Technical method for replacing gas by water injection in ultra-deep layer fracture-cavity type condensate gas reservoir of Tahe River

Abstract

The invention belongs to the technical field of oil-gas exploration and development, and particularly relates to a technical method for water injection and gas replacement of a Tahe ultra-deep layer fracture-cavity type condensate gas reservoir. The method comprises the steps that S1, a gas well with a high overflow port position is selected according to the characteristics of a Tahe ultra-deep layer fracture-cavity type condensate gas reservoir body; s2, determining the optimal water injection opportunity and the optimal water injection rate; s3, injecting water according to the optimal water injection opportunity and the optimal water injection rate; s4, soaking is started after water injection is completed, and the step S5 is executed after soaking is completed; and S5, calculating the critical liquid-carrying flow of the gas well by adopting a Lie Fujian model, and predicting the nozzle flow dynamic state in combination with the isentropic principle of the gas nozzle flow to determine a well opening working system. The water injection gas replacement technical method provided by the invention can be well applied to the oilfield exploitation of the ultra-deep fracture-cavity condensate gas reservoir in the Tahe river, the natural gas recovery rate can be improved, and the economic benefit is greatly improved.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas exploration and development technology, specifically relating to a technical method for water injection and gas replacement in the Tarim River ultra-deep fractured-vuggy condensate gas reservoir. Background Technology

[0002] The Chinese patent with publication number CN102518414A, "Experimental Test Method for Water Injection and Gas Replacement in Fractured-Void Carbonate Condensate Gas Reservoirs," establishes an experimental test method for physical simulation of water injection and gas replacement by creating a full-diameter fractured-void core physical model with a single fracture surface that maintains the integrity of the core.

[0003] Chinese patent CN104895537A, entitled "Water Injection Method for Oil Recovery in Fractured-Vuggy Carbonate Condensate Gas Reservoirs," considers the reverse condensation phenomenon in condensate gas reservoirs and uses three-dimensional geological modeling and numerical simulation technology to demonstrate the feasibility of water injection technology to improve oil recovery in condensate gas reservoirs with different reservoir types and different condensate oil contents.

[0004] In 2015, author Peng Song published an article titled "Water Injection Experiment for Condensate Gas Reservoirs in Fractured-Void Carbonate Reservoirs" in Daqing Petroleum Geology and Development. Drawing on the "water injection for oil replacement" method for fractured-void carbonate reservoirs, the author used outcrop carbonate rocks to create full-diameter fractured-void cores through artificial fracture and void-making techniques. Multi-stage water injection for oil replacement physical simulation experiments were conducted under the original formation conditions (140.6℃, 58MPa), achieving good results.

[0005] The existing technologies represented by the above literature mainly use indoor core experiments and modeling techniques to demonstrate the feasibility of water injection for gas and oil replacement in carbonate fracture-vuggy condensate gas reservoirs. However, the ultra-deep carbonate fracture-vuggy condensate gas reservoirs in the Tarim Basin have significant differences from the core characteristics of condensate gas reservoirs studied by existing technologies due to their diverse reservoir spaces, network-like reservoir structure, and complex configuration relationship between reservoirs and fractures. Therefore, existing water injection technology cannot be applied to the actual production of ultra-deep carbonate fracture-vuggy condensate gas reservoirs in the Tarim Basin.

[0006] The Tahe Oilfield is the largest carbonate oil and gas field discovered in my country to date. The Tahe ultra-deep condensate gas reservoir has diverse reservoir space types, is deeply buried, and has a complex structure with network characteristics. As the pressure decreases, the permeability of the fractures connecting various karst caves decreases, resulting in a smaller reserve recovery. Therefore, the single-well water injection replacement of the Tahe ultra-deep fractured-vuggy condensate gas reservoir differs from water injection replacement considering only the reverse condensation effect in terms of well selection, water injection timing, injection volume, water injection pressure, and injection rate.

[0007] In addition, the current development methods for carbonate fracture-vuggy condensate gas reservoirs at home and abroad are mainly based on depletion development, and the enhanced oil recovery technology is mainly focused on improving condensate oil recovery, lacking a more complete technical method for improving natural gas recovery. Summary of the Invention

[0008] This invention addresses the problems that existing water injection gas replacement technology cannot be applied to the actual production of ultra-deep fractured-vuggy condensate gas reservoirs in the Tarim River Basin, and that existing technologies lack a relatively complete method for improving natural gas recovery. It provides a technical method for water injection gas replacement in ultra-deep fractured-vuggy condensate gas reservoirs in the Tarim River Basin, which can effectively improve the life cycle of ultra-deep fractured-vuggy condensate gas reservoirs in the Tarim River Basin and improve natural gas recovery.

