Method for stabilizing yield of compact sandstone cluster well group

Abstract

The invention relates to a yield stabilizing method for a compact sandstone cluster well group, and belongs to the technical field of natural gas extraction. According to the yield stabilizing method of the compact sandstone cluster well group, the gas source well and the gas-lifted well are selected in the well site in real time, and the gas-lifted well is subjected to gas-lifting liquid drainage and gas production by utilizing the output gas of the gas source well, so that on one hand, the production return pressure of the gas source well can be reduced, and the negative-pressure gas production effect is achieved; and on the other hand, liquid drainage and gas production of the gas-lifted well can be achieved through gas produced by the gas source well, the working system of alternately replacing the gas source well can be achieved by selecting the gas source well and the gas-lifted well in real time, and the effects of gas-lifting liquid drainage of multiple wells and recovery and stable production are achieved. According to the method for stabilizing the yield of the compact sandstone cluster well group, the liquid carrying capacity and the overall yield of the well site can be effectively improved by utilizing the capacity of each gas well in the well site, the recovery and stable production time of the well site is prolonged, the problem of a gas lift gas source is effectively solved, and no pollution gas is discharged.

Description

Technical Field

[0001] The present invention relates to a stable production method for a cluster well group in tight sandstone, belonging to the technical field of natural gas exploitation. Background Technique

[0002] Tight sandstone gas reservoirs generally contain water. With the continuous deepening of development, liquid accumulation at the bottom of gas wells intensifies, resulting in a double decline in production and pressure, a shortened stable production period, and an extended low-pressure and low-production time, thereby leading to a reduction or even shutdown of gas well production. Taking drainage gas production measures has become an effective means to solve the problem of liquid accumulation in gas wells. At the same time, to meet the deployment requirements of the overall development of gas reservoirs and reduce investment costs, large-scale regular well patterns are no longer considered for deployment, and cluster well groups are mostly used for development. During the production process of cluster well groups, as the number and frequency of water-flooded wells increase, it will seriously affect the development effect and process of gas reservoirs.

[0003] Currently, for the slightly liquid-accumulated and water-flooded working conditions of cluster well groups, the nitrogen gas lift process is mostly adopted. The nitrogen gas lift process is a method of injecting high-pressure gas through the annulus between the tubing and the casing, entering the tubing through the bottom of the tubing, thereby carrying out the liquid accumulated in the wellbore from the tubing and then restoring the gas well productivity. It is found during on-site operations that the construction process of sequentially nitrogen gas lifting each gas well in the cluster well group is cumbersome, with a high construction frequency and a long operation cycle, resulting in a low gas lift restoration efficiency; at the same time, a large amount of nitrogen is required, causing a significant increase in cost and being unable to effectively guarantee the gas source. Moreover, the initial investment in nitrogen gas lift equipment is large, the energy consumption is high, and there are also problems such as the emission of polluting gases during the operation process. For high-liquid-production and severely liquid-accumulated water-flooded well groups, the jet pump drainage gas production process is currently adopted, but it has disadvantages such as a relatively large initial cost investment, a more cumbersome equipment construction, and high requirements for water quality during operation. For example, the Chinese utility model patent with the authorization publication number CN217380506U discloses a well-site type jet pump drainage gas production device, which includes a ground power device, a power liquid manifold, a multi-well single-well concentric tube jet pump gas production device, a blowout manifold, a blowout purification device, a liquid storage device, a separation and metering system, and a gas gathering manifold. It restores and stabilizes the production of multiple low-pressure and high-production water wells through a set of ground power liquid systems for multiple jet pump wells. However, this system has a relatively large initial cost investment, a more cumbersome equipment construction, high requirements for water quality during operation, and a low stable production efficiency. Summary of the Invention

[0004] The purpose of the present invention is to provide a stable production method for a cluster well group in tight sandstone, which can solve the problem of low stable production efficiency existing in the current gas production of cluster well groups in tight sandstone.

