CN114151048A - Gas channeling prevention and oil displacement method for compact reservoir horizontal well - Google Patents
Gas channeling prevention and oil displacement method for compact reservoir horizontal well Download PDFInfo
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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
- E21B43/164—Injecting CO2 or carbonated water
-
- 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
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
-
- 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
- E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
- E21B43/168—Injecting a gaseous medium
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Abstract
A gas channeling-oil displacement preventing method for a tight oil reservoir horizontal well comprises the following steps: injecting a flushing agent into the horizontal well section of the compact oil reservoir with the channeling, flushing residual oil on the surface of the channeling fracture, injecting a temporary plugging agent into the horizontal well section of the compact oil reservoir after flushing residual oil, temporarily plugging a supporting seam and a micro-fracture which do not have the channeling, then injecting a main plugging agent to plug the main fracture with the channeling, injecting a displacing agent into the horizontal well section of the compact oil reservoir after injecting the main plugging agent, continuously displacing the main plugging agent in a shaft into the main fracture with the channeling, stopping injection and waiting for a period of time until the main plugging agent is gelled to form effective plugging, and finally injecting an oil displacing agent into the horizontal well for displacing; the temporary plugging agent capable of automatically plugging removal is used for temporarily plugging micro cracks and supporting cracks in the stratum, permanent damage to the micro cracks and the supporting cracks caused by the main plugging agent during plugging is avoided, the output effect is guaranteed, and therefore the recovery ratio of the low-permeability reservoir is effectively improved.
Description
Technical Field
The invention relates to the technical field of oil reservoir development, in particular to a gas channeling prevention and oil displacement method for a compact oil reservoir horizontal well.
Background
In recent years, unconventional oil and gas occupy an important position in the development of energy in China. The problems of poor reservoir physical property, strong heterogeneity, difficult water injection and the like generally exist in a compact reservoir in unconventional oil gas. Except for adopting gas injection development measures, fracturing transformation is often required to be carried out on a reservoir, and because of reservoir stress complexity and uncertainty of fracture network distribution, fracturing fractures appearing in the transformation process are connected with each other to form a high-permeability fracture channel, so that injection and production wells are communicated, and the oil reservoir production degree is reduced.
Unlike conventional reservoirs, dense oil reservoirs are often developed in a gas drive mode with reservoir fracturing modification measures. Generally, three types of fractures exist in a reservoir that has undergone fracture reformation and has a cross-flow: one type is a main crack communicated with an injection and production well, the existence of the cracks greatly reduces the oil displacement efficiency, and the cracks are also main objects of plugging measures. The second type is a supporting crack without fluid channeling in the fracturing process, the last type is a branch micro-crack in the main crack, and the existence of the latter two types of cracks can effectively improve the sweep efficiency and change the need of protecting the two types of cracks in the plugging measure.
Due to the complexity of the fracture network distribution, the effective plugging of the fractures communicated with the injection and production wells has higher requirements on plugging technology and system. Research shows that the conventional profile control after horizontal well fracturing has the following problems: on one hand, the traditional single profile control agent (gel particles, in-situ gel and the like) has outstanding contradiction between the injectability in a reservoir and deep migration requirements, so that the deep profile control is difficult to realize, and the plugging strength of the traditional single plugging agent hardly meets the crack plugging requirements; on the other hand, the conventional general injection method cannot effectively avoid micro cracks and unconnected cracks, and the cracks are sealed after the measures are taken, so that the early-stage reconstruction measures are poor in effect; finally, as the fracturing fracture mostly belongs to a dynamic fracture, namely, the fracture is opened along with the increase of pressure, the fracture is closed along with the decrease of pressure, and the conventional plugging agent is difficult to achieve effective plugging. Therefore, the conventional single plugging agent and general injection method are not suitable for profile control operation after horizontal well fracturing. The method is difficult to obtain a better effect in a mine field test only by optimizing and improving the traditional profile control method, and needs innovation of technical thought, so that the problem that the gas channeling crack channel can be effectively plugged while micro cracks and unconnected cracks are not damaged is solved.
Disclosure of Invention
In view of the above, the technical problem to be solved by the invention is to provide a gas channeling prevention-oil displacement method for a compact oil reservoir horizontal well, which is used for effectively plugging and displacing a compact oil reservoir with a complex fracture system and improving the recovery ratio of an ultra-low permeability oil reservoir.