[0009] The technical solution claimed by this invention is as follows:

[0010] A technical method for water injection and gas replacement in the Tarim River ultra-deep fractured-vuggy condensate gas reservoir includes the following steps:

[0011] S1: Based on the characteristics of the Tarim River ultra-deep fractured-vuggy condensate gas reservoir, select a gas well with a high overflow location;

[0012] S2: Determine the optimal water injection timing and volume. The optimal water injection timing is obtained by dynamically monitoring the fracture permeability during the gas reservoir development process of the gas well selected in S1. The water injection volume is determined by analyzing the relationship between water injection volume and pressure recovery and reserve utilization using the material balance method.

[0013] S3: Inject water according to the optimal water injection timing and volume determined in S2. When injecting water, the injection speed should be selected with the largest possible flow rate while meeting the reasonable water injection pressure and on-site water supply conditions. The water injection pressure should be controlled within 20MPa.

[0014] S4: After water injection in S3 is completed, the well will begin to be shut down. The shut-down process will end when the formation pressure stabilizes after water injection, and the process will proceed to S5.

[0015] S5: The critical flow rate for carrying liquid in gas wells is calculated using the Li Min model, and the dynamics of the nozzle flow are predicted by combining the isentropic principle of gas nozzle flow to determine the well opening operation system.

[0016] Preferably, the reservoir in S1 is characterized as follows: the gas reservoir is a relatively independent fracture-vuggy unit, and the configuration relationship between the reservoir and the fracture is network-like.

[0017] Preferably, the optimal timing for water injection in S2 is before the crack permeability begins to be impaired.

[0018] In a specific embodiment of the present invention, the time before the crack permeability begins to be damaged in S2 is the time when the production indicator curve begins to deviate from the straight line, that is, the time when the crack permeability begins to be damaged.

[0019] The formula for calculating the water injection volume mentioned in S2 is:

[0020]

[0021] In the formula: P1 is the formation pressure before water injection, MPa; P2 is the formation pressure after water injection, MPa; V is the volume of the karst cave, m³. 3 .

[0022] The method for determining the water injection volume calculation formula is as follows: According to the gas state equation PV=ZnRT, the total gas volume remains unchanged during the single-well water injection process, therefore the amount of gas moles remains unchanged. The relationship between the gas volume V1 before water injection and the compressed gas volume V2 after water injection is as follows:

[0023] P2V2=Z2nRT (2)

[0024] P1V2=Z2nRT (3)

[0025] Dividing formula (2) and formula (3) yields:

[0026]

[0027] Before water is injected, the entire cavern is filled with gas, so the cavern volume V is equal to the gas volume V1 before water is injected. After water is injected, the cavern volume consists of two parts: the compressed gas volume V2 and the injected water volume V. w ,therefore:

[0028] V = V² + V w (5)

[0029] Substituting formula (4) into formula (5) yields:

[0030]

[0031] When the influence of formation temperature variation is ignored, the deviation factor Z is a function of pressure P. Based on the measured gas deviation factor data of the DK25 well area, the relationship between P / Z and P is fitted to obtain an empirical formula: Where a = 1.4185, b = 0.8617, the empirical formula can be expressed as:

[0032]

[0033] Substituting formula (7) into formula (6), we obtain the formula for the injection volume:

[0034]

[0035] Ignoring the compression of the injected water, i.e.: V w =Q w Finally, the water injection volume formula (1) was determined;

[0036] In the formula: V1 is the gas volume before water injection, m 3 V2 is the volume of gas compressed after water injection, in meters. 3Z1 is the gas deviation factor corresponding to pressure P1, a decimal; Z2 is the gas deviation factor corresponding to pressure P2, a decimal; V w m is the volume of water injected. 3 Q w The volume of water injected is in meters. 3 V represents the volume of the cavern, in meters. 3 .

[0037] Preferably, the simmering time in S4 is optimal when the formation pressure tends to stabilize after water injection.

[0038] In a specific embodiment of the present invention, steps S2-S5 are repeated during the exploitation of the Tarim River ultra-deep fractured-vuggy condensate gas reservoir.

