Liquid drainage method and system for near-wellbore zone of injection and production well of oil and gas reservoir type gas storage

Abstract

The invention discloses an oil and gas reservoir type gas storage injection and production well near-wellbore area liquid drainage method which comprises the steps that on the basis of gas injection front edge positions and formation pressure conditions of adjacent high-yield wells, a plurality of injection and production wells are selected in the gas injection period to serve as target liquid drainage wells; the target liquid drainage well is opened for gas production; and the current position of the gas injection front edge of natural gas injected into the adjacent high-yield well reservoir is determined, and when the current position is diffused to the well bottom of the target liquid drainage well, the produced gas of the target liquid drainage well brings out residual liquid in the near-wellbore zone outside the wellbore. The formation pressure is monitored in real time, the target liquid drainage well is accurately selected, efficient gas production and liquid drainage are conducted by fully utilizing the gas injection front edge position of the adjacent high-yield well and the formation pressure condition, effective management of accumulated liquid in the near-wellbore area is facilitated, and the liquid drainage efficiency and the safety and economical efficiency of gas storage operation are comprehensively improved. On the other hand, the liquid drainage system provided by the invention has corresponding advantages.

Description

Technical Field

[0001] This invention relates to the field of oil and gas storage and transportation technology, and in particular to a method and system for draining fluid from the near-wellbore zone during the gas injection period of an oil and gas reservoir-type gas storage well. Background Technology

[0002] In the management of underground gas storage facilities, well completion and injection operations before new wells are drilled, completed, and put into production, as well as well workover operations required due to wellbore malfunctions during routine high-speed injection and production operations, can all potentially cause contamination and damage to the production layer. These gas storage wells differ significantly from conventional oil and gas field wells due to their deep burial characteristics and high-intensity injection-production cycle operating conditions. Underground gas storage facilities are important energy infrastructure, playing a crucial role when natural gas supply and demand are imbalanced. However, during the injection and production process of gas storage facilities, especially after drilling, completion, and workover operations, the wellbore and near-wellbore area may become contaminated, affecting the operational efficiency of the gas storage facility. The main problems that still exist in the existing technology are: well kill fluid or acidizing fluid may remain during the drilling, completion and workover processes of injection and production wells, and these residues can contaminate the production layer; excessive residual liquid in the wellbore and near-wellbore area can lead to wellbore accumulation, affecting normal gas injection and production operations; wellbore accumulation can drive residual liquid into reservoir pores, occupying space, blocking natural gas flow, and reducing gas phase permeability; direct gas production from wellbore with accumulated liquid can lead to well opening failure and hydrate freezing blockage, affecting the normal operation of gas storage facilities.

[0003] To address the aforementioned problems, a preferred prior art provides a natural gas underground storage liquid drainage and gas production device and method. This method is achieved through the following steps: utilizing the pressure of the gas production layer to allow water-bearing natural gas to enter the liquid drainage and gas production chamber; rotating an impeller to agitate the water-bearing natural gas, achieving liquid-phase atomization; coupling the atomized water-bearing natural gas with a direct jet to form a coupled direct jet; and discharging the coupled direct jet from the exhaust chamber to reduce liquid accumulation within the wellbore.

[0004] While existing technologies have played a positive role in reducing and draining fluid buildup in wellbores, they have limitations in effectively draining near-wellbore areas during the injection-production cycle. These limitations primarily stem from poor on-site operability and their inability to fully meet the high-efficiency operation requirements of gas storage injection-production wells. Specifically, existing drainage methods cannot quickly and effectively remove residual liquid from the near-wellbore area of ​​gas storage injection-production wells, especially under high-pressure and high-speed injection-production conditions. Drainage in the near-wellbore area outside the wellbore is even more difficult because the liquid in this area is harder to directly contact and drain. Existing drainage systems are ill-suited to the special operating conditions of gas storage injection-production wells, such as high-pressure, high-temperature, or chemically complex environments. On-site drainage operations require complex equipment and procedures, increasing operational difficulty and time costs. Furthermore, the drainage process may cause secondary pollution to the reservoir, affecting its long-term performance and the operational efficiency of the gas storage facility.

[0005] It is evident that there is an urgent need to develop more efficient, adaptable, easy-to-operate, and cost-effective drainage systems and corresponding drainage methods to improve the operational efficiency and safety of gas storage injection and production wells.