The technical scheme of the invention is that the gas channeling-oil displacement preventing method for the compact oil reservoir horizontal well comprises the following steps of:
s1: injecting an oil washing agent into the horizontal well section of the compact oil reservoir with the channeling flow, and washing residual oil on the surface of the channeling flow crack;
s2: injecting a temporary plugging agent comprising a polymer into the horizontal well section of the compact oil reservoir after residual oil is washed away, and temporarily plugging the supporting seams and the microcracks which do not generate fluid channeling;
s3: injecting a main plugging agent comprising a polymer into the temporarily plugged compact oil reservoir horizontal well section to plug a main crack with fluid channeling;
s4: injecting a displacing agent into the compact oil reservoir horizontal well section after the main plugging agent is injected, and continuously displacing the main plugging agent in the shaft into a main crack with the cross flow;
s5: stopping injection and waiting for a period of time until the main plugging agent is gelatinized to form effective plugging;
s6: and after the temporary plugging agent is completely unplugged, injecting an oil displacement agent into the horizontal well, and displacing residual oil in the compact reservoir pore matrix.
In one embodiment of the present invention, the oil-washing agent is capable of reducing the oil-water interfacial tension to 10-3An order of magnitude surfactant solution.
One embodiment of the invention is that the temporary plugging agent can automatically remove the plugging under the stratum condition, the plugging removal time is 4-10 days, and the plugging removal rate is more than 95%.
One embodiment of the invention is that the polymer in the main plugging agent is grafted with a structural group with the electric property opposite to that of the formation rock.
One embodiment of the present invention is that the system formed by the polymer in the primary plugging agent is a secondary gel system.
Further, the secondary gel system is mixed with flexible particles.
One embodiment of the present invention is that the displacement fluid is a polymer solution having a final rate of self-degradation of 90% or more under formation conditions.
One embodiment of the invention is that the time of the stop wait is in the range of 48-72 h.
One embodiment of the invention is that the oil displacement agent comprises natural gas and carbon dioxide.
The invention has the technical effects that:
1. the temporary plugging agent capable of automatically plugging is used for temporarily plugging the microcracks and the supporting fractures in the stratum, so that permanent damage to the microcracks and the supporting fractures caused by the main plugging agent during plugging is avoided, the output effects of the microcracks and the supporting fractures are ensured under the condition that the main fractures are plugged, and the recovery ratio of the low-permeability reservoir is effectively improved.
2. The method is characterized in that a surfactant solution with a strong oil washing effect is used for cleaning the wall surface of the main crack before the main crack is plugged, and the adhesion effect between the wall surface of the crack and the main plugging agent is enhanced by utilizing the charge effect, so that the gas channeling channel can be effectively plugged.
Drawings
In order to more clearly illustrate the technical solution of the embodiments of the present invention, the drawings used in the embodiments will be briefly described below.
FIG. 1 is a flow chart of a specific implementation of the method for preventing gas channeling and oil displacement of a tight reservoir horizontal well in the invention;
FIG. 2 is a schematic diagram of the fracture distribution in a tight reservoir horizontal well according to the present invention;
FIG. 3 is a dynamic graph of the experimental process in example 1 of the present invention;
FIG. 4 is a dynamic graph of the experimental process in example 2 of the present invention;
FIG. 5 is a dynamic graph of the experimental process in example 3 of the present invention.
Detailed Description
The present invention will be described in further detail with reference to the following examples and the accompanying drawings.
In order to make the objects, technical solutions and advantages of the embodiments of the present invention more apparent, the embodiments of the present invention will be described clearly and completely with reference to the accompanying drawings, which are attached to the drawings and are a part of the embodiments of the present invention, but not all of the embodiments of the present invention. All other embodiments, which can be obtained by a person skilled in the art without any inventive step based on the embodiments of the present invention, are within the scope of the present invention.
Referring to fig. 1, a gas channeling prevention-oil displacement method for a tight reservoir horizontal well specifically comprises the following steps:
step S1: and injecting an oil washing agent into the horizontal well section of the compact oil reservoir with the channeling flow, and washing residual oil on the surface of the channeling flow crack.
