures, oil saturation degrees and permeability rates.
Optionally, the preset temperature is between 25 ℃ and 300 ℃.
Specifically, the foaming agent was first evaluated statically and dynamically. The static evaluation specifically comprises foamability, stability, salt tolerance and thermal stability, and the dynamic evaluation specifically comprises evaluating the plugging capability of the foaming agent under different oil saturation degrees, different permeabilities and different temperatures. In this example, the heavy oil reservoir water type is a sodium bicarbonate type, and the formation water mineralization by sampling analysis is 3938.7 mg per liter. The static evaluation method comprises the steps of preparing different types of foaming agents by using water with equal mineralization degree, and testing the foam volume times and half-life periods of the different types of foaming agents at 25 ℃, 200 ℃ and 300 ℃ respectively. According to the content shown in the table 1, the screening is carried out on the foaming agent to determine the matching high-temperature resistant foaming agent.
TABLE 1 evaluation of thermal stability of foaming agent
Based on the above Table 1, the results show that GFPJ-10 foams have a foaming volume of 6.7 and a half-life of 375 minutes at a high temperature of 300 ℃. Thus, according to this mode, the high-temperature resistant foaming agent obtained by the static evaluation method is determined to be GFPJ-10 foaming agent.
As shown in fig. 2 to 4, a dynamic evaluation method can be used to select a matching high temperature resistant foaming agent. Specifically, the dynamic evaluation method is to simulate actual formation conditions through indoor experiments and evaluate the plugging capability of the foaming agent GFPJ-10 under different oil saturation degrees, different permeabilities and different temperatures. The results show that the foaming agent GFPJ-10 has better capability of plugging a macroporous belt and a high-permeability belt.
In conclusion, the foaming agent GFPJ-10 is a matched high-temperature-resistant foaming agent, and the screened high-temperature-resistant foaming agent can prevent steam from entering along a high-permeability channel after being injected into a well, so that the swept volume of the steam is enlarged, and the steam utilization rate is improved.
From the above analysis, it can be seen that the foam volume multiple of 7.0 or more, the half-life period of 5 hours or more, and the resistance factor of 20 or more at the predetermined temperature are determined to be the matching high temperature resistant foaming agent.
When the high-temperature-resistant foaming agent is injected into a well, determining the gas-liquid ratio of the high-temperature-resistant foaming agent and the concentration of the high-temperature-resistant foaming agent, and determining the injection mode of the high-temperature-resistant foaming agent according to the ground conditions. Specifically, table 2 shows the change in drag factor for the foamable composition at different gas to liquid ratios. Table 3 shows the change in drag factor for different concentrations of the foaming agent.
TABLE 2 resistance factor variation of foaming agent at different gas-liquid ratios
| Gas to liquid ratio | Pressure difference (MPa) | Resistance factor |
| 1:3 | 0.0063 (basic)/0.1594 (working) | 25.3 |
| 1:2 | 0.0082 (basic)/0.3321 (working) | 40.5 |
| 1:1 | 0.0099 (basic)/0.3802 (working) | 38.4 |
| 2:1 | 0.013 (basic)/0.3575 (working) | 27.5 |
| 3:1 | 0.015 (basic)/0.372 (working) | 24.8 |
TABLE 3 resistance factor variation of the foam at different concentrations
As shown in tables 2 and 3, through experiments, the high-temperature resistant foaming agent GFPJ-10 is selected and tested, respectively, under the condition of 250 ℃, the resistance factor change condition of the high-temperature resistant foaming agent GFPJ-10 with the gas-liquid ratio of 1:3 to 3:1 and the mass fraction of 0.1 to 1 percent is tested. The result shows that the gas-liquid ratio of the high-temperature resistant foaming agent GFPJ-10 is between 1:2 and 1:1, and the plugging capability is strongest when the mass fraction is between 0.3% and 0.5%.
From the analysis, the gas-liquid ratio of the high-temperature resistant foaming agent is determined to be in the range of 1:2 to 1:1, and the mass fraction of the high-temperature resistant foaming agent is in the range of 0.3% to 0.5%; the injection mode is a mode of stirring to form bubbles.
