CN118029954A - Channeling sealing method for inter-well channeling channels in gas-drive oil reservoir - Google Patents
Channeling sealing method for inter-well channeling channels in gas-drive oil reservoir Download PDFInfo
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Abstract
The invention relates to the technical field of oil and gas field development engineering, in particular to a channeling sealing method for an inter-well channeling passage in a gas-driven oil reservoir, which comprises the following steps: selecting an oil reservoir to be plugged, wherein the injection well and the production well are communicated by a gas channeling channel; injecting inorganic salt solution into the stratum through an injection well, and stopping injection when the inorganic salt solution is detected in the produced liquid of the production well; a CO 2 -containing gas is injected into the formation through an injection well. According to the channeling sealing method provided by the invention, CO 2 is continuously contacted with the inorganic salt solution to promote the crystallization and precipitation of inorganic salt in the inorganic salt solution, so that the inter-well channeling channel is plugged. Compared with the reagents injected in the prior art, the inorganic salt solution has better temperature and salt resistance, wider oil reservoir applicability, and good injectability of the solution can be ensured in the form of the solution, and the solution can be far moved in the stratum and has longer channeling sealing effect by matching with the subsequent injection of the gas containing CO 2.
Description
Technical Field
The invention relates to the technical field of oil and gas field development engineering, in particular to a channeling sealing method for an inter-well channeling passage in a gas-driven oil reservoir.
Background
In the development of gas injection of oil reservoirs, due to the heterogeneity of the stratum or the difference in fluidity between the injected gas and crude oil, the injected gas tends to preferentially enter a high-permeability area with smaller flow resistance in the stratum, uneven propulsion is shown on the longitudinal section of the oil reservoir, and the fingering phenomenon is serious. In particular, the dominant seepage region between the injection well and the production well gradually develops into a well-to-well gas channeling channel in the middle and later stages of reservoir development. The injected gas can easily directly reach the bottom of the production well along the crossflow channel between the wells and is produced, so that the gas yield in the production well is increased sharply, and the oil yield is greatly attenuated. In addition, the ineffective circulation of the injected gas between the injection well and the production well has not continued to effectively expand its swept area in the reservoir, resulting in dramatic deterioration of reservoir development. Therefore, the method can inhibit or block the gas channeling, enlarge the swept volume of the injected gas, and has great significance for improving the oil reservoir development effect.
The existing channeling sealing method on the mine site can be used for improving the fluidity difference between the injection fluid and the crude oil, including viscosity increase of the injection fluid, viscosity reduction of the crude oil and the like; or directly plugging a channeling area in the stratum by using a chemical agent, wherein the channeling area comprises paraffin-rosin, high molecular polymer, inorganic sediment and the like. Specifically, common means for solving the above-mentioned channeling problem include chemical agent-assisted gas channeling, gel/gel channeling or inorganic precipitation channeling, etc.
For example, chinese patent CN 105952425A relates to a method for improving recovery ratio of common heavy oil reservoir by assisting CO 2 throughput with a chemical agent, wherein the chemical agent is added into CO 2 throughput for assistance, the chemical agent is a viscosity reducer and/or a foaming agent, and the chemical agent and CO 2 cooperate to form foam in the stratum to block the channeling area, thereby effectively inhibiting CO 2 channeling and expanding the scope of coverage. However, in the process, the foam stability is deteriorated and the blocking effect is weakened due to the influence of the stability of the foam itself, and the method has a limited range of action and a short duration time due to the adsorption of the liquid film on the rock wall surface under the complex stratum condition.
Chinese patent CN 107556996A relates to a CO 2 response in-situ gel channeling-blocking agent and a preparation method thereof, the provided CO 2 response in-situ gel channeling-blocking agent is suitable for an oil reservoir low pH value environment caused by CO 2 flooding, a hydrophobically modified polyacrylamide polymer solution is gelled in situ, gas channeling channels such as heterogeneous hypertonic zones, natural/artificial cracks and the like in the CO 2 flooding oil reservoir are blocked, and the control and inhibition or prevention of gas channeling and the expansion of swept volume are realized. However, gel channeling blocking agent has strong adaptability to stratum, and the high viscoelasticity makes the migration distance of the blocking agent limited, so that the blocking range is smaller. In addition, the plugging strength of the plugging agent is weakened along with the plugging time, and the injected fluid is easy to bypass the plugging agent to further form a channeling flow, so that the plugging is invalid.