In a gas channeling well bore, certain residual oil often exists on the surface of fractured rock, and the contact of the water-soluble gel plugging agent and the rock surface is affected under the condition that an oily substance exists, so that the problems such as poor adhesion effect and the like occur. For the gas channeling oil reservoir, the channeling through cracks are mostly stretchable dynamic cracks, the plugging object is gas, and the adhesion strength of the plugging agent and the rock surface has great influence on the plugging effect of the cracks, so that the oil washing agent is used for cleaning the surfaces of the cracks before plugging, and the gelling effect of the follow-up plugging agent can be effectively improved.
Generally, under the condition of larger crack permeability, the surfactant with obvious effect of reducing the oil-water interfacial tension has better cleaning effect; in order to wash out residual oil in the fracture as much as possible and expose the rock on the surface of the fracture, some embodiments of the invention choose to be able to wash out residual oil in the fractureThe oil-water interfacial tension is reduced to 10-3And injecting the surfactant solution of the order of magnitude as an oil washing agent into the gas channeling shaft for cleaning until the water content in the produced liquid reaches more than 95%, wherein the oil washing process in the step can be considered to meet the requirements.
Step S2: and injecting a temporary plugging agent into the shaft of the compact oil reservoir after the oil washing process is finished, and temporarily plugging the support seams and the micro-cracks without channeling.
The main structural distribution of the fractures in the shaft can be seen in fig. 2, and the fractures comprise main fractures, supporting fractures which are not communicated with the main fractures and micro fractures which are communicated with the main fractures, wherein the main fractures are main objects of gas channeling prevention operation, and the supporting fractures and the micro fractures are main oil production positions of a compact oil reservoir after gas channeling occurs, so that the purpose of the gas channeling prevention operation is to completely block the main fractures which have gas channeling under the condition of ensuring that the supporting fractures and the micro fractures are not damaged as much as possible;
the temporary plugging agent used in the embodiment of the specification is a gel polymer, and is injected to temporarily plug the propping seams and the micro cracks before the gas channeling cracks are plugged, so that the temporary plugging agent can directly enter the micro cracks; the injection amount of the temporary plugging agent can be determined by the fracture volume in the stratum obtained in the well logging process; when the injection operation is started, the inside of the shaft is in a pressure-bearing state, so that the supporting seams are opened to be communicated with the main fractures, and the temporary plugging agent is allowed to enter. Correspondingly, the viscosity distribution of the temporary plugging agent needs to be determined according to the actual working condition and the stratum condition, the viscosity of the temporary plugging agent is not suitable to be too high, the purpose is to avoid influencing the injection process on one hand, and to avoid the higher viscosity from hindering the temporary plugging agent from entering the microcracks and the supporting seams on the other hand, meanwhile, the viscosity of the temporary plugging agent needs to be ensured above the minimum viscosity requirement for smooth gelling under the stratum condition, and the temporary plugging agent is prevented from being subjected to shearing influence when the viscosity is too low to cause non-gelling.
In addition, the temporary plugging agent in the embodiment can also automatically remove the plugging, and the plugging removal rate is ensured to be more than 95%; because the micro cracks and the supporting seams need to be ensured to be opened in the subsequent oil extraction process, after the temporary plugging agent breaks gel automatically under the stratum condition, solid residues which obviously hinder permeation cannot exist, and the plugging removal rate is more than 95 percent, so that the temporary plugging agent cannot cause damage to the micro cracks and the supporting seams; meanwhile, considering that the temporary plugging agent in the subsequent steps needs to ensure the plugging effect before the complete gelling of the temporary plugging agent, the complete self-plugging removal time of the temporary plugging agent is controlled within the range of 4-10 days.
Step S3: and injecting a main plugging agent comprising a polymer into the horizontal well section of the compact oil reservoir obtained after temporary plugging to plug the main crack with the flow channeling.
After the temporary plugging agent is used for temporarily plugging the micro-cracks and the supporting cracks in the crack system in the previous step, the main cracks in the stratum become main gas channeling cracks, the main plugging agent is required to be used for plugging the main cracks, and the injection amount of the main plugging agent can be calculated through the channeling crack volume obtained in the well logging step.