[0006] To address the problem of poor residual fluid drainage in the near-wellbore area outside the wellbore after injection and production well operations in oil and gas reservoirs, this invention provides a method and system for draining residual fluid in the near-wellbore area during the gas injection period of injection and production wells in oil and gas reservoirs. Summary of the Invention

[0007] This invention addresses the problem of ineffective drainage of residual liquid in the near-wellbore area after injection and production wells in oil and gas reservoirs. It provides a method and system for draining residual liquid in the near-wellbore area during the injection phase of injection wells in oil and gas reservoirs, solving all or at least some of the technical problems. During injection, some injection and production wells are selected for production operations. The produced gas carries away residual liquid in the near-wellbore area. The produced gas is treated to ensure that the separated dry gas meets the required gas quality standards. The treated dry gas is then reinjected into the gas reservoir, achieving gas recycling and improving the operational efficiency of the gas reservoir. This invention resolves the problem of liquid accumulation inside and near the wellbore during the injection phase, avoiding the traditional practice of draining only during the production phase. It achieves a virtuous cycle of injection and production during the injection phase, improving the operational flexibility of the gas reservoir. It is convenient for on-site operation, easy to implement, and reduces operational complexity. It lowers operational risks and improves the safety level of the gas reservoir. It also contributes to ensuring the sustainable operation and environmental protection of the gas reservoir.

[0008] This invention provides a method for draining near-wellbore fluid during the gas injection period of an injection-production well in an oil and gas reservoir, comprising: selecting several injection-production wells as target draining wells during the gas injection period based on the injection front position of adjacent high-yield wells and formation pressure conditions; opening the target draining wells for gas production; determining the current position of the gas injection front in the reservoir of adjacent high-yield wells; and when the current position has diffused to the bottom of the target draining well, the produced gas from the target draining well carries away the residual fluid in the near-wellbore area outside the wellbore.

[0009] By implementing a scheme where some injection and production wells in the gas storage facility are put into operation during the injection period, and taking advantage of the fact that the injection front edge of adjacent high-yield wells has already affected the operated well, as well as the high formation pressure in the middle and late stages of injection, the gas produced by the operated well can carry residual liquid out of the wellbore. This invention optimizes the operation strategy of the injection and production wells, effectively removing residual liquid from the near-wellbore area outside the wellbore before gas production and during the gas production and drainage process. This improves gas production efficiency and the operational efficiency of the gas storage facility, enabling effective drainage during the injection period. This breaks with the traditional practice of restoring normal operation only through gas production and drainage during the production period, and reduces problems such as formation pressure reduction and wellbore blockage caused by residual liquid, thus contributing to the long-term stable operation of the gas storage facility.

[0010] In some optional embodiments, the method for selecting the target drainage well includes: monitoring the injection front position during the mid-to-late stage of gas injection in the gas storage reservoir; obtaining formation pressure data during the mid-to-late stage of gas injection based on measured formation pressure data from injection and production wells and pressure data from reservoir monitoring wells, and assessing and determining the formation pressure conditions; analyzing the monitoring results of the formation pressure conditions and the injection front position to identify target areas that meet preset pressure distribution concentration and pressure gradient indicators; and selecting a number of injection and production wells within the target area as the target drainage wells.

[0011] The beneficial effects of this technical solution are as follows: When selecting drainage wells, formation pressure conditions must be fully considered. On the one hand, excessively low formation pressure may hinder oil and gas migration, affecting drainage efficiency; on the other hand, excessively high formation pressure may increase drilling and production risks. Formation pressure coefficient and pressure gradient are important indicators for assessing whether formation pressure is normal. When selecting drainage wells, these indicators can be used to evaluate formation pressure conditions, further ensuring the safety and efficiency of the drainage process.

[0012] In some optional embodiments, the method further includes: monitoring the current formation pressure of the gas storage facility in real time before gas production; comparing the difference between the current formation pressure and the preset upper limit formation pressure of the gas storage facility during the gas injection period; and determining that the gas production and drainage requirements of the target drainage well are met if the proportion of the difference to the upper limit formation pressure is below a preset threshold.

[0013] The beneficial effects of this technical solution are as follows: by precisely controlling the formation pressure, it can not only effectively avoid the safety risks caused by excessive formation pressure, but also ensure that under appropriate pressure conditions, the target drainage well can efficiently and stably carry out the residual liquid in the near-wellbore area outside the wellbore, thereby further improving the drainage efficiency and optimizing the operation performance of the gas storage facility.