The Chinese patent CN 102797442A relates to a deep liquid flow diversion method, which adopts inorganic sediment as a plugging agent, and controls the process of precipitation reaction in stratum pore medium by adjusting the content of sediment ions in injected water or adding an antiscaling agent to change the thermodynamic and dynamic conditions of the reaction, thereby generating sediment in a preset region of the stratum deep and achieving the purpose of diversion of deep profile control liquid. But the construction requirements of the method are strict, and the thermodynamic and kinetic control difficulties are high in the face of complex stratum conditions.
From the above, although the current channeling sealing system and method play a great role in guaranteeing the increase and stable yield of the oil reservoir, some problems still exist, and the channeling sealing system and method are influenced by complex oil reservoir conditions, have severe applicable conditions and are limited in use environment. In particular to an inorganic precipitation channeling sealing system and method, because the inorganic precipitation reaction belongs to ionic reaction, the reaction speed is high, the control difficulty is high, the migration distance is short, and the preset channeling sealing effect is difficult to achieve.
Therefore, aiming at the problems of the existing channeling sealing technology, how to provide a channeling sealing method with better injectability, smaller process control difficulty and more efficient and convenient operation becomes a technical problem to be solved.
Disclosure of Invention
The invention aims to overcome the defects of the prior art, and provides a channeling sealing method for an inter-well channeling in a gas-driven oil reservoir, which can be used for effectively sealing the inter-well channeling only by sequentially injecting an inorganic salt solution and CO 2 -containing gas.
In order to achieve the technical effects, the invention adopts the following technical scheme:
a channeling sealing method for an inter-well channeling passage in a gas-driven oil reservoir comprises the following steps:
s1, selecting an oil reservoir to be plugged, wherein an injection well and a production well are communicated through a gas channeling channel;
s2, injecting inorganic salt solution into the stratum through an injection well, and stopping injection when the inorganic salt solution is detected in the produced liquid of the production well;
S3, injecting the gas containing CO 2 into the stratum through an injection well.
According to the channeling sealing method provided by the invention, CO 2 is continuously contacted with the inorganic salt solution, and the dissolution of CO 2 in the inorganic salt solution and the reduction of solvent water can promote the crystallization and precipitation of inorganic salt in the inorganic salt solution, so that the channeling channels between wells are plugged. Specifically, in the pore throat of the reservoir, flowing CO 2 is continuously contacted with the inorganic salt solution, and CO 2 continuously impacts the solution in the process, so that solvent water in the inorganic salt solution is changed from a liquid state to a gas state, and then is carried away by fast flowing CO 2, thereby reducing the solvent water, concentrating the inorganic salt solution, and further promoting the crystallization of inorganic salt; CO 2 can be dissolved in the inorganic salt solution to generate inorganic salt ions, so that solutes in the solution are increased, concentration of the solution is accelerated, and crystallization and precipitation of inorganic salt are promoted. The method provided by the invention changes the channeling blocking principle in the prior art, does not need to inject other chemical reagents such as polymers, surfactants or antiscaling agents, and greatly reduces the damage of the chemical reagents to the oil reservoir.
Meanwhile, compared with the reagent injected in the prior art, the inorganic salt solution has better temperature and salt resistance, has wider oil reservoir applicability, can ensure good injectability in the form of the solution, and is matched with the subsequent injection of CO 2 -containing gas, so that the solution has a deeper migration distance in the stratum and a longer channeling sealing effect.