[0005] In order to achieve the above purpose, the technical solution adopted by the stable production method for the cluster well group in tight sandstone of the present invention is as follows:

[0006] A stable production method for a dense sandstone cluster well group, comprising the following steps: real-time monitoring of the liquid accumulation situation, potential tapping effect parameters, and production data of each gas well in the target cluster well group, then real-time selecting a gas source well and a gas-lifted well from the gas wells, and injecting the produced gas of the gas source well into the gas-lifted well to perform gas-lift liquid drainage on the gas-lifted well; the potential tapping effect parameters include reservoir physical properties, production test data, and flowing pressure test data, the production data includes pressure fluctuation data and production volume fluctuation data; the reservoir physical properties include the average reservoir permeability; the production test data includes the middle flowing pressure and the open flow potential.

[0007] In the stable production method of the dense sandstone cluster well group of the present invention, by real-time selecting a gas source well and a gas-lifted well in the well field, and using the produced gas of the gas source well to perform gas-lift liquid drainage and gas production on the gas-lifted well, on the one hand, the production back pressure of the gas source well can be reduced to achieve the effect of negative pressure gas production, and on the other hand, the produced gas of the gas source well can be used to realize the liquid drainage and gas production of the gas-lifted well. By real-time selecting the gas source well and the gas-lifted well, the working system of alternately replacing the gas source well can be realized, the gas-lift liquid drainage of multiple wells can be realized, and the effect of resuming production and stable production can be achieved. In the stable production method of the dense sandstone cluster well group of the present invention, by utilizing the self-production capacity of each gas well in the well field, the liquid-carrying capacity and the overall production capacity of the well field can be effectively improved, the time for resuming production and stable production of the well field can be extended, and the gas-lift gas source problem can be effectively solved and there is no polluting gas emission.

[0008] Compared with other reservoir physical properties, selecting the average reservoir permeability can provide data support for the selection of the gas source well and the gas-lifted well from the aspects of static key parameters of the reservoir.

[0009] Compared with other production test data, selecting the middle flowing pressure and the open flow potential can provide data support for the selection of the gas source well and the gas-lifted well from the aspects of dynamic key parameters of the reservoir.

[0010] In the present invention, the middle flowing pressure refers to the pressure at the middle of the oil and gas layer measured by a downhole pressure gauge during the normal production of the gas well.

[0011] Preferably, the selection criteria for the gas source well are as follows: the average reservoir permeability is greater than the average value of the reservoir average permeabilities of all gas wells in the target cluster well group, the middle flow pressure is greater than the average value of the middle flow pressures of all gas wells in the target cluster well group, the open flow potential is greater than the average value of the open flow potentials of all gas wells in the target cluster well group, the liquid holdup in the wellbore is small, the flow pressure gradient in the gas well is less than 0.4 MPa / 100 m, the pressure fluctuation data is less than 10%, and the production fluctuation data is less than 10%. The small liquid holdup in the wellbore means that the critical liquid-carrying velocity of the gas well is less than the gas velocity in the wellbore. Preferably, the selection criteria for the gas-lifted well are as follows: the average reservoir permeability is less than the average value of the reservoir average permeabilities of all gas wells in the target cluster well group, or the middle flow pressure is less than the average value of the middle flow pressures of all gas wells in the target cluster well group, or the open flow potential is less than the average value of the open flow potentials of all gas wells in the target cluster well group, or the liquid holdup in the wellbore is large, or the flow pressure gradient in the gas well is not less than 0.4 MPa / 100 m, or the pressure fluctuation data is greater than 10%, or the production fluctuation data is greater than 10%. The large liquid holdup in the wellbore means that the critical liquid-carrying velocity of the gas well is greater than the gas velocity in the wellbore. For tight sandstone cluster well groups, a large amount of production data shows that by using the above selection criteria to select the gas source well and the gas-lifted well, the gas source well and the gas-lifted well can be accurately selected, and the total production and the total stable production time of the well group can be improved.

[0012] When judging the liquid holdup in the wellbore, it can be determined by the critical velocity method or the direct observation method. Preferably, the small liquid holdup in the wellbore means that the critical liquid-carrying velocity of the gas well is less than the gas velocity in the wellbore, the fluctuation of the tubing-casing pressure difference of the gas well is not more than 10%, the fluctuation of the daily gas production of the gas well is not more than 10%, or the fluctuation of the daily liquid production of the gas well is not more than 10%; the large liquid holdup in the wellbore means that the critical liquid-carrying velocity of the gas well is greater than the gas velocity in the wellbore, the fluctuation of the tubing-casing pressure difference of the gas well is greater than 10%, the fluctuation of the daily gas production of the gas well is greater than 10%, or the fluctuation of the daily liquid production of the gas well is greater than 10%. The experimental results show that the critical velocity method has the advantages of simple operation and accurate results. Therefore, the critical velocity method is preferably used in the present invention to determine the liquid holdup in the wellbore.