[0039] The mechanism of water injection for gas replacement is as follows: by injecting high-density formation water into the gas well to replenish the energy deficit in the formation, the gas and water in the reservoir undergo gravity separation. As the gas-liquid interface gradually rises, the volume of natural gas is continuously compressed, and the gas well eventually resumes its production capacity.

[0040] The well opening operation system described in S5 is: gas well production rate v g Greater than or equal to the critical fluid carrying velocity v of a gas well cr ;in:

[0041]

[0042] In the formula: Q g For gas production, m 3 / d; A is the cross-sectional area of ​​the nozzle, m 2 ;

[0043]

[0044] In the formula: ρ g The density of the gas is kg / m³. 3 σ represents the surface tension of the gas-liquid mixture, in N / m; ρ1 represents the density of the liquid, in kg / m³. 3 .

[0045] Beneficial effects:

[0046] This invention provides a technical method for water injection and gas replacement in the Tarim River ultra-deep fractured-vuggy condensate gas reservoir. Based on the characteristics of the reservoir, well selection is determined, choosing wells with high overflow locations. Considering the impact of pressure on fracture permeability, the fracture permeability of the selected wells is dynamically monitored during reservoir development to determine the optimal timing for water injection. The relationship between water injection volume, pressure recovery, and reserve utilization is analyzed using the material balance method to determine a reasonable water injection volume. During water injection, the injection rate should be maximized while meeting reasonable injection pressure and on-site water supply conditions to improve production efficiency. The injection pressure should be controlled below 20 MPa. Field practice shows that the above-mentioned water injection and gas replacement method can effectively improve the natural gas recovery rate of the Tarim River ultra-deep fractured-vuggy condensate gas reservoir. Given the simultaneous presence of gas and water in the reservoir after water injection, to avoid wellbore clogging and insufficient production capacity, the Li Min model is used to calculate the critical flow rate for liquid carrying in the gas well. Combined with the isentropic principle of gas nozzle flow, the dynamics of the nozzle flow are predicted to determine the well operation regime. A reasonable operation regime is selected, meaning the gas production rate of the gas well is higher than the critical flow rate for liquid carrying. Practice shows that using the above method to determine a reasonable well operation regime can effectively avoid bottomhole liquid accumulation and ensure stable gas well production. This invention has been applied to the Ordovician carbonate fracture-vuggy condensate gas reservoir in Block 9 of the Tarim Oilfield. As of March 2023, 15 wells were injected with water for gas replacement, with 12 wells showing effectiveness. Among them, well DK25-1 is a reservoir with a network of fractures and karst caves. The pressure during the pressure recovery test propagated along the fractures, and communication with the external reservoir was poor. After water injection, 7.69 million cubic meters of gas were added, increasing the natural gas recovery rate by 8.6%. Water injection and gas replacement in the Ordovician carbonate fractured-vuggy condensate gas reservoir in Block 9 of the Tarim Oilfield has added 150 million cubic meters of recoverable reserves, increasing natural gas recovery by 2-8%. The above practice demonstrates that the water injection and gas replacement technology provided by this invention can be well applied to the development of ultra-deep fractured-vuggy condensate gas reservoirs in the Tarim Oilfield, and can improve natural gas recovery, significantly increasing economic benefits. This solves the problems that existing water injection and gas replacement technologies cannot be applied to the actual production of ultra-deep fractured-vuggy condensate gas reservoirs in the Tarim Oilfield, and that existing technologies lack a comprehensive method for improving natural gas recovery. Attached Figure Description

[0047] Figure 1 This is a flowchart illustrating the implementation of the present invention.

[0048] Figure 2 Chart showing the reasonable water injection volume for water injection and gas replacement in wells D25-1 and D25-3. Detailed Implementation

[0049] The present invention will be further described below with reference to the accompanying drawings:

[0050] This invention provides a technical method for water injection and gas replacement in the Tarim River ultra-deep fractured-vuggy condensate gas reservoir. Based on the fact that the gas reservoir is composed of relatively independent fractured-vuggy units with a network-like structure, wells with high overflow points are prioritized. The optimal timing for water injection is before fracture permeability is compromised, maximizing reserve utilization and minimizing the impact of reverse condensation. The relationship between water injection volume, pressure recovery, and reserve utilization is analyzed using the material balance method, balancing these two factors when determining a reasonable water injection volume. The reasonable water injection pressure should be controlled below 20 MPa, and the injection rate should be as high as possible to improve production efficiency under reasonable injection pressure and on-site water supply conditions. The optimal well-closing time is when the formation pressure tends to stabilize after water injection. The well operation system determined by using the Li Min model (developed by Li Min et al. of Southwest Petroleum University) to calculate the critical flow rate of liquid-carrying gas in the well, combined with the isentropic principle of gas nozzle flow prediction, effectively avoids bottomhole liquid accumulation and ensures stable gas well production.