In view of the fact that the high-temperature-resistant foaming agent injection process flow of the heavy oil reservoir in the embodiment is that the movable tank car directly injects the high-temperature-resistant foaming agent into a wellhead, the high-temperature-resistant foaming agent injection mode is determined to be foaming injection.
In the invention, the ratio of urea to aqueous solution is 1:2, the dissolving temperature is 50-60 ℃, and steam is injected for 1 day to preheat the stratum before the urea aqueous solution is injected.
Specifically, the proportion of urea and water is optimized, urea is dissolved at a proper water temperature to form a urea aqueous solution, the proportion of the urea to the water is 1:2, the dissolving water temperature is 50-60 ℃, and the urea aqueous solution is prevented from being decomposed due to overhigh water temperature. After the urea aqueous solution is injected into the well, carbon dioxide can be decomposed at high temperature, the carbon dioxide can supplement formation energy, the viscosity of crude oil is reduced, a heat insulation layer can be formed at the top of an oil reservoir, and steam heat loss is reduced. In addition, the formation was preheated by injecting steam into the well at a rate of 60 tons/day for 1 day prior to injecting the aqueous urea solution.
The urea aqueous solution in the embodiment belongs to a multi-medium solution, the formation conditions are simulated, and the profit is the highest when the injection amount of the multi-medium solution is 1 ton/m compared with the profit conditions of the multi-medium solution under six conditions of 0 ton/m, 0.5 ton/m, 1 ton/m, 2 ton/m, 3 ton/m and 4 ton/m through a homogeneous model. Considering that the thick oil reservoir in the embodiment has strong heterogeneity and the effective volume is smaller than that of the mean model, the injection amount of the urea aqueous solution is determined to be 0.8 ton/m according to the previous field implementation experience.
After urea aqueous solution is injected, steam is injected into the well at a steam injection speed of 60 tons/day, the steam dryness is controlled to be more than 70%, and the steam quantity is improved by 10% compared with the previous cycle. It should be noted that the previous round described herein refers to the amount of steam injected during pure steam throughput production.
And (3) determining the soaking time to be 5 days according to the wellhead temperature of the well, opening the well for production when the wellhead temperature is reduced to be below 80 ℃, and stopping production until the oil-gas ratio is lower than the economic limit of 0.1.
Compared with the previous round of pure steam huff-puff mining, the implementation result shows that the oil production of 11 wells in the 15 wells of the embodiment is greatly improved compared with the previous round, the oil production of 1 well is equal to that of the previous round, the oil production effect of 3 wells is not ideal, and the effectiveness rate is 80.0%. Compared with the previous round of pure steam huff and puff mining, the liquid yield is increased by 2604.26 tons and is improved by 51.0 percent, the oil yield is increased by 646.48 tons and is improved by 41.7 percent, the oil-steam ratio is improved by 0.13, and the effect is obvious.
From the above description, it can be seen that the above-described embodiments of the present invention achieve the following technical effects:
1. the high-temperature resistant foaming agent can prevent steam from entering along a high-permeability channel, so that the swept volume of the steam is enlarged, and the utilization rate of the steam is improved.
2. The urea aqueous solution can decompose carbon dioxide at high temperature, the carbon dioxide can supplement formation energy, the viscosity of crude oil is reduced, a heat insulation layer can be formed at the top of an oil reservoir, and steam heat loss is reduced.
3. The urea aqueous solution can decompose ammonia gas at high temperature, the ammonia gas is easy to dissolve in water to form ammonia water, the ammonia water and the crude oil can form a surfactant, the interfacial tension of the crude oil is reduced, and the oil-water fluidity ratio is improved; meanwhile, ammonium ions can exchange with cations in the swelling clay, and the swelling clay has the effects of stabilizing the clay and reducing water sensitivity.
4. The high-temperature resistant foaming agent and the urea aqueous solution are injected into the well, so that the recovery ratio of the heavy oil reservoir in the later exploitation stage is improved.