[0013] In the present invention, the pressure fluctuation data refers to the oil pressure change rate between two adjacent days, and the oil pressure change rate = |M - N| / M × 100%, where M is the oil pressure on the i-th day, N is the oil pressure on the (i + 1)-th day, and i is an integer greater than 0; the production fluctuation data refers to the production change rate between two adjacent days, and the production change rate = |P - Q| / P × 100%, where P is the production on the j-th day, Q is the production on the (j + 1)-th day, and j is an integer greater than 0.

[0014] In order to improve the utilization efficiency of the gas production from the gas source wells and enable the produced gas from the gas source wells to smoothly enter the lifted wells and perform gas lift fluid drainage on the lifted wells, preferably, the stable production method of the tight sandstone cluster well group further includes the following steps: First, separate the gas and liquid from the produced gas of the gas source wells, then pressurize the gas obtained from the gas-liquid separation, and then inject the pressurized gas into the lifted wells.

[0015] In the present invention, injecting the produced gas of the gas source wells into the lifted wells means injecting the produced gas of all the gas source wells into the lifted wells simultaneously, or injecting the produced gas of each gas source well into the lifted wells separately in a certain order.

[0016] In order to shorten the construction time and increase the total gas production, preferably, sort the gas source wells in the order from large to small according to the gas supply sequence index, and then inject the produced gas of each gas source well into the annulus between the tubing and the casing of the lifted wells in the order of the gas source wells; the gas supply sequence index is the middle flow pressure and / or the open flow potential.

[0017] In order to make full use of the produced gas of the gas source wells and maximize the number of lifted wells to be restarted and the gas production, preferably, inject the produced gas of the selected gas source wells into each lifted well separately in sequence to perform gas lift fluid drainage on each lifted well separately. It can be understood that injecting the produced gas of the selected gas source wells into each lifted well separately in sequence to perform gas lift fluid drainage on each lifted well separately means: injecting the produced gas of the selected gas source wells into a certain lifted well first until the liquid accumulation in the lifted well is discharged and the well is restarted, and then injecting it into the next lifted well.

[0018] In order to further optimize the number of lifted wells to be restarted and increase the gas production, preferably, sort the lifted wells in the order from large to small according to the gas injection sequence index, and then inject the produced gas of the gas source wells into the annulus between the tubing and the casing of the lifted wells in the order of the lifted wells; the gas injection sequence index is the middle flow pressure and / or the open flow potential.

[0019] In order to better select and determine the gas source wells and the lifted wells, and facilitate the determination of the construction parameters of the gas source wells and the lifted wells, before performing the gas lift fluid drainage construction, collect the historical gas lift construction data of each gas well in the target cluster well group, and the historical gas lift construction data includes the gas lift duration, the breakthrough pressure, and the gas injection volume. In order to ensure the accuracy of the data, the span of the historical gas lift construction data is more than 1 year. Based on the historical gas lift construction data of a certain gas well, the gas lift construction parameters required for this gas well in subsequent construction can be roughly determined.

[0020] To discharge the liquid accumulation in the gas-lifted well faster and more thoroughly to resume production, preferably, the stable production method for the dense sandstone cluster well group further includes the following steps: after selecting the gas-lifted well, injecting a foam drainage agent into the gas-lifted well, and then injecting the produced gas from the selected gas source well into the gas-lifted well after pressurization to conduct gas-lift liquid drainage for the gas-lifted well.