Preferably, the reservoir to be plugged also meets the following conditions: the average thickness of the oil-bearing reservoir of the oil reservoir is more than or equal to 5m; the oil-containing area is more than 0.5km 2; the permeability is less than or equal to 400 multiplied by 10 -3μm2.
Further preferably, the production mode of the oil reservoir to be plugged is any one of one injection and one production, multiple injection and multiple production or one injection and multiple production.
Preferably, the solute inorganic salt in the inorganic salt solution is selected from NaCl, caCl 2, naHCO 3 and the like, and further preferably, the solute inorganic salt composition in the inorganic salt solution is adjusted according to the salt composition in the formation water in the reservoir to be plugged; the solvent is fresh water, pure water or stratum water.
It is further preferred that the total mineralization of the inorganic salt solution is higher than the mineralization of the formation water in the reservoir to be plugged.
Preferably, the CO 2 -containing gas is pure CO 2, flue gas, CO 2 purge gas or other CO 2 -containing gas; further preferably, the volume fraction of CO 2 in the CO 2 -containing gas is greater than 30%.
Preferably, in both step S2 and step S3, the injection pressure is less than the formation fracture pressure.
Preferably, in the step S3, the volume ratio of the injection amount of the CO 2 -containing gas to the injection amount of the inorganic salt solution is (3-5): 1.
Along with the injection of CO 2, inorganic salt crystals in the inorganic salt solution start to be separated out, the plugging effect also occurs, and the injection pressure of the gas also rises. In the actual injection process, when the injection pressure increase is obviously slowed down, the gas injection can be stopped.
The invention has the beneficial effects that:
1. According to the channeling sealing method provided by the invention, flowing CO 2 can be continuously contacted with the inorganic salt solution, CO 2 continuously impacts the solution in the process, so that solvent water in the inorganic salt solution is changed from a liquid state to a gaseous state, and then is carried away by fast flowing CO 2, so that the solvent water is reduced, the inorganic salt solution is concentrated, and the crystallization precipitation of inorganic salt is further promoted; CO 2 can be dissolved in the inorganic salt solution to generate inorganic salt ions, so that solutes in the solution are increased, concentration of the solution is accelerated, and further, crystallization of the inorganic salt is promoted to separate out to plug a channeling channel. The method provided by the invention changes the channeling blocking principle in the prior art, does not need to inject other chemical reagents such as polymers, surfactants, antiscaling agents and the like, and greatly reduces the damage of the chemical reagents to the oil reservoir.
2. In the channeling sealing method provided by the invention, compared with the reagents injected in the prior art, the inorganic salt solution has better temperature and salt resistance, has wider oil reservoir applicability, and meanwhile, the solution form can ensure good injectability, and the solution can be far moved in the stratum and has longer channeling sealing effect by matching with the subsequent injection of CO 2 -containing gas. Meanwhile, the inorganic salt solution has the advantages of simple components, easy preparation, low cost, lower viscosity of the salt solution, and great advantages in injectability and operability, and is convenient for large-scale field application under oilfield working conditions.
3. In the channeling sealing method provided by the invention, the CO 2 is used, so that serious corrosion problem to equipment is avoided, and the air source is rich and can be flue gas or CO 2 flooding produced gas and the like. In addition, the injected CO 2 is also a good oil displacement agent, and can effectively improve the recovery ratio of crude oil and realize the sealing and storage of CO 2 while salt precipitation seals channeling.
Drawings
FIG. 1 is a schematic diagram of the gas drive wave of the reservoir to be plugged in example 1;
FIG. 2 is a schematic diagram of the gas flooding waveform of the plugged reservoir in example 1;
FIG. 3 is a graph showing the variation of the core permeability decrease degree with the initial permeability in experimental example 1;
FIG. 4 is a graph showing the change of the degree of core permeability decrease with the mineralization degree of the inorganic salt solution in experimental example 2;
FIG. 5 is a graph showing the variation of the core permeability decrease degree with the CO 2 injection rate in experimental example 3;
FIG. 6 is a graph showing the permeability change of different cores using different plugging methods in experimental example 4;
Wherein 1 is an injection well, 2 is a production well, 3 is a reservoir, 4 is a gas channeling channel, and 5 is a sweep region for injecting gas.