It is to be understood that the above-described embodiments are only a few, but not all, embodiments of the present invention. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
It is noted that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of example embodiments according to the present application. As used herein, the singular is intended to include the plural unless the context clearly dictates otherwise, and it should be further understood that the terms "comprises" and/or "comprising," when used in this specification, specify the presence of features, steps, operations, devices, components, and/or combinations thereof.
It should be noted that the terms "first," "second," and the like in the description and claims of this application and in the drawings described above are used for distinguishing between similar elements and not necessarily for describing a particular sequential or chronological order. It is to be understood that the data so used is interchangeable under appropriate circumstances such that the embodiments of the application described herein are capable of operation in sequences other than those illustrated or described herein.
The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention, and various modifications and changes may be made by those skilled in the art. Any modification, equivalent replacement, or improvement made within the spirit and principle of the present invention should be included in the protection scope of the present invention.
Claims (10)
1. A method for improving the effect of the late development of heavy oil steam huff and puff, which is characterized by comprising the following steps:
screening matched high-temperature resistant foaming agents through static and dynamic evaluation;
determining injection parameters and an injection mode of the high-temperature-resistant foaming agent, and injecting the high-temperature-resistant foaming agent into a well;
determining the proportion and the dissolving temperature of urea and aqueous solution to form urea aqueous solution, injecting the urea aqueous solution into the well, and injecting steam to preheat the stratum before injecting the urea aqueous solution;
injecting the steam into the well to improve the dryness and quantity of the steam;
determining soaking time according to the wellhead temperature of the well;
and (5) opening the well and continuously producing until the oil-gas ratio reaches the economic limit of 0.1, and stopping production.
2. The method for improving the effect of the thick oil steam huff and puff later development according to claim 1, wherein during the screening of the high temperature-resistant foaming agent, the compatibility and stability of the high temperature-resistant foaming agent are evaluated through the foam volume and half-life period of the foaming agent at a preset temperature under the water mineralization degree of the oil reservoir stratum, and the plugging capability of the high temperature-resistant foaming agent is evaluated under the stratum conditions of different oil saturation, permeability and temperature.
3. The method for improving the effect of late stage exploitation of steam stimulation of thick oil according to claim 2, wherein the preset temperature is between 25 ℃ and 300 ℃.
4. The method for improving the effect of late stage development of thickened oil steam huff and puff as claimed in claim 2, wherein the determination that the foam volume multiple reaches more than 7.0, the half-life period is more than 5 hours and the resistance factor is more than 20 at the preset temperature is the high temperature resistant foam agent.
5. The method for improving the effect of the later development of the thickened oil steam huff and puff is characterized in that when the high-temperature-resistant foaming agent is injected into the well, the gas-liquid ratio of the high-temperature-resistant foaming agent and the concentration of the high-temperature-resistant foaming agent are determined, and the injection mode of the high-temperature-resistant foaming agent is determined according to the ground conditions.
6. The method for improving the effect of the late steam stimulation development of the thickened oil according to claim 5, wherein the gas-liquid ratio of the high-temperature-resistant foaming agent is determined to be in a range of 1:2 to 1:1, and the mass fraction of the high-temperature-resistant foaming agent is in a range of 0.3% to 0.5%; the injection mode is a mode of stirring to form bubbles.
7. The method for improving the effect of late stage exploitation of steam stimulation of heavy oil according to claim 1, wherein the ratio of urea to aqueous solution is 1:2, the dissolution temperature is in the range of 50 ℃ to 60 ℃, and the steam is injected for 1 day before the urea aqueous solution is injected to preheat the formation.
8. The method for improving the effect of late stage exploitation of thick oil steam stimulation according to claim 1, wherein the steam is injected into the well, and the steam quality of the steam is greater than or equal to 70%.
9. The method for improving the effect of late stage exploitation of thick oil steam throughput as claimed in claim 8, wherein the injection amount of steam is increased by 10% compared with that of pure steam throughput exploitation.
10. The method for improving the effect of the late stage exploitation of the steam stimulation of the thick oil according to any one of claims 1 to 9, wherein the well is opened after the temperature of the well head is reduced to below 80 ℃.
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