In some embodiments of the present disclosure, a polymer in the main plugging agent is grafted with a structural group having an electrical property opposite to that of the formation rock to form a gel system capable of adsorbing the formation rock, so that under the action of an electric charge, the main plugging agent can generate an active attraction effect with the bare rock washed out by the oil washing agent, since the fracture crack is a dynamic crack, when the plugging agent is injected to complete the subsequent displacement, the crack will expand to a certain extent along with the rise of pressure, and at this time, the main plugging agent will deform along with the expansion of the crack based on its own elasticity and adsorption, so as to dynamically plug the crack, thereby effectively ensuring the close contact between the main plugging agent and the wall surface of the crack, and ensuring the plugging effect; in addition, the breakthrough pressure gradient of the gelled main plugging agent needs to be higher than the starting pressure gradient of the matrix, so that the plugging effect of the main plugging agent is ensured.
In other embodiments, the polymer system formed by the polymer in the primary plugging agent is a secondary gel system, where the secondary gel system refers to a polymer system that is formed by pre-crosslinking the polymer in the primary plugging agent under ground conditions to form a weak gel with a certain viscosity, and then the weak gel is injected into the formation and then is secondarily crosslinked into a polymer system with strength and toughness meeting the plugging conditions under the temperature condition of the formation, because the viscosity of the primary plugging agent in the injection process needs to be controlled within a certain range, on one hand, too low viscosity will affect the gelling performance, and the lower the viscosity of the plugging agent, the higher the filtration loss of the plugging agent will be, and when a large amount of the plugging agent enters the matrix layer, the serious reservoir damage will be caused, the seepage capability of the reservoir will be reduced, so the minimum viscosity required to be ensured at this point of the plugging agent can be lower than 5%, on the other hand, the viscosity of the main plugging agent cannot be too high, and the too high viscosity can cause too high injection pressure and improve injection difficulty and production cost, so the upper limit of the viscosity should be controlled according to the relevant construction cost in the actual production condition; therefore, the secondary gel system with certain basic viscosity can effectively meet the viscosity requirement of the main plugging agent in the injection process, namely, the main plugging agent is firstly crosslinked on the ground in advance to obtain certain viscosity, and simultaneously, better flowing performance is still kept, so that the filter loss is effectively reduced, meanwhile, the main plugging agent can be injected into a specified gas channeling main crack easily and quickly, after the main plugging agent enters a specified position in the main crack, the secondary gel is crosslinked into polymer gel with good strength and toughness under the influence of the formation temperature condition, and the effective plugging of the main crack is realized.
In addition, in some further embodiments of the present invention, partial flexible particles may be further mixed into the secondary gel system, and after the secondary gel and the flexible particles are blended to form a blended system, the secondary gel system has a better suspension effect, and enhances the deep migration capability thereof.
Step S4: and injecting a displacing agent into the horizontal well section of the compact oil reservoir after the main plugging agent is injected, and continuously displacing the main plugging agent in the shaft into the main crack with the channeling.
After the main plugging agent is injected into a stratum according to the designed amount, part of the main plugging agent exists in the main part of a shaft, so that the main plugging agent needs to be pushed into a main crack by using a displacement fluid, the main plugging agent is prevented from being retained in the shaft to be gelatinized and block the shaft, and the main plugging agent can also indirectly drive a temporary plugging agent in the main crack to continuously enter a micro crack connected with the main crack, so that the temporary plugging effect of the micro crack is ensured; meanwhile, in order not to influence the subsequent oil displacement medium to smoothly enter the wellbore, in some embodiments of the invention, the displacement fluid is a polymer solution with a self-degradation rate of more than 90% under the formation condition, the primary plugging agent is effectively replaced, the displacement fluid is ensured to be effectively degraded in time, the injection amount of the displacement fluid can be calculated according to the actual wellbore volume, and the reason for using the polymer displacement fluid is that if a polymer with lower viscosity or clean water is directly used as the displacement fluid, the concentration of a secondary gel system of the primary plugging agent polymer in the wellbore in step S3 is diluted, the gelling strength during secondary gelling is reduced, the plugging effect of gas channeling is influenced, the filtration loss of the secondary gel system is increased, and the matrix damage is enhanced, so the displacement fluid needs to have certain viscosity; meanwhile, the injection of the displacement fluid also needs to meet the actual construction conditions, and the injection difficulty and the steep increase of the cost caused by a high-viscosity high-pressure state are avoided, so that the preferable viscosity of the displacement fluid is higher than the viscosity of the secondary gel system of the main plugging agent polymer, and the exceeding range is controlled within 10% of the viscosity of the secondary gel system, so that the smooth injection and displacement of the displacement agent are ensured.