[0021] It can be understood that in the development of a water-drive gas reservoir, to ensure the stable production of a gas well and avoid liquid accumulation in the wellbore, it is necessary to consider the critical liquid-carrying flow rate and critical liquid-carrying velocity of the gas well. Only when the gas velocity is greater than the critical liquid-carrying velocity of the gas well or the gas flow rate is greater than the critical liquid-carrying flow rate of the gas well can the liquid accumulation in the gas well be carried out by the rising gas flow. Therefore, in the present invention, after conducting gas-lift liquid drainage for the gas-lifted well, to ensure that the gas-lifted well can produce stably by itself, it is necessary to detect the gas velocity or gas flow rate of the gas-lifted well. When the gas velocity in the gas-lifted well is greater than the critical liquid-carrying velocity of the gas-lifted well or the gas flow rate is greater than the critical liquid-carrying flow rate of the gas-lifted well, it can ensure that the gas-lifted well can carry liquid and produce by itself; when the gas velocity in the gas-lifted well is greater than the critical foam-carrying velocity of the gas-lifted well or the gas flow rate is greater than the critical foam-carrying flow rate of the gas-lifted well, it can ensure that the gas-lifted well can carry liquid and produce by itself by injecting a foam drainage agent into the gas-lifted well.

[0022] To increase the stable production time of the gas-lifted well, after the gas-lift liquid drainage of the gas-lifted well is completed, the instantaneous gas velocity of the gas-lifted well is adjusted in real time, so that the instantaneous gas velocity of the gas-lifted well is greater than the critical liquid-carrying velocity to enable the gas-lifted well to carry liquid and produce stably by itself, or the instantaneous gas velocity of the gas-lifted well is greater than the critical foam-carrying velocity to enable the gas-lifted well to carry liquid and produce stably by itself after injecting a foam drainage agent.

[0023] To further increase the stable production time of the gas-lifted well and the total output of the well group, preferably, when the instantaneous gas velocity of the gas-lifted well decreases to be less than the critical liquid-carrying velocity and greater than the critical foam-carrying velocity, a foam drainage agent is injected into the gas-lifted well to ensure that the gas-lifted well can carry liquid and produce by itself.

[0024] In the present invention, if a certain gas-lifted well can produce stably and carry liquid by itself after gas-lift liquid drainage, this gas-lifted well can be used as a gas source well to supply gas for other gas-lifted wells in the well field for gas-lift liquid drainage. BRIEF DESCRIPTION OF THE DRAWINGS

[0025] Figure 1 It is a schematic diagram of the middle flow pressure and open flow potential of 4 gas wells in the cluster well group in the embodiment of the present invention;

[0026] Figure 2 It is a process schematic diagram of the stable production method for the cluster well group in the embodiment of the present invention; Figure 2The reference numerals in the figures are as follows: 1 - the first pipeline; 2 - the gas-liquid separator; 3 - the second pipeline; 4 - the compressor;

[0027] Figure 3 It is a schematic diagram showing the relationship between the total gas production of the cluster well group in the embodiment of the present invention and time. Detailed implementation manners

[0028] The technical solution of the present invention will be further described below in conjunction with specific embodiments.

[0029] Embodiment

[0030] The stable production method of the tight sandstone cluster well group in this embodiment takes a certain tight sandstone cluster well group as an example, and specifically includes the following steps:

[0031] (1) Obtain the liquid accumulation situation, potential tapping effect parameters (the potential tapping effect parameters include reservoir physical properties, production test data, gas well production mode, fracturing stimulation measures and flowing pressure test data), production data (the production data includes pressure fluctuation data and production volume fluctuation data) and historical gas lift construction data (the historical gas lift construction data includes gas lift duration, through-lifting pressure and gas injection volume) of each gas well in the cluster well group, then determine the selection criteria for the gas source wells and the selected criteria for the gas-lifted wells, and select the gas source wells and the gas-lifted wells from the cluster well group according to the determined criteria; in this embodiment, the reservoir physical property is permeability, and the production test data includes the middle flowing pressure and the absolute open flow; the selection criteria for the gas source wells in this embodiment are: the average reservoir permeability is greater than the average value of the reservoir average permeabilities of all gas wells in the target cluster well group, and the middle flowing pressure is greater than the average value of the middle flowing pressures of all gas wells in the target cluster well group, and the absolute open flow is greater than the average value of the absolute open flows of all gas wells in the target cluster well group, and the liquid accumulation amount in the wellbore is small, and the flowing pressure gradient in the gas well is less than 0.4 MPa / 100 m, and the pressure fluctuation data is less than 10%, and the production volume fluctuation data is less than 10%; the selection criteria for the gas-lifted wells are: the average reservoir permeability is less than the average value of the reservoir average permeabilities of all gas wells in the target cluster well group, or the middle flowing pressure is less than the average value of the middle flowing pressures of all gas wells in the target cluster well group, or the absolute open flow is less than the average value of the absolute open flows of all gas wells in the target cluster well group, or the liquid accumulation amount in the wellbore is large, or the flowing pressure gradient in the gas well is not less than 0.4 MPa / 100 m, or the pressure fluctuation data is greater than 10%, or the production volume fluctuation data is greater than 10%;