[0051] Specifically, such as Figure 1 As shown, the above-mentioned technical method for water injection and gas replacement in the Tarim River ultra-deep fractured-vuggy condensate gas reservoir includes the following steps:

[0052] S1: Based on the characteristics of the Tarim River ultra-deep fractured-vuggy condensate gas reservoir, select gas wells with high overflow locations; the characteristics of the reservoir are: the gas reservoir is a relatively independent fractured-vuggy unit, and the configuration relationship between the reservoir and fractures is network-like.

[0053] S2: Determine the optimal water injection timing and volume. The optimal water injection timing takes into account the influence of pressure on fracture permeability and is obtained by dynamically monitoring the fracture permeability during the gas reservoir development process of the gas well selected in S1. The water injection volume is determined by analyzing the relationship between water injection volume and pressure recovery and reserve utilization using the material balance method. The optimal timing is before fracture permeability begins to be damaged.

[0054] Specifically, as pressure decreases, fracture permeability decreases, leading to a reduction in recoverable reserves. The optimal time for water injection is before fracture permeability is damaged, i.e., the time when the production indicator curve begins to deviate from a straight line (i.e., the time when fracture permeability begins to be damaged). At the same time, dynamic monitoring needs to be reasonably arranged during the development of this type of gas reservoir. The advantages are maximizing reserve utilization and minimizing the impact of anti-condensation. The production indicator curve refers to the relationship curve between cumulative gas production and apparent pressure, which is used to characterize the type of energy supplied by the gas reservoir.

[0055] The formula for calculating the water injection volume is:

[0056]

[0057] In the formula: P1 is the formation pressure before water injection, MPa; P2 is the formation pressure after water injection, MPa; V is the volume of the karst cave, m³. 3 .

[0058] The method for determining the water injection volume calculation formula is as follows: According to the gas state equation PV=ZnRT, the total gas volume remains unchanged during the single-well water injection process, therefore the amount of gas moles remains unchanged. The relationship between the gas volume V1 before water injection and the compressed gas volume V2 after water injection is as follows:

[0059] P2V2=Z2nRT (2)

[0060] P1V2=Z2nRT (3)

[0061] Dividing formula (2) and formula (3) yields:

[0062]

[0063] Before water is injected, the entire cavern is filled with gas, so the cavern volume V is equal to the gas volume V1 before water is injected. After water is injected, the cavern volume consists of two parts: the compressed gas volume V2 and the injected water volume V. w ,therefore:

[0064] V = V² + V w (5)

[0065] Substituting formula (4) into formula (5) yields:

[0066]

[0067] When the influence of formation temperature variation is ignored, the deviation factor Z is a function of pressure P. Based on the measured gas deviation factor data of the DK25 well area, the relationship between P / Z and P is fitted to obtain an empirical formula: Where a = 1.4185, b = 0.8617, the empirical formula can be expressed as:

[0068]

[0069] Substituting formula (7) into formula (6), we obtain the formula for the injection volume:

[0070]

[0071] Ignoring the compression of the injected water, i.e.: V w =Q w Finally, the water injection volume formula (1) was determined;

[0072] In the formula: V1 is the gas volume before water injection, m 3 V2 is the volume of gas compressed after water injection, in meters. 3 Z1 is the gas deviation factor corresponding to pressure P1, a decimal; Z2 is the gas deviation factor corresponding to pressure P2, a decimal; V w m is the volume of water injected. 3Q w The volume of water injected is in meters. 3 V represents the volume of the cavern, in meters. 3 .

[0073] Taking the Ordovician fractured-vuggy condensate gas reservoir in the ninth block of the Tarim Basin as an example, a chart showing the reasonable water injection volume during the water injection and pressure maintenance stage of wells D25-1 and D25-3 was drawn. Figure 2 If the point corresponding to the injected water and the pressure after injection falls to the left of the curve, it indicates that the injected water has achieved external diffusion; otherwise, it indicates internal diffusion. For example... Figure 2 As shown, for well D25-3, the pressure recovering to below 40MPa after injecting 86,000 cubic meters of water indicates that the injected water achieved external diffusion during this stage, utilizing more reserves than in the previous stage.