Step S5: stopping injection and waiting for a certain time until the main plugging agent is gelatinized to form effective plugging.
After the primary plugging agent is displaced into the designated position of the primary fracture by the displacement liquid in step S4, in order to avoid that the subsequent steps are performed when the plugging agent is not completely gelatinized, which causes the system strength to decrease due to the gas entering the gel system of the primary plugging agent, the injection is stopped to wait for the complete gelatinization of the primary plugging agent, and the plugging strength is ensured, in some embodiments of the present invention, the time range of the injection stopping wait is 48 to 72 hours.
Step S6: and injecting an oil displacement agent into the horizontal well, and displacing residual oil in the compact oil reservoir pore matrix.
Because the compact oil reservoir has lower permeability, and conventional oil displacement agents such as water, a surfactant and a polymer solution often have higher injection difficulty, in some embodiments of the invention, gas such as natural gas or carbon dioxide is used as the oil displacement agent to displace the compact oil reservoir, the good fluidity of the gas ensures the injection effect, and meanwhile, the gas can be miscible with crude oil under certain conditions, which is beneficial to reducing the viscosity of the crude oil, realizing miscible phase displacement, greatly improving sweep efficiency and oil washing efficiency until complete gas channeling is achieved by displacement;
it is worth noting that the oil displacement operation needs to be carried out after the temporary plugging agent is completely unplugged, so that the phenomenon that the operation effect is influenced due to oil displacement under the condition that the plugging of the matrix gap plugged by the temporary plugging agent is not completely unplugged and recovered is avoided.
In order to fully understand the steps of the present invention, several sets of examples are provided below to illustrate the specific technical effects of the present invention.
The design mode of the main gas channeling and the supporting gap without gas channeling simulated in the following embodiment is shown in fig. 2, the width of the main gap is controlled by the thickness of a metal gasket, the propping agent is ceramsite, and the crack-forming rock core is wrapped and fixed by a thermoplastic pipe.
Example 1:
the core used in the experiment is artificial conglomerate core (0.5mD), the core has positive charge, the water used is the formation water of a certain compact reservoir, and the degree of mineralization is 3 multiplied by 104mg/L, the used crude oil is the degassed crude oil of the oil field, the viscosity is 4.73mPa.s at 50 ℃, the reservoir temperature is 91 ℃, the width of a main crack is 1mm, the propping agent is 30-50 meshes of ceramsite, the surfactant adopts sodium alkyl alcohol polyoxyethylene ether sulfonate, the temporary plugging agent adopts sodium alginate/acrylamide hydrogel, the complete gel breaking time is controlled to be 4 days, the secondary gel adopts N, N-dimethyl-polyamide-amine, the displacing liquid adopts HPAM solution, and the gas flooding medium is CO2. Through experimental tests, when the viscosity of the main plugging agent is higher than 230mPa.s, the damage rate to the matrix is less than 5%, the problems of dilution effect and cost of the temporary plugging agent and the displacement liquid on the main plugging agent are considered, the viscosity of the temporary plugging agent is 262mPa.s, the viscosity of the main plugging agent is 252mPa.s, and the viscosity of the displacement liquid is 265 mPa.s. The total volume of the unconnected supporting cracks and the micro cracks is 1.25mL, the volume of the main crack is 1.07mL, and the volume of the injection section pipeline is 0.5 mL.