[0014] In some optional embodiments, the method for determining the current position of the injection front of natural gas in an adjacent high-yield well reservoir includes: performing microseismic monitoring and injection front monitoring at a preset monitoring frequency during the middle and late stages of gas injection in the gas storage facility to determine the current position of the injection front.

[0015] The beneficial effects of this technical solution are as follows: by setting a preset monitoring frequency, microseismic monitoring and gas injection front monitoring are implemented in the middle and late stages of gas injection in the gas storage facility to determine the leading edge position of the injected natural gas, which further improves the accuracy and real-time performance of monitoring, and can more effectively manage the gas storage facility injection and production process, ensuring the safe operation and efficient utilization of the gas storage facility.

[0016] In some optional embodiments, the method further includes employing a methanol injection antifreeze process before and / or during gas production and drainage from the target drainage well.

[0017] The beneficial effects of this technical solution are as follows: by injecting methanol into the well or natural gas, it prevents hydrate formation and pipeline freezing caused by low temperatures. Methanol injection can be performed before reopening a draining well after a long period of shutdown, helping to remove residual liquid in the pipeline and preventing hydrate formation and freezing at low temperatures. Alternatively, methanol can be injected during gas production and draining processes, depending on the actual situation and needs, to maintain natural gas flow and prevent freezing.

[0018] In one specific embodiment, the methanol injection antifreeze process includes starting methanol injection before gas production from the target drainage well according to a preset advance time threshold; during the injection process, the operating status parameters of the pipeline are monitored in real time, and the injection volume and injection frequency are adjusted based on the operating parameters to meet the requirements for inhibiting hydrate formation; wherein, the advance time threshold is at least 12 hours; the operating parameters include pressure parameters and temperature parameters.

[0019] In some optional embodiments, the method further includes: processing the well flow material carried out of the wellbore through a hydrocarbon dew point control unit to separate dry gas and water-containing components; processing the dry gas to meet the gas quality requirements and then re-injecting it into the gas storage group.

[0020] The beneficial effects of this technical solution are as follows: It further refines the well fluid carried out of the wellbore through a hydrocarbon-water dew point control unit, effectively separating dry gas and water-bearing components. The treated dry gas, after meeting specific quality requirements, is reinjected into the gas storage reservoir, achieving efficient utilization of well fluids and resource recycling. Simultaneously, it ensures the safe and stable operation of the gas storage reservoir, significantly improving the practicality and environmental friendliness of near-wellbore drainage during the gas injection phase of oil and gas reservoir-type gas storage wells.

[0021] In one specific embodiment, before the hydrocarbon dew point control unit processes the gas, the status of the process control valve is confirmed to ensure that the process is open and without bypass, and that the gas sampling and injection processes are connected.

[0022] The treatment of the well fluid includes: connecting the target drainage well to the gas production process, and continuously injecting methanol into the injection-production pipeline from the wellhead of the target drainage well.

[0023] In some optional embodiments, the method further includes: draining residual fluid from the wellbore area and emptying the fluid in and near the wellbore area; gradually restoring the wellhead pressure to the normal production state before the operation; and adjusting the current well fluid gas-liquid ratio to the original oil and gas reservoir level based on the original oil and gas reservoir gas-liquid ratio before the target drainage well was converted into the gas storage tank.

[0024] The beneficial effects of this technical solution are as follows: it further enhances the drainage efficiency of the wellbore area and the management of wellhead pressure recovery. By effectively draining residual fluid from the well and near-wellbore area, it ensures a clean well environment, providing favorable conditions for subsequent operations. Simultaneously, it gradually restores the wellhead pressure to the normal production state before operations, ensuring the stability and safety of the production process. Furthermore, by adjusting the current well fluid gas-liquid ratio to its original level based on the original gas-liquid ratio of the target drainage well before its modification, it not only optimizes production parameters but also improves the storage efficiency and operational effectiveness of the gas storage facility.

[0025] In some optional embodiments, the method further includes: after the target drainage well is opened for gas production, continuously tracking the wellhead pressure change; if the wellhead pressure does not decrease when the opening degree of the wellhead gas production regulating valve is increased, then it is determined that the target drainage well has been successfully opened.