[0032] In this embodiment, the liquid accumulation situation is determined by the critical flow velocity method. When the test result of the critical flow velocity method shows that the critical liquid-carrying flow velocity of the gas well is less than the gas flow velocity in the wellbore, the liquid accumulation situation is determined to be a small liquid accumulation amount, and the corresponding gas well can be used as a gas source well; when the test result of the critical flow velocity method shows that the critical liquid-carrying flow velocity of the gas well is greater than the gas flow velocity in the wellbore, the liquid accumulation situation is determined to be a large liquid accumulation amount, and the corresponding gas well can be used as a gas-lifted well;

[0033] When the production mode of the gas well is natural flow production or foam drainage gas production for auxiliary production, it indicates that the gas source in the gas well is sufficient, and the gas well can be used as a gas source well; when the fracturing stimulation measure is large-scale sand addition fracturing (large-scale sand addition fracturing means that the single-stage sand addition volume during fracturing is more than 100 cubic meters), the gas well can be used as a gas source well; when the flowing pressure test data shows that the flowing pressure gradient in the gas well is less than 0.4 MPa / 100 m, the gas well can be used as a gas source well;

[0034] According to the pressure fluctuation data and production fluctuation data, it can be judged whether the production situation of the gas well is stable. When the pressure fluctuation data is less than 10%, the corresponding gas well can be used as a gas source well. When the production fluctuation data is less than 10%, the corresponding gas well can be used as a gas source well; when the pressure fluctuation data is greater than 10%, the corresponding gas well can be used as a gas-lifted well. When the production fluctuation data is greater than 10%, the corresponding gas well can be used as a gas-lifted well; according to the historical gas-lifting construction data of a certain gas well, the gas-lifting construction parameters required for the subsequent construction of the gas well can be roughly determined; among them, the pressure fluctuation data refers to the oil pressure change rate between two adjacent days, and the oil pressure change rate = |M - N| / M × 100%, where M is the oil pressure on the i-th day and N is the oil pressure on the (i + 1)-th day; the production fluctuation data refers to the production change rate between two adjacent days, and the production change rate = |P - Q| / P × 100%, where P is the production on the j-th day and Q is the production on the (j + 1)-th day;

[0035] In this embodiment, there are 4 gas wells in the target cluster well group, namely Gas Well 1, Gas Well 2, Gas Well 3, and Gas Well 4. The permeability data of the 4 gas wells are shown in Table 1; the middle flowing pressure and open flow potential of the 4 gas wells are shown in Table 2 and Figure 1 as shown;

[0036] Table 1 Permeability data of 4 gas wells

[0037] Index Gas Well 1 Gas Well 2 Gas Well 3 Gas Lift Well 4 Average Permeability (mD) 0.170 1.420 2.220 0.523 Permeability Range (mD) 0.880 0.950 0.204 1.022 Coefficient of Variation of Permeability 1.059 1.534 1.459 1.283

[0038] Table 2 Middle flowing pressure and open flow potential of 4 gas wells

[0039] Index Gas Well 1 Gas Well 2 Gas Well 3 Gas Lift Well 4 Midpoint Flow Pressure (MPa) 8 22 12 7 <![CDATA[Open flow rate (10 4 m 3 )]]> 2 10 4.8 1.8

[0040] As can be seen from Tables 1 - 2, the average reservoir permeability of Gas Well 2 and Gas Well 3 is greater than the average value of the average reservoir permeability of all gas wells in the target cluster well group, the permeability range is less than 1 mD, the permeability variation coefficient is greater than 1.4, the middle flowing pressure is greater than the average value of the middle flowing pressure of all gas wells in the target cluster well group, the open flow potential is greater than the average value of the open flow potential of all gas wells in the target cluster well group, and the liquid holdup in the wellbore is small (the critical liquid-carrying velocity of the gas well is less than the gas velocity in the wellbore);

[0041] The average reservoir permeability of Gas Well 1 and Gas Well 4 is less than the average of the average reservoir permeabilities of all gas wells in the target cluster well group, the permeability variation coefficient is less than 1.4, the middle flowing pressure is less than the average of the middle flowing pressures of all gas wells in the target cluster well group, the open flow potential is less than the average of the open flow potentials of all gas wells in the target cluster well group, and there is a large amount of liquid accumulation in the wellbore (the critical liquid-carrying velocity of the gas well is greater than the gas velocity in the wellbore).