Detailed Description
The invention will be further described with reference to the drawings and examples.
For the oil reservoir at the middle and later stages of gas drive exploitation, a gas channeling passage is formed between the injection well and the production well, and the gas channeling passage is in the high-gas-content production stage. The invention provides a channeling sealing method for an inter-well channeling passage in a gas-driven oil reservoir, which comprises the following specific steps:
s1, selecting an oil reservoir to be plugged, which is communicated with an injection well and a production well through a gas channeling passage, wherein the oil reservoir to be plugged also needs to meet the following conditions: the average thickness of the oil-bearing reservoir of the oil reservoir is more than or equal to 5m; the oil-containing area is more than 0.5km 2; the permeability is less than or equal to 400 multiplied by 10 -3μm2; meanwhile, the production mode of the oil reservoir to be plugged is any one of one injection and one production, multiple injection and multiple production or one injection and multiple production;
S2, injecting inorganic salt solution into the stratum through an injection well, wherein the injection pressure is less than or equal to the stratum fracture pressure, and after the salt solution preferentially enters a cross flow channel between wells, the salt solution moves towards the production well end along the cross flow channel; when inorganic salt solution is detected in the produced liquid of the production well, the salt solution is indicated to be filled in the channeling channel, and injection is stopped;
S3, injecting the gas containing CO 2 into the stratum through an injection well, wherein the injection pressure is less than or equal to the stratum fracture pressure; CO 2 gas preferentially enters the cross-flow channel between wells and is continuously contacted with the inorganic salt solution in the channel. CO 2 continuously diffuses into the salt solution under the effects of pressure gradient, concentration difference and the like, gradually evaporates and takes away moisture in the salt solution, the concentration of the salt solution is increased, salt in the solution is crystallized and separated out, the salt is precipitated, accumulated and grown in the pore throats of an oil reservoir, and finally the pore channels of the oil reservoir are blocked, so that the cross flow channels among wells are blocked, and the effect of adjusting the gas flooding profile is exerted.
In the step S2, the mineralization degree of the inorganic salt solution is higher than the mineralization degree of formation water in the oil reservoir to be plugged. The solute inorganic salt in the inorganic salt solution is selected from inorganic salts such as NaCl, caCl 2 or NaHCO 3, and the specific composition is adjusted according to the composition of formation water in the oil reservoir to be plugged; the solvent is fresh water, pure water or stratum water.
In step S3, the CO 2 -containing gas is pure CO 2, flue gas, CO 2 -driven gas or other CO 2 -containing gas; further preferably, the volume fraction of CO 2 in the CO 2 -containing gas is greater than 30%; in the step S3, the volume ratio of the gas injection amount to the inorganic salt solution injection amount is (3-5): 1.
Example 1
A channeling sealing method for an inter-well channeling passage in a gas-driven oil reservoir comprises the following steps:
S1, selecting an oil reservoir to be plugged, which is communicated with an injection well and a production well through a gas channeling passage, as shown in FIG. 1, wherein in the embodiment, the oil reservoir to be plugged is as follows:
The production mode is one injection and one production, and the average thickness of an oil reservoir is 8m; the oil-containing area is 1km 2; the average horizontal permeability of the reservoir is 200×10 -3μm2; the mineralization degree of stratum water in the oil reservoir is 130660.8mg/L; a gas channeling passage has been formed in the reservoir between the injection well and the production well, the injection well and the production well being located within the same gas channeling passage and communicating with each other through the passage;
S2, injecting inorganic salt solution into the stratum through an injection well, wherein the injection pressure is less than or equal to the stratum fracture pressure, and after the salt solution preferentially enters a cross flow channel between wells, the salt solution moves towards the production well end along the cross flow channel; when inorganic salt solution is detected in the produced liquid of the production well, the salt solution is indicated to be filled in the channeling channel, and injection is stopped;
S3, injecting CO 2 -containing gas into the stratum through an injection well, wherein the injection pressure is less than or equal to the stratum fracture pressure, the volume ratio of the injection amount of the CO 2 -containing gas to the injection amount of the inorganic salt solution in the step S2 is 4:1, and in the embodiment, the CO 2 -containing gas is flue gas with the volume fraction of CO 2 of 58%; CO 2 gas preferentially enters the cross-flow channel between wells and is continuously contacted with the inorganic salt solution in the channel. CO 2 continuously diffuses into the salt solution under the effects of pressure gradient, concentration difference and the like, gradually evaporates and takes away moisture in the salt solution, the concentration of the salt solution is increased, salt in the solution is crystallized and separated out, the salt is precipitated, accumulated and grown in the pore throats of an oil reservoir, and finally the pore channels of the oil reservoir are blocked, so that the cross flow channels among wells are blocked, and the effect of adjusting the gas flooding profile is exerted.