[0026] The beneficial effects of this technical solution are as follows: By continuously tracking changes in wellhead pressure and observing whether the wellhead pressure decreases accordingly when the opening of the wellhead gas production regulating valve increases, it is possible to determine whether the target drainage well has been successfully opened. This allows for real-time and accurate judgment of the drainage well's opening status, ensuring the safety and efficiency of the gas production process. Through dynamic monitoring of wellhead pressure, measures can be taken quickly if no pressure response or abnormality is detected, avoiding potential risks and losses.

[0027] In some optional embodiments, the method further includes calculating a minimum gas flow rate that ensures the gas can carry the accumulated liquid in the well smoothly out without causing an increase in the liquid accumulation in the wellbore or insufficient liquid-carrying capacity; during the gas production and liquid drainage process, the instantaneous flow rate of the target drainage well is monitored in real time, and the instantaneous flow rate is adjusted to keep it above the minimum gas flow rate; wherein the parameters used to calculate the minimum gas flow rate include: bottom hole flow pressure, gas flow critical velocity for liquid carrying, tubing cross-sectional area, natural gas deviation coefficient, gas flow temperature, interfacial tension, liquid density, and gas density.

[0028] The beneficial effects of this technical solution are as follows: By comprehensively considering multiple parameters such as bottom hole flow pressure, critical velocity of gas flow carrying liquid, cross-sectional area of ​​tubing, natural gas deviation coefficient, gas flow temperature, interfacial tension, liquid density, and gas density, the minimum gas flow rate required to ensure smooth discharge of accumulated liquid in the well is accurately determined. During gas production and liquid drainage, the instantaneous flow rate of the target drainage well is monitored and adjusted in real time to ensure that it remains above the minimum gas flow rate. This effectively avoids the problem of increased liquid accumulation in the wellbore or insufficient liquid carrying capacity, significantly improving the efficiency and safety of gas production and liquid drainage, and further achieving precise control and efficient liquid drainage.

[0029] In another aspect, this invention provides a near-wellbore drainage system for injection and production wells in an oil and gas reservoir, comprising: a well selection module configured to select several injection and production wells as target drainage wells during the injection period based on the injection front position and formation pressure conditions of adjacent high-yield wells; a production module connected to the well selection module, configured to remove residual liquid from the near-wellbore area outside the wellbore of the target drainage wells through produced gas; a processing module connected to the production module, configured to process well fluids and separate dry gas; and an injection module connected to the processing module, configured to reinject the separated dry gas into the reservoir group within the gas storage facility; wherein the production module includes a wellhead production regulating valve, a production pipeline, and a methanol injection skid; the processing module includes a hydrocarbon dew point control unit; and the injection module includes a production export valve group and a compressor.

[0030] The beneficial effects of this technical solution are as follows: The system integrates multiple modular designs, including well selection, gas production, treatment, and injection, forming a complete near-wellbore drainage system. Through precise well selection, efficient drainage, advanced gas treatment and reinjection technologies, and real-time monitoring and adjustment capabilities, it can significantly improve the drainage efficiency and safety of injection wells in oil and gas reservoirs during the gas injection period. The well selection module accurately selects target drainage wells based on the injection front location of adjacent high-yield wells and formation pressure conditions. The gas production module utilizes wellhead gas production regulating valves, gas production pipelines, and methanol injection skids to efficiently remove residual liquid from the near-wellbore area of ​​the target drainage well through produced gas, avoiding wellbore accumulation and improving the injection efficiency of the injection wells. The hydrocarbon dew point control unit in the treatment module effectively treats well fluids and separates dry gas, ensuring the quality of gas subsequently injected into the gas reservoir. The injection module re-injects the separated dry gas into the gas reservoir's storage group through the gas production export valve group and compressor, achieving gas recycling and reducing resource waste. It can monitor the instantaneous flow rate of the target drainage well in real time and adjust the instantaneous flow rate to keep it above the minimum gas flow rate, ensuring that the gas can carry the accumulated liquid in the well out smoothly, and the safety and stability of the system are comprehensively improved. Attached Figure Description

[0031] The accompanying drawings, which are incorporated in and form part of this specification, illustrate embodiments consistent with the invention and, together with the description, serve to explain the principles of the invention.