The experimental process is as follows: and vacuumizing the core to saturate water and oil, and then forming a seam and filling sand. CO injection2To complete gas channeling; injecting a surfactant solution to the outlet end to produce a solution with water content of 95%; injecting 1.25mL of temporary plugging agent; injection ofInjecting 0.5mL of polymer solution into 1.07mL of secondary gel, and stopping injection for 48 hours; after the temporary plugging agent is completely broken, subsequent CO is carried out2And (5) driving. Gas flooding, surfactant solution injection, temporary plugging agent injection, polymer solution injection, secondary gel injection and subsequent CO2The drive test dynamics are shown in figure 3. The experimental results show that: after the gas channeling occurs, the subsequent CO is selectively blocked by the temporary blocking agent and the secondary gel2The flooding efficiency is effectively improved by 21.68%.
Example 2:
the core used in the experiment is artificial conglomerate core (0.5mD), the core has positive charge, the water used is the formation water of a certain compact reservoir, and the degree of mineralization is 3 multiplied by 104mg/L, the used crude oil is the degassed crude oil of the oil field, the viscosity is 4.73mPa.s at 50 ℃, the reservoir temperature is 91 ℃, the width of a main crack is 1mm, the propping agent is 30-50 meshes of ceramsite, the surfactant adopts sodium alkyl alcohol polyoxyethylene ether sulfonate, the temporary plugging agent adopts sodium alginate/acrylamide hydrogel, the complete gel breaking time is controlled to be 4 days, the secondary gel adopts N, N-dimethyl-polyamide-amine, the displacing liquid adopts HPAM solution, and the gas flooding medium is natural gas. Through experimental tests, when the viscosity of the main plugging agent is higher than 230mPa.s, the damage rate to the matrix is less than 5%, the problems of dilution effect and cost of the temporary plugging agent and the displacement liquid on the main plugging agent are considered, the viscosity of the temporary plugging agent is 262mPa.s, the viscosity of the main plugging agent is 252mPa.s, and the viscosity of the displacement liquid is 265 mPa.s. The total volume of the unconnected supporting cracks and microcracks is 1.33mL, the volume of the main crack is 1.12mL, and the volume of the injection section pipeline is 0.5 mL.
The experimental process is as follows: and vacuumizing the core to saturate water and oil, and then forming a seam and filling sand. Injecting natural gas to complete gas channeling; injecting a surfactant solution to the outlet end to produce a solution with water content of 95%; injecting 1.33mL of temporary plugging agent; injecting 1.12mL of secondary gel, injecting 0.5mL of polymer solution, stopping injection and waiting for 72 h; and after the temporary plugging agent is completely broken, performing subsequent natural gas flooding. The natural gas flooding-surfactant solution injection-temporary plugging agent injection-polymer solution injection-secondary gel injection-subsequent natural gas flooding experiment dynamics are shown in fig. 4. The experimental results show that: after the gas channeling happens, the subsequent natural gas flooding effectively improves the oil displacement efficiency by 17.38 percent through the selective plugging of the temporary plugging agent and the secondary gel
Example 3:
the core used in the experiment is an artificial conglomerate core (0.5mD), the water used is formation water of a certain compact reservoir, the mineralization degree is 3 multiplied by 104mg/L, the crude oil used is the degassed crude oil of the oil field, the viscosity is 4.73mPa.s at 50 ℃, the reservoir temperature is 91 ℃, the width of a main crack is 1mm, the propping agent is 30-50 meshes of ceramsite, the mass concentration of flexible particles is 0.5% in a blending system of secondary gel and flexible particles, the surfactant adopts sodium alkyl alcohol polyoxyethylene ether sulfonate, the temporary plugging agent adopts sodium alginate/acrylamide hydrogel, the complete gel breaking time is controlled to be 7 days, the secondary gel adopts N, N-dimethyl-polyamide-amine, the flexible particles are rubber particles, the displacing liquid adopts HPAM solution, and the gas flooding medium is CO2. Through experimental tests, when the viscosity of the main plugging agent is higher than 230mPa.s, the damage rate to the matrix is less than 5%, the problems of dilution effect and cost of the temporary plugging agent and the displacement liquid on the main plugging agent are considered, the viscosity of the temporary plugging agent is 262mPa.s, the viscosity of the main plugging agent is 252mPa.s, and the viscosity of the displacement liquid is 265 mPa.s. The total volume of the unconnected supporting cracks and microcracks is 1.49mL, the volume of the main crack is 1.25mL, and the volume of the injection section pipeline is 0.5 mL.