In step S2, according to the reservoir physical properties of the reservoir to be plugged and the mineralized components of the formation water, the solvent in the inorganic salt solution is fresh water, the solute inorganic salt comprises NaCl, na 2SO4、NaHCO3、KCl、CaCl2 and MgCl 2, and the specific ion composition and content are shown in table 1:
TABLE 1 inorganic salt ion composition and content Table
In the embodiment, the total mineralization degree of the inorganic salt solution is 194020.6mg/L, which is higher than the mineralization degree of formation water in the oil reservoir to be plugged.
After the plugging is carried out by using the method provided by the application, as shown in figure 2, the gas drive wave range returns to the normal state again.
Experimental example 1
Through an indoor experiment, the permeability adaptability of the channeling sealing method disclosed by the invention is explored by using a core displacement device. The experimental procedure was as follows:
(1) Selecting 4 cores with different permeabilities, placing the cores in an oven for high-temperature drying, vacuumizing for 24 hours, and then saturating the inorganic salt solution;
(2) After the rock core is saturated with the inorganic salt solution, pure CO 2 is continuously injected at the flow rate of 0.2mL/min at the temperature of 60 ℃ and the pressure of 8MPa for displacement until the steam quality in the gas collecting bottle is kept constant or slightly reduced.
The permeability before and after all core experiments were measured using a conventional permeability meter, and the degree of permeability decrease was calculated as shown in the following table, and the change curve of the core permeability decrease with the initial permeability is shown in fig. 3.
Table 2 experimental parameter table
In the table, the calculation formula of the degree of decrease in permeability is:
Experimental results and analysis:
The lower the initial permeability of the core, the greater the degree of decrease in permeability after the experiment. Experiments show that the lower the initial permeability of the stratum is, the higher the plugging strength of the channeling sealing method is. This is because the pore throats of the hypotonic core are smaller than those of the hypertonic core, and these micropores or fine throats are more easily blocked by the precipitated fine salt crystal particles, thereby blocking the pore throats. The core with larger permeability has larger pore channels, and is difficult to block compared with the core, so that the core has smaller reduction degree of the permeability and lower blocking strength.
Experimental example 2
Through an indoor experiment, the change of the plugging strength of the channeling sealing method along with the mineralization degree of the inorganic salt solution is explored by using a rock core displacement device, and the higher the concentration of the salt solution is, the higher the mineralization degree is. The experimental procedure was as follows:
(1) Selecting 4 cores with similar permeability, placing the cores in an oven for high-temperature drying, vacuumizing for 24 hours, and respectively saturating inorganic salt solutions with different mineralization degrees;
(2) After the rock core is saturated with the inorganic salt solution, flue gas containing 80% CO 2 by volume fraction is continuously injected at the flow rate of 0.2mL/min for displacement at the temperature of 60 ℃ and the pressure of 8MPa respectively until the steam quality in the gas collecting bottle is kept constant or slightly reduced.
The permeability before and after all core experiments were measured using a conventional permeability meter, and the degree of permeability decrease was calculated as shown in the following table, and the change curve of the degree of core permeability decrease with the mineralization degree of the inorganic salt solution is shown in fig. 4.