[0032] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, for those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0033] Figure 1 This is a schematic diagram of a near-wellbore drainage system during the gas injection period of an injection-production well in an oil and gas reservoir, provided by an embodiment of the present invention.

[0034] Figure 2 This is a schematic diagram of a near-wellbore drainage method during the gas injection period of an oil and gas reservoir-type gas storage well, according to an embodiment of the present invention. Detailed Implementation

[0035] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this application, not all embodiments. Based on the embodiments of this application, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this application.

[0036] like Figure 1 As shown in the embodiment of this application, a near-wellbore drainage system for an oil and gas reservoir-type gas storage facility is provided, comprising: a well selection module (not shown), configured to select several injection and production wells as target drainage wells during the gas injection period based on the injection front position and formation pressure conditions of adjacent high-yield wells; a gas production module 1, connected to the well selection module, configured to remove residual liquid from the near-wellbore zone outside the wellbore of the target drainage wells through produced gas; a processing module 2, connected to the gas production module 1, configured to process well fluids and separate dry gas; and an injection module 3, connected to the processing module 2, configured to reinject the separated dry gas into the reservoir group within the gas storage facility.

[0037] Specifically, the gas production module 1 includes: a wellhead gas production regulating valve 11, a gas production pipeline 12, and a methanol injection skid 10; the processing module 2 is equipped with a hydrocarbon-water dew point control unit; the injection module 3 includes: a gas production external transmission valve group 31 and a compressor 32. For example... Figure 1 As shown, the methanol injection skid 10 is installed between the wellhead of the target drainage well and the gas production regulating valve 11. One end of the gas production pipeline 12 is connected to the wellhead gas production regulating valve 11, and the other end is connected to the processing module 2. The gas production export valve group 31 is installed between the compressor 32 and the processing module 2.

[0038] In one specific embodiment, the hydrocarbon dew point control unit comprises the following devices: a production separator 21, an air cooler 22, a pre-cooling separator 23, a heat exchanger 24, and a cryogenic separator 25. The hydrocarbon dew point control unit may also be composed of or include other devices, and is not limited thereto. Figure 1 In the example scenario, the input end of the production separator 21 is connected to the gas production pipeline 12, and the output end is connected to the air cooler 22; the output end of the air cooler 22 is connected to the precooling separator 23; the output end of the precooling separator 23 is connected to the heat exchanger 24; the heat exchanger 24 and the cryogenic separator 25 perform processing, including precooling, throttling expansion, cryogenic separation, condensate treatment, and recycling, so that the condensate oil and ethylene glycol-rich liquid in the natural gas are effectively separated and recovered, while ensuring that the hydrocarbon dew point of the pipeline natural gas meets the pipeline transportation standard requirements. Then, the output end of the heat exchanger 24 is connected to the input end of the gas production export valve group 31; the output end of the gas production export valve group 31 is connected to the compressor 32.

[0039] like Figure 2 As shown in the embodiments of this application, a method for draining fluid from the near-wellbore zone of injection and production wells in an oil and gas reservoir is also provided. This method includes: selecting several injection and production wells as target draining wells during the injection period based on the injection front position and formation pressure conditions of adjacent high-yield wells; opening the target draining wells for gas production; determining the current position of the natural gas injection front in the reservoir of the adjacent high-yield wells; and when the current position has diffused to the bottom of the target draining well, the produced gas from the target draining well carries away the residual fluid in the near-wellbore zone outside the wellbore. The illustrated method for draining fluid from the near-wellbore zone of injection and production wells in an oil and gas reservoir is operated by the draining system provided in the embodiments of this invention.

[0040] In one specific embodiment, the method for selecting target drainage wells includes: monitoring the injection front position during the middle and late stages of gas injection in the gas storage facility; obtaining formation pressure data during the middle and late stages of gas injection based on measured formation pressure data from injection and production wells and pressure data from reservoir monitoring wells, and assessing and determining formation pressure conditions; analyzing the monitoring results of formation pressure conditions and injection front position to identify target areas that meet preset pressure distribution concentration and pressure gradient indicators; and selecting several injection and production wells within the target area as target drainage wells.

[0041] In one specific embodiment, before gas production, the current formation pressure of the gas storage is monitored in real time; the difference between the current formation pressure and the preset upper limit formation pressure of the gas storage during the gas injection period is compared. If the difference is less than the preset threshold, the gas production and drainage requirements of the target drainage well are met.