[0042] In addition, the flowing pressure gradients of Gas Well 1, Gas Well 2, Gas Well 3 and Gas Well 4 are 0.85 MPa / 100 m, 0.32 MPa / 100 m, 0.16 MPa / 100 m and 0.54 MPa / 100 m respectively. Therefore, the flowing pressure gradients of Gas Well 2 and Gas Well 3 are less than 0.4 MPa / 100 m;

[0043] The pressure fluctuation data of Gas Well 1, Gas Well 2, Gas Well 3 and Gas Well 4 are 16%, 4%, 7% and 13% respectively. Therefore, the pressure fluctuation data of Gas Well 2 and Gas Well 3 are less than 10%;

[0044] The production fluctuation data of Gas Well 1, Gas Well 2, Gas Well 3 and Gas Well 4 are 13%, 2%, 5% and 11% respectively. Therefore, the production fluctuation data of Gas Well 2 and Gas Well 3 are less than 10%;

[0045] In summary, according to the selection criteria of the gas source wells, Gas Well 2 and Gas Well 3 are selected as gas source wells, and Gas Well 1 and Gas Well 4 are selected as the gas-lifted wells;

[0046] (2) Connect the first pipeline 1, gas-liquid separator 2, second pipeline 3 and compressor 4 in sequence in the direction of the produced gas from the tubing of Gas Well 2 and Gas Well 3, as Figure 2 shown, and connect the outlet of the compressor 4 to Gas Well 1 and Gas Well 4. Then start the compressor 4, separate the produced gas from Gas Well 2 and Gas Well 3 through gas-liquid separation, and then pressurize the gas obtained from the gas-liquid separation and inject it into the annulus between the tubing and casing of Gas Well 1 to conduct gas-lift drainage for Gas Well 1. After the liquid accumulation in Gas Well 1 is drained, separate the produced gas from Gas Well 2 and Gas Well 3 through gas-liquid separation, and then pressurize the gas obtained from the gas-liquid separation and inject it into the annulus between the tubing and casing of Gas Well 4 to conduct gas-lift drainage for Gas Well 4;

[0047] After the liquid accumulation in Gas Well 1 is drained, the gas velocity in Gas Well 1 is greater than the critical bubble-carrying velocity and less than the critical liquid-carrying velocity. In order to enable Gas Well 1 to achieve self-production, a foam drainage agent is injected into Gas Well 1, and Gas Well 1 achieves self-stable production (resumption of production);

[0048] After the liquid accumulation in Gas Well 4 is drained, the gas velocity in Gas Well 4 is greater than the critical liquid-carrying velocity. Therefore, Gas Well 4 can achieve self-stable production (resumption of production) without using a foam drainage agent;

[0049] After gas wells 1 and 4 resume production, stop pressurizing the produced gas from gas wells 2 and 3, and at the same time stop injecting the produced gas from gas wells 2 and 3 into gas wells 1 and 4; in order to increase the stable production time of gas wells 1 and 4, it is necessary to adjust the instantaneous gas flow rate in gas wells 1 and 4 in real time. The method for adjusting the instantaneous gas flow rate in gas wells 1 and 4 in real time is as follows: According to the pressure, daily gas production, and daily liquid production after gas wells 1 and 4 resume production, calculate the critical liquid-carrying flow rate or critical foam-carrying flow rate of gas wells 1 and 4. Through real-time monitoring of production data, adjust the instantaneous gas flow rate in gas wells 1 and 4 in real time to be greater than the critical liquid-carrying flow rate or critical foam-carrying flow rate to ensure that gas wells 1 and 4 can achieve long-term stable production; when the instantaneous gas flow rate in a gas well is greater than the critical liquid-carrying flow rate, the gas well can be stably produced without adding foam drainage agent into the gas well. When the instantaneous gas flow rate in a gas well is greater than the critical foam-carrying flow rate and less than the critical liquid-carrying flow rate, it is necessary to add foam drainage agent into the gas well to achieve stable production of the gas well. When the instantaneous gas flow rate of a gas well (gas well 4) decreases to be less than the critical liquid-carrying flow rate and greater than the critical foam-carrying flow rate, inject foam drainage agent into the lifted well to ensure that the lifted well can carry liquid by itself for production;