Table 3 table of experimental parameters
In the table, the calculation formula of the degree of decrease in permeability is:
Experimental results and analysis:
The higher the mineralization degree of the inorganic salt solution is, the greater the reduction degree of the core permeability is after the experiment. Experiments show that the higher the mineralization degree of the inorganic salt solution is, the higher the plugging strength of the channeling sealing method is. This is because the higher the mineralization degree of the inorganic salt solution, the more evaporated salt is crystallized and separated out in the CO 2 injection process, the more easily the rock pore channel is blocked, so that the higher the core permeability is, the higher the blocking strength is.
Experimental example 3
Through an indoor experiment, the change of the plugging strength of the channeling sealing method along with the CO 2 injection rate is explored by using a rock core displacement device. The experimental procedure was as follows:
(1) Selecting 4 cores with similar permeability, placing the cores in an oven for high-temperature drying, vacuumizing for 24 hours, and respectively saturating inorganic salt solutions;
(2) After the rock core is saturated with the inorganic salt solution, CO 2 flooding produced gas with the volume fraction of 70% is continuously injected at the flow rates of 0.02, 0.2, 1 and 2mL/min respectively at the temperature of 60 ℃ and the pressure of 8MPa for displacement until the steam quality in the gas collecting bottle is kept constant or slightly reduced.
The permeability of all cores before and after the experiment was measured using a conventional permeability meter, and the degree of permeability decrease was calculated as shown in the following table, and the variation curve of the degree of core permeability decrease with the injection rate of CO 2 is shown in fig. 5.
Table 4 table of experimental parameters
In the table, the calculation formula of the degree of decrease in permeability is:
Experimental results and analysis:
The higher the injection rate of CO 2, the greater the degree of core permeability reduction after the experiment. Experiments show that the higher the injection rate of CO 2 is, the higher the plugging strength of the channeling sealing method is. This is because, the higher the injection rate of CO 2, the more gas flowing through the pore throat during CO 2 injection, the more H 2 O evaporates into the gas phase and is carried away, the concentration of the inorganic salt solution increases significantly, the more evaporated salt crystallizes out, the more easily the rock pore channel is blocked, and the greater the degree of core permeability reduction, the higher the blocking strength.
Experimental example 4
Through an indoor experiment, the continuous plugging effect of the channeling sealing method provided by the invention, CN105952425A and CN107556996A is explored by using a core displacement device. The experimental procedure was as follows:
And3 cores with similar permeability are selected, and are placed in an oven for high-temperature drying, and then experiments are respectively carried out.
Core #13 (invention):
(1) Injecting an inorganic salt solution at a flow rate of 0.2mL/min at 60 ℃ and 8 MPa;
(2) CO 2 was injected at a flow rate of 0.2mL/min until the vapor quality in the gas cylinders remained constant or slightly reduced;
(3) After 1d, the permeability of the core after the experiment is measured by using a conventional permeability meter;
(4) The core was allowed to stand at 60℃and 8MPa, and the permeability of the core was measured 2 times at intervals of 5d using a conventional permeability meter.
Core #14 (CN 105952425A):
(1) CO 2 is injected at the flow rate of 0.3mL/min at 60 ℃ and 8MPa, and the foaming agent provided in the example 1 in CN105952425A is injected at the flow rate of 0.1mL/min until the foam is stably produced at the outlet end of the core;
(2) After 1d, the permeability of the core after the experiment is measured by using a conventional permeability meter;
(3) The core was allowed to stand at 60℃and 8MPa, and the permeability of the core was measured 2 times at intervals of 5d using a conventional permeability meter.