[0042] In one specific embodiment, the method for determining the current position of the injection front of natural gas in an adjacent high-yield well reservoir includes: determining the current position of the injection front by implementing microseismic monitoring and injection front monitoring in the middle and late stages of gas injection in the gas storage facility according to a preset monitoring frequency.

[0043] In one specific embodiment, the drainage method further includes: employing a methanol injection antifreeze process before and / or during the gas production and drainage process of the target drainage well; the methanol injection antifreeze process includes starting methanol injection before the target drainage well is opened for gas production according to a preset advance time threshold; during the injection process, the pipeline's operating status parameters are monitored in real time, and the injection volume and injection frequency are adjusted based on the operating parameters to meet the requirements for inhibiting hydrate formation; wherein, the advance time threshold is at least 12 hours; the operating parameters include pressure parameters and temperature parameters.

[0044] In one specific embodiment, the well flow material brought out of the wellbore is processed by a hydrocarbon dew point control unit to separate dry gas and water-containing components; the dry gas is processed to meet the gas quality requirements and then reinjected into the gas storage group; wherein, before being processed by the hydrocarbon dew point control unit, the status of the process control valve is confirmed to ensure that the process is open and without bypass, and that the gas production and injection processes are connected.

[0045] In one specific embodiment, the drainage method further includes: draining residual fluid from the wellbore area and emptying the fluid in and near the wellbore area; gradually restoring the wellhead pressure to the normal production state before the operation; and adjusting the current well fluid gas-liquid ratio to the original oil and gas reservoir level based on the original oil and gas reservoir gas-liquid ratio before the target drainage well is converted into a gas storage tank.

[0046] In one specific embodiment, the drainage method further includes: after opening the target drainage well for gas production, continuously tracking the wellhead pressure change; when the opening degree of the wellhead gas production regulating valve increases and the wellhead pressure does not decrease, it is determined that the target drainage well has been successfully opened.

[0047] In one specific embodiment, the drainage method further includes: calculating the minimum gas flow rate to ensure that the gas can carry the accumulated liquid in the well smoothly out without causing an increase in the accumulated liquid in the wellbore or insufficient liquid-carrying capacity; during the gas production and drainage process, monitoring the instantaneous flow rate of the target drainage well in real time; adjusting the instantaneous flow rate to keep it above the minimum gas flow rate; wherein the parameters used to calculate the minimum gas flow rate include: bottom hole flow pressure, gas flow critical velocity for liquid carrying, tubing cross-sectional area, natural gas deviation coefficient, gas flow temperature, interfacial tension, liquid density, and gas density.

[0048] The following is for reference only. Figure 1 and Figure 2As shown, a specific example is provided. During the mid-to-late stages of gas injection in the gas storage facility, microseismic monitoring and injection front monitoring are implemented to determine the location of the natural gas injection front in the reservoir of adjacent high-yield wells. Further, based on measured formation pressure data from injection and production wells and pressure data from reservoir monitoring wells, the formation pressure during the mid-to-late stages of gas injection is determined.

[0049] Furthermore, the formation pressure in the mid-to-late stage of gas injection was determined to be close to the upper limit of the design formation pressure during the gas injection period of the gas storage facility, thus meeting the gas production and drainage requirements of the injection-production wells being operated (i.e., the target drainage wells).

[0050] Furthermore, in the specific methanol injection antifreeze process, methanol injection begins 12 hours before the well is opened, and the amount of methanol used should meet the requirements for preventing hydrate formation.

[0051] Further, in a specific embodiment, the preparation before the well fluid is processed by the hydrocarbon dew point control unit is as follows: 1. Confirm that the gas phase inlet and outlet valves of the production separator 21 are in the open position and the liquid phase regulating valve is in the closed position. 2. Confirm that the main flow valve of the air cooler 22 is in the open position and the bypass process valve is in the closed position. 3. Confirm that the gas phase inlet and outlet valves of the precooling separator 23 are in the open position and the liquid phase regulating valve is in the closed position. 4. Confirm that the main flow valve of the heat exchanger 24 is in the open position and the bypass process valve is in the closed position. Confirm that the shut-off JT valve is in the closed position. 5. Confirm that the gas phase inlet and outlet valves of the cryogenic separator 25 are in the open position and the liquid phase regulating valve is in the closed position. 6. Confirm that the gas production export valve group 31 valve is in the open position, and the gas production process is connected to the gas injection process.