[0050] In this embodiment, since the middle flow pressure of gas well 1 is greater than that of gas well 4, and the open flow potential of gas well 1 is greater than that of gas well 4, therefore, first perform gas lift drainage on gas well 1, and then perform gas lift drainage on gas well 4, which can ensure that gas well 1 enters the stable production period first, thereby increasing the total gas production;

[0051] In this embodiment, since the middle flow pressure of gas well 2 is greater than that of gas well 3, and the open flow potential of gas well 2 is greater than that of gas well 3, therefore, first separate the gas and liquid of the produced gas from gas well 2, pressurize it and then inject it into gas wells 1 and 4, and then separate the gas and liquid of the produced gas from gas well 3, pressurize it and then inject it into gas wells 1 and 4, which can ensure the longest gas supply time of the gas source well, shorten the construction time, and increase the total production time and total gas production;

[0052] (3) Continuously detect the liquid accumulation situation, pressure fluctuation data, and production fluctuation data of gas wells 1, 2, 3, and 4. When there is a lifted well in the cluster well group, select the gas source well according to the method in step (1), and then inject the produced gas of the gas source well into the lifted well for gas lift drainage according to the method in step (2) until the lifted well resumes production. Repeat the above operations to keep the cluster well group in a stable production state.

[0053] Plot the relationship between the total gas production of the cluster well group and time, and the result is as Figure 3 shown, Figure 3Among them, before April is the relationship between the total gas production and time when gas production is carried out without using the method of this embodiment. The solid line after April represents the relationship between the total gas production and time when gas production is carried out using the method of this embodiment. The dotted line after April represents the benchmark gas production, that is, when gas production is carried out without using the method of the present invention, the relationship between the total gas production of 4 wells and time. From Figure 3 It can be seen that after using the method of this embodiment, the gas production increase rate in May compared with that in April reached 4.64 times, and the gas production of the well group from May to November was stable at 500,000 - 600,000 cubic meters, effectively realizing the drainage gas production and stable production and efficiency increase of this cluster well group.

[0054] In order to investigate the influence of the selection criteria of gas source wells in the stable production method of the tight sandstone cluster well group of the present invention on the results, the selection criteria of gas source wells in the method of the embodiment are adjusted to that the average reservoir permeability is greater than the average of the average reservoir permeabilities of all gas wells in the target cluster well group, or the middle flow pressure is greater than the average of the middle flow pressures of all gas wells in the target cluster well group, or the open flow potential is greater than the average of the open flow potentials of all gas wells in the target cluster well group, or the liquid holdup in the wellbore is small, or the flow pressure gradient in the gas well is less than 0.4 MPa / 100 m, or the pressure fluctuation data is less than 10%, or the production fluctuation data is less than 10%. The adjusted method is named Method A. Then, the method of the embodiment and Method A are simultaneously used to carry out gas production on two adjacent tight sandstone cluster gas well groups with similar geological conditions (the number of gas wells in the two cluster gas well groups is the same). The results show that the stable production time corresponding to Method A is less than 50% of the stable production time corresponding to the method of the embodiment, and the total production corresponding to Method A is less than 60% of the total production corresponding to the method of the embodiment.

Claims

1. A stable production method for a cluster well group in tight sandstone, characterized in that, It includes the following steps: Real-time monitor the liquid holdup situation, potential tapping effect parameters and production data of each gas well in the target cluster well group, then select the gas source well and the gas-lifted well from the gas wells in real time, and inject the produced gas of the gas source well into the gas-lifted well to conduct gas-lift liquid drainage for the gas-lifted well; the potential tapping effect parameters include reservoir physical properties, production test data and flowing pressure test data, and the production data includes pressure fluctuation data and production rate fluctuation data; the reservoir physical properties include the average reservoir permeability; the production test data includes the middle flowing pressure and the open flow potential.