[0074] S3: Inject water according to the optimal water injection timing and volume determined in S2. When injecting water, the injection rate should be selected with a large flow rate as much as possible while meeting the reasonable water injection pressure and on-site water supply conditions. The water injection pressure should be controlled within 20MPa. In a specific embodiment of the present invention, considering the pressure bearing level of the wellhead pipeline and the minimum rupture pressure of the formation, it is determined that the reasonable water injection pressure should be controlled within 20MPa.

[0075] S4: After water injection in S3 is completed, the well is shut-in. The shut-in ends when the formation pressure tends to stabilize after water injection, and then proceeds to S5. In a specific embodiment of the present invention, carbonate fracture-vuggy reservoirs are relatively independent reservoir spaces with different reservoir characteristics and different gas-water replacement rates. The shut-in time cannot be generalized. Therefore, the optimal shut-in time is when the formation pressure tends to stabilize after water injection.

[0076] S5: The critical flow rate for carrying liquid in a gas well is calculated using the Li Min model, and the dynamics of the nozzle flow are predicted to determine the well opening operation system in combination with the isentropic principle of gas nozzle flow. The isentropic principle means that the entropy of the system remains constant during the process, that is, there is no heat flowing in or out when the gas flows through the nozzle or pipeline.

[0077] In a specific embodiment of the present invention, given that gas and water coexist in the reservoir after water injection, in order to avoid wellbore clogging caused by liquid accumulation and insufficient production capacity, the Li Min model of Southwest Petroleum University is used to calculate the critical flow rate for liquid carrying in the gas well. Combined with the isentropic principle of gas nozzle flow, a reasonable well-opening operating regime is selected based on the dynamic selection of the nozzle flow. The well-opening operating regime is as follows: gas well production rate v... g Greater than or equal to the critical fluid carrying velocity v of a gas well cr ;in:

[0078]

[0079] In the formula: Q g For gas production, m 3 / d; A is the cross-sectional area of ​​the nozzle, m 2 ;

[0080]

[0081] In the formula: ρ g The density of the gas is kg / m³. 3 σ represents the surface tension of the gas-liquid mixture, in N / m; ρ1 represents the density of the liquid, in kg / m³. 3 .

[0082] Practice has shown that the well opening operation system determined by the above method can effectively avoid liquid accumulation at the bottom of the well during the production process and ensure stable gas well production.

[0083] In a specific embodiment of the present invention, the mechanism of water injection for gas replacement is as follows: by injecting high-density formation water into the gas well to replenish the formation's depleted energy, the gas and water in the reservoir undergo gravitational differentiation. As the gas-liquid interface gradually rises, the natural gas volume is continuously compressed, ultimately restoring the gas well's production capacity. The above steps S2-S5 are repeated during the exploitation of the Tarim River ultra-deep fractured-vuggy condensate gas reservoir. Field practice shows that the water injection for gas replacement method provided by the present invention can effectively improve the life cycle of the Tarim River ultra-deep carbonate fractured-vuggy condensate gas reservoir and increase the natural gas recovery rate, providing an effective technical method for improving the natural gas recovery rate of similar gas reservoirs.

Claims

1. A technical method for water injection gas replacement in Tahe ultra-deep interstitial condensate gas reservoirs, characterized in that, The method comprises the following steps: S1: selecting a gas well with high overflow port position according to the characteristics of the Tahe super-deep fracture-cavity type condensate gas reservoir; S2: determining the optimal water injection time and water injection volume, wherein the optimal water injection time is obtained by dynamically monitoring the fracture permeability during the development of the gas reservoir of the gas well selected in S1, and the water injection volume is determined by analyzing the relationship between the water injection volume and pressure recovery and reserve movement using the material balance method; S3: injecting water according to the optimal water injection time and water injection volume determined in S2, wherein the water injection speed is as large as possible under the conditions of reasonable water injection pressure and on-site water supply, and the water injection pressure is controlled within 20 MPa; S4: after the water injection in S3 is completed, hatching is started, and the hatching is ended when the formation pressure tends to be stable after the water injection, and then S5 is jumped to; S5: calculating the liquid-carrying critical flow of the gas well using the Li Min model, and determining the opening work system by predicting the nozzle flow dynamics based on the isentropic principle of gas nozzle flow.