[0052] The specific well fluid is processed by the hydrocarbon dew point control unit and then guided to the gas production process by the working well (i.e. the target drainage well). Methanol is continuously injected into the injection and production pipeline through the methanol injection skid 10 at the wellhead of the working well to prevent the produced fluid in the near-wellbore area from freezing and blocking the injection and production pipeline.

[0053] Furthermore, the production pressure is reduced to the production pressure of the gas production unit at the gas storage and injection station via the wellhead gas production regulating valve 11. During the gas production and liquid discharge process of the operated well, the produced natural gas vapor phase is processed by the hydrocarbon-water dew point control unit and then enters the gas production export valve group 31. After the production-injection process is switched, it enters the compressor 32 for pressurization and reinjection into the formation. The produced liquid phase is processed by the hydrocarbon-water dew point control unit and then transported to a qualified processing unit.

[0054] Furthermore, after the injection-production well is put into production, changes in wellhead pressure should be continuously monitored. A successful well opening is indicated by a wellhead pressure that does not significantly decrease with increasing opening of the wellhead gas production regulating valve and meets the requirements for continuous gas and fluid production on-site.

[0055] The specific continuous gas extraction and liquid drainage process should meet the minimum liquid-carrying gas extraction requirement. The minimum liquid-carrying gas extraction volume is determined by the following calculation formulas (1), (2), (3), and (4).

[0056] qSC =2.5×10 4 ·A·P wf ·V g / (ZT) (1)

[0057] A=πd 2 / 4 (2)

[0058] In the formula: q SC —Minimum liquid-carrying gas production rate, x10 4 m 3 / d;

[0059] P wf — Bottom hole flowing pressure, MPa;

[0060] V g —Critical velocity of gas flow carrying liquid, m / s;

[0061] A—Cross-sectional area inside the oil pipe, m² 2 ;

[0062] Z—Natural gas deviation coefficient;

[0063] T—Airflow temperature, K;

[0064]

[0065] Where: σ—interfacial tension, taken as 60mN / m for water;

[0066] ρ l —Liquid density, kg / m³ 3 1074 kg / m³ of water was used. 3 ;

[0067] ρ g —Gas density, kg / m³ 3 .

[0068] ρ g =3.4844×10 3 γ g P wf / (ZT) (4)

[0069] In the formula: P wf — Bottom hole flow pressure, MPa.

[0070] Specifically, once the drainage of fluid in the near-wellbore area of ​​the injection-production well is completed, the wellhead pressure is restored to the normal production state before the operation, and the gas-liquid ratio of the well fluid reaches or approaches the original gas-liquid ratio of the oil and gas reservoir before it was converted into a gas storage facility.

[0071] Furthermore, by combining relevant monitoring technologies within the wellbore of the operated well, a scientific injection and production operation plan is formulated to achieve a virtuous cycle of production during the injection and production cycle of the operated well.

[0072] The above description is merely a specific embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any person skilled in the art can easily conceive of various equivalent modifications or substitutions within the technical scope disclosed in the present invention, and these modifications or substitutions should all be covered within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be determined by the scope of the claims.

Claims

1. A method for draining the near-well zone of a gas injection / production well of a gas storage of the oil and gas reservoir type, characterized in that, The method comprises: selecting several injection-production wells as target drainage wells based on the injection gas front position and formation pressure condition of adjacent high-yield wells during the injection period; opening the target drainage wells for gas production; determining the current position of the injected natural gas injection front in the reservoir of the adjacent high-yield well, and when the current position has diffused to the bottom of the target drainage well, the produced gas from the target drainage well carries out the residual liquid in the near-wellbore zone.

2. The method according to claim 1, wherein the method is characterized by, The method for selecting the target drainage well comprises: monitoring the injection gas front position in the later stage of the gas injection in the gas storage; obtaining the formation pressure data in the later stage of the gas injection according to the measured formation pressure of the injection-production well and the pressure data of the reservoir monitoring well, and evaluating and determining the formation pressure condition; analyzing the monitoring results of the formation pressure condition and the injection gas front position, and identifying the target area that meets the preset pressure distribution concentration index and pressure gradient index; selecting the several injection-production wells as the target drainage wells in the target area.