2. The stable production method of the dense sandstone cluster well group according to claim 1, characterized in that, The selection criteria for the gas source well are as follows: the average reservoir permeability is greater than the average value of the average reservoir permeabilities of all gas wells in the target cluster well group, the middle flowing pressure is greater than the average value of the middle flowing pressures of all gas wells in the target cluster well group, the open flow potential is greater than the average value of the open flow potentials of all gas wells in the target cluster well group, the liquid holdup in the wellbore is small, the flowing pressure gradient in the gas well is less than 0.4 MPa / 100 m, the pressure fluctuation data is less than 10%, and the production rate fluctuation data is less than 10%. The small liquid holdup in the wellbore means that the critical liquid-carrying velocity of the gas well is less than the gas velocity in the wellbore.

3. The stable production method of the dense sandstone cluster well group according to claim 1, characterized in that The selection criteria for the gas-lifted well are as follows: the average reservoir permeability is less than the average value of the average reservoir permeabilities of all gas wells in the target cluster well group, or the middle flowing pressure is less than the average value of the middle flowing pressures of all gas wells in the target cluster well group, or the open flow potential is less than the average value of the open flow potentials of all gas wells in the target cluster well group, or the liquid holdup in the wellbore is large, or the flowing pressure gradient in the gas well is not less than 0.4 MPa / 100 m, or the pressure fluctuation data is greater than 10%, or the production rate fluctuation data is greater than 10%. The large liquid holdup in the wellbore means that the critical liquid-carrying velocity of the gas well is greater than the gas velocity in the wellbore.

4. The stable production method of the dense sandstone cluster well group according to claim 2 or 3, characterized in that, The pressure fluctuation data refers to the oil pressure change rate between two adjacent days. The oil pressure change rate = |M - N| / M×100%, where M is the oil pressure on the i-th day, N is the oil pressure on the (i + 1)-th day, and i is an integer greater than 0.

5. The stable production method of the dense sandstone cluster well group according to claim 2 or 3, characterized in that, The production rate fluctuation data refers to the production rate change rate between two adjacent days. The production rate change rate = |P - Q| / P×100%, where P is the production rate on the j-th day, Q is the production rate on the (j + 1)-th day, and j is an integer greater than 0.

6. The stable production method of the dense sandstone cluster well group according to any one of claims 1-3, characterized in that, Sort the gas source wells in descending order according to the gas supply sequence index, and then inject the produced gas of each gas source well into the annulus between the tubing and the casing of the gas-lifted well in turn according to the sequence of the gas source wells; the gas supply sequence index is the middle flowing pressure and / or the open flow potential.

7. The stable production method of the dense sandstone cluster well group according to any one of claims 1-3, characterized in that, Inject the produced gas of the selected gas source wells into each gas-lifted well in turn to conduct gas-lift liquid drainage for each gas-lifted well respectively.

8. The stable production method of the dense sandstone cluster well group according to claim 7, characterized in that, Sort the gas-lifted wells in descending order according to the gas injection sequence index, and then inject the produced gas of the gas source well into the annulus between the tubing and the casing of the gas-lifted well in turn according to the sequence of the gas-lifted wells; the gas injection sequence index is the middle flowing pressure and / or the open flow potential.

9. The stable production method of the dense sandstone cluster well group according to any one of claims 1-3, characterized in that, After the gas lift drainage of the well to be gas lifted is completed, the instantaneous gas flow rate of the well to be gas lifted is adjusted in real time, so that the instantaneous gas flow rate of the well to be gas lifted is greater than the critical liquid-carrying flow rate to enable the well to carry liquid by itself and produce stably, or the instantaneous gas flow rate of the well to be gas lifted is greater than the critical bubble-carrying flow rate to enable the well to carry liquid by itself and produce stably after injecting foam drainage agent.

10. The stable production method of the dense sandstone cluster well group according to claim 9, characterized in that, When the instantaneous gas flow rate of the well to be gas lifted decreases to be less than the critical liquid-carrying flow rate and greater than the critical bubble-carrying flow rate, foam drainage agent is injected into the well to be gas lifted to ensure that the well carries liquid by itself.

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