Core #15 (CN 107556996 a):
(1) The hydrophobically modified polyacrylamide polymer solution provided in example 1 of CN107556996a was injected at 60 ℃ at 8MPa at a flow rate of 0.2 mL/min;
(2) Injecting CO 2 at a flow rate of 0.2mL/min until gas is produced at the outlet end of the core;
(3) After 1d, the permeability of the core after the experiment is measured by using a conventional permeability meter;
(4) The core was allowed to stand at 60℃and 8MPa, and the permeability of the core was measured 2 times at intervals of 5d using a conventional permeability meter.
The results of the experiments are arranged, and permeability change curves of different cores are shown in fig. 6.
Experimental results and analysis:
As can be seen from fig. 6, the initial permeability of the 3 cores was similar when untreated. After the treatment is carried out by using the channeling sealing methods provided by the invention, the CN105952425A and the CN107556996A respectively, the permeability of different cores is greatly reduced. But as the rest time increases, the core permeability gradually increases. Wherein, the permeability of the core #14 increases the most with time, and after 10d, the permeability is close to the initial value. Although core #15 had a lower permeability than core #13 after treatment for 1d, its permeability increased substantially with increasing standing time and was significantly higher than core #13. The permeability of the core #13 treated by the method provided by the invention is hardly changed along with the increase of the standing time, and the higher channeling sealing degree is always maintained. In conclusion, the channeling sealing method provided by the invention has obviously better effect than the other two methods.
Claims (7)
1. A channeling sealing method for an inter-well channeling passage in a gas-driven oil reservoir is characterized by comprising the following steps:
s1, selecting an oil reservoir to be plugged, wherein an injection well and a production well are communicated through a gas channeling channel;
s2, injecting inorganic salt solution into the stratum through an injection well, and stopping injection when the inorganic salt solution is detected in the produced liquid of the production well;
s3, injecting gas containing CO 2 into the stratum through an injection well;
The reservoir to be plugged also needs to meet the following conditions: the average thickness of the oil-bearing reservoir of the oil reservoir is more than or equal to 5m; the oil-containing area is more than 0.5km 2; the permeability is less than or equal to 400 multiplied by 10 -3μm2; and the production mode of the oil reservoir to be plugged is any one of one injection and one production, multiple injection and multiple production or one injection and multiple production.
2. The channeling sealing method for the inter-well channeling flow channel in a gas-driven oil reservoir according to claim 1, wherein the composition of solute inorganic salt in the inorganic salt solution is adjusted according to the composition of salt in formation water in the reservoir to be plugged; the solvent is fresh water, pure water or stratum water.
3. The method of plugging a cross-well flow channel in a gas-driven oil reservoir of claim 2, wherein the total mineralization of the inorganic salt solution is higher than the mineralization of formation water in the oil reservoir to be plugged.
4. The method of sealing off a cross-well flow channel in a gas-drive reservoir of claim 1, wherein the CO 2 -containing gas is pure CO 2, flue gas, or CO 2 -drive produced gas.
5. The method of sealing off a cross-well flow path in a gas-drive reservoir of claim 4, wherein the volume fraction of CO 2 in the CO 2 -containing gas is greater than 30%.
6. The method of plugging a cross-well flow channel in a gas-drive reservoir of claim 1, wherein in step S2 and step S3, the injection pressure is less than the formation fracture pressure.
7. The method for sealing a cross-well flow channel in a gas-driven oil reservoir according to claim 1, wherein in the step S3, the volume ratio of the injection amount of the gas containing CO 2 to the injection amount of the inorganic salt solution is (3-5): 1.
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| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN202410314793.8A CN118029954A (en) | 2024-03-19 | 2024-03-19 | Channeling sealing method for inter-well channeling channels in gas-drive oil reservoir |
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| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN202410314793.8A CN118029954A (en) | 2024-03-19 | 2024-03-19 | Channeling sealing method for inter-well channeling channels in gas-drive oil reservoir |
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| CN118029954A true CN118029954A (en) | 2024-05-14 |
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| CN202410314793.8A Pending CN118029954A (en) | 2024-03-19 | 2024-03-19 | Channeling sealing method for inter-well channeling channels in gas-drive oil reservoir |
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| Country | Link |
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| CN (1) | CN118029954A (en) |
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