3. The method according to claim 1, wherein the method is characterized by, Further comprising: monitoring the current formation pressure of the gas storage in real time before gas production; comparing the difference between the current formation pressure and the preset upper limit formation pressure designed for the gas injection period of the gas storage, and if the proportion of the difference to the designed upper limit formation pressure is below the preset threshold, it is determined that the target drainage well meets the gas production and drainage requirements.

4. The method according to claim 1, wherein the method is characterized by, The method for determining the current position of the injected natural gas injection front in the reservoir of the adjacent high-yield well comprises: implementing microseismic monitoring and injection front monitoring to determine the current position of the injection front in the later stage of the gas injection in the gas storage according to a preset monitoring frequency.

5. The method according to claim 1, wherein, Further comprising: using the methanol injection anti-freezing process before and / or during the gas production and drainage of the target drainage well; the methanol injection anti-freezing process comprises starting to inject methanol before the gas production of the target drainage well according to a preset advance time threshold; during the injection process, real-time monitoring of the operating state parameters of the pipeline is performed, and the injection amount and injection frequency are adjusted based on the operating parameters to meet the requirement of inhibiting hydrate generation; wherein the advance time threshold is at least 12 hours; the operating parameters include pressure parameters and temperature parameters.

6. The method of claim 1, wherein the method is used for the drainage of the near wellbore zone of a gas injection and production well of a gas storage reservoir of the oil and gas field type. Further comprising: processing the well stream carried out of the wellbore by a hydrocarbon water dew point control unit to separate dry gas and water-containing part; processing the dry gas to meet the gas quality requirements and then re-injecting it into the group of gas storages in the gas storage; wherein before the processing by the hydrocarbon water dew point control unit, the state of the flow control valve is confirmed to make the flow connected and without bypass, and the gas production and injection processes are connected.

7. The method according to any one of claims 1-6, wherein the method is used for the drainage of the near wellbore zone of a gas injection / production well of a gas storage reservoir of the oil and gas field type, characterized in that, Further comprising: draining the residual liquid in the well zone to empty the liquid in the well and the near-well zone; gradually restoring the wellhead pressure to the normal production state before the operation; based on the original gas-liquid ratio of the oil and gas reservoir before the target drainage well is rebuilt into the gas storage, adjusting the current well stream gas-liquid ratio to the original oil and gas reservoir level.

8. The method for draining the near-well zone of a gas injection / production well of a gas storage of the oil and gas reservoir type according to any one of claims 1 to 6, characterized in that, Further comprising: continuously tracking the wellhead pressure change after the target drainage well is opened for gas production; when the opening degree of the wellhead gas production regulating valve increases, and the wellhead pressure does not decrease, it is determined that the target drainage well is successfully opened.

9. The method of claim 1, wherein the method is used for the drainage of the near wellbore zone of a gas injection / production well of a gas storage reservoir of the oil and gas field type. Further comprising: calculating the minimum gas flow rate to ensure that the gas can carry the accumulated liquid in the well to be drained smoothly without causing the increase of the liquid accumulation in the wellbore or the insufficient liquid carrying capacity. monitoring the instantaneous flow rate of the target drainage well in real time during gas production and liquid drainage; adjusting the instantaneous flow rate to keep it above the minimum gas flow rate; wherein the parameters used to calculate the minimum gas flow rate include bottom hole flowing pressure, gas flow liquid carrying critical velocity, inner cross-sectional area of the tubing, natural gas deviation factor, gas flow temperature, interfacial tension, liquid density, and gas density.

10. A gas reservoir type gas storage injection-production well near-wellbore drainage system, characterized by, comprising: a well selection module configured to select a number of injection-production wells as target drainage wells during the gas injection period based on the injection front position of adjacent high-yield wells and formation pressure conditions; a gas production module connected to the well selection module and configured to bring residual liquid in the near-wellbore zone outside the wellbore of the target drainage well to the wellbore through produced gas; a processing module connected to the gas production module and configured to process well stream and separate dry gas; an injection module connected to the processing module and configured to re-inject the separated dry gas into the reservoir group in the gas storage; wherein the gas production module comprises a wellhead gas production regulating valve, a gas production pipeline, and a methanol injection pry; the processing module comprises a hydrocarbon water dew point control unit; and the injection module comprises: a gas production export valve group and a compressor.

Images