The experimental process is as follows: and vacuumizing the core to saturate water and oil, and then forming a seam and filling sand. CO injection2To complete gas channeling; injecting a surfactant solution to the outlet end to produce a solution with water content of 95%; injecting 1.49mL of temporary plugging agent; injecting a 1.25mL secondary gel and flexible particle blending system, injecting 0.5mL polymer solution, stopping injection and waiting for 72 h; after the temporary plugging agent is completely broken, subsequent CO is carried out2And (5) driving. Gas flooding-surfactant solution injection-temporary plugging agent injection-polymer solution injection-secondary gel injection + flexible particle blending system injection-subsequent CO2The drive test dynamics are shown in figure 5. The experimental results show that: after the gas channeling occurs, the subsequent CO is selectively blocked by the temporary blocking agent and the secondary gel2The oil displacement efficiency is effectively improved by 22.20 percent.
According to the embodiments, the secondary gel of the temporary plugging agent and the main plugging agent or the secondary gel and flexible particle mixed slug is injected into the gas channeling cracks, so that the gas channeling channel can be effectively plugged, the dynamic displacement profile of the tight oil reservoir is improved, a subsequent oil displacement medium obtains a better displacement effect on residual oil and residual oil of the tight matrix, and the recovery ratio of the tight oil reservoir is greatly improved.
The above description is only a preferred embodiment of the present invention, but the scope of the present invention is not limited thereto, and any changes or substitutions that can be easily conceived by those skilled in the art within the technical scope of the embodiments of the present invention are included in the scope of the present invention. Therefore, the protection scope of the present invention shall be subject to the protection scope of the claims.
Claims (9)
1. A gas channeling-oil displacement preventing method for a tight oil reservoir horizontal well is characterized by comprising the following steps of:
s1: injecting an oil washing agent into the horizontal well section of the compact oil reservoir with the channeling flow, and washing residual oil on the surface of the channeling flow crack;
s2: injecting a temporary plugging agent comprising a polymer into the horizontal well section of the compact oil reservoir after residual oil is washed away, and temporarily plugging the supporting seams and the microcracks which do not generate fluid channeling;
s3: injecting a main plugging agent comprising a polymer into the temporarily plugged compact oil reservoir horizontal well section to plug a main crack with fluid channeling;
s4: injecting a displacing agent into the compact oil reservoir horizontal well section after the main plugging agent is injected, and continuously displacing the main plugging agent in the shaft into a main crack with the cross flow;
s5: stopping injection and waiting for a period of time until the main plugging agent is gelatinized to form effective plugging;
s6: and after the temporary plugging agent is completely unplugged, injecting an oil displacement agent into the horizontal well, and displacing residual oil in the compact reservoir pore matrix.
2. The gas channeling-preventing oil displacement method for the tight reservoir horizontal well, according to claim 1, is characterized in that: the oil washing agent can reduce the oil-water interfacial tension to 10-3An order of magnitude surfactant solution.
3. The gas channeling-preventing oil displacement method for the tight reservoir horizontal well, according to claim 1, is characterized in that: the temporary plugging agent can automatically plug under stratum conditions, the plugging time is 4-10 days, and the plugging rate is more than 95%.
4. The gas channeling-preventing oil displacement method for the tight reservoir horizontal well, according to claim 1, is characterized in that: and a structural group with the electric property opposite to that of stratum rock is grafted on the polymer in the main plugging agent.
5. The gas channeling-preventing oil displacement method for the tight reservoir horizontal well, according to claim 1, is characterized in that: the system formed by the polymer in the main plugging agent is a secondary gel system.
6. The gas channeling-oil displacement preventing method for the tight reservoir horizontal well according to claim 5, is characterized in that: the secondary gel system has flexible particles mixed therein.
7. The gas channeling-preventing oil displacement method for the tight reservoir horizontal well, according to claim 1, is characterized in that: the displacement fluid is a polymer solution with the final self-degradation rate of more than 90% under the formation condition.
8. The gas channeling-preventing oil displacement method for the tight reservoir horizontal well, according to claim 1, is characterized in that: the time range of the stop waiting is 48-72 h.
9. The gas channeling-preventing oil displacement method for the tight reservoir horizontal well, according to claim 1, is characterized in that: the oil displacement agent comprises natural gas and carbon dioxide.
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