Method, device and equipment for determining production parameters of oil transfer pipe of horizontal well and medium

Abstract

The invention provides a method, a device and equipment for determining production parameters of a horizontal well oil transfer pipe and a medium, and the method for determining the production parameters of the horizontal well oil transfer pipe is realized by determining the diameter