2. The technical method for water injection gas replacement in the Tahe ultra-deep interlayer fractured-vuggy condensate gas reservoir according to claim 1, characterized in that, The characteristics of the reservoir in S1 are that the gas reservoir is a relatively independent fracture-cavity unit, and the configuration relationship between the reservoir and the fracture is network-shaped.

3. The technical method for water injection gas replacement in the Tahe ultra-deep interlayer fractured-vuggy condensate gas reservoir according to claim 1, characterized in that, The optimal water injection time in S2 is before the fracture permeability starts to be damaged.

4. The technical method for water injection gas replacement in the Tahe ultra-deep interlayer fractured-vuggy condensate gas reservoir according to claim 3, characterized in that, The time before the fracture permeability starts to be damaged in S2 is the time when the production indicator curve starts to deviate from a straight line, that is, the time when the fracture permeability starts to be damaged.

5. The technical method for water injection gas replacement in the Tahe ultra-deep interlayer fractured-vuggy condensate gas reservoir according to claim 1, characterized in that, The calculation formula of the water injection volume in S2 is: In the formula, P1 is the formation pressure before water injection, MPa; P2 is the formation pressure after water injection, MPa; V is the volume of the solution cavity, m 3 .

6. The technical method for water injection gas replacement in the Tahe ultra-deep interlayer fractured-vuggy condensate gas reservoir according to claim 5, characterized in that, The determination method of the water injection volume calculation formula is as follows: according to the gas state equation PV=ZnRT, the total gas volume is unchanged during the single-well water injection process, so the amount of gas moles remains unchanged, and the relationship between the gas volume V1 before water injection and the compressed gas volume V2 after water injection is as follows: P2V2=Z2nRT (2) P1V2=Z2nRT (3) Dividing formula (2) by formula (3) can obtain: Before water injection, the gas fills the entire cave, so the cave volume V is equal to the gas volume V1 before water injection. After water injection, the cave volume is composed of two parts: the compressed gas volume V2 after water injection and the injected water volume V w Thus: V = V2+ V w (5) Substituting formula (4) into formula (5) can obtain: Ignoring the effect of formation temperature change, the deviation factor Z is a function of pressure P. According to the measured data of gas deviation factor in DK25 well area, the relationship between P / Z and P is fitted, and the empirical formula is obtained: wherein a=1.4185, b=0.8617, and the empirical formula can be expressed as: Substituting formula (7) into formula (6) can obtain the formula of the water injection volume as follows: Without considering the compression of injected water, namely: V w = Q w Finally determine the injection formula (1); Wherein: V1 is the volume of gas before water injection, m 3 ; V2 is the volume of compressed gas after water injection, m 3 ; Z1 is the gas deviation factor corresponding to pressure P1, decimal; Z2 is the gas deviation factor corresponding to pressure P2, decimal; V w is the volume of injected water, m 3 ; Q w is the water injection rate, m 3 ; V is the volume of the solution cavity, m 3 .

7. The technical method for water injection gas replacement in the Tahe ultra-deep interlayer fractured-vuggy condensate gas reservoir according to claim 6, characterized in that, The hatching time in S4 is the best when the formation pressure tends to be stable after the water injection.

8. The technical method for water injection gas replacement in the Tahe ultra-deep interlayer fractured-vuggy condensate gas reservoir according to claim 7, characterized in that, The steps S2-S5 are repeatedly executed during the exploitation of the Tahe super-deep fracture-cavity type condensate gas reservoir.

9. The method according to claim 1, wherein the water injection gas replacement technology is applied to the Tahe ultra-deep interlayer fractured-vuggy condensate gas reservoir. The mechanism of the water injection gas replacement is that the formation energy loss is supplemented by injecting high-density formation water into the gas well, and at the same time, the gas and water in the reservoir are subjected to gravity differentiation, with the gas-liquid interface gradually rising, the natural gas volume being continuously compressed, and finally the production capacity of the gas well being restored.

10. The technical method for water injection gas replacement in the Tahe ultra-deep interlayer fractured-vuggy condensate gas reservoir according to claim 1, characterized in that, The well opening operation system described in S5 is: the gas well gas production rate v g greater than or equal to the gas well liquid carrying critical speed v cr ; Wherein: where: Q g is the gas production, m 3 / d; A is the cross-sectional area of the choke, m 2 ; where: p g is the density of the gas, kg / m 3 ; σ is the gas-liquid surface tension, N / m; and ρ1is the density of the liquid, kg / m 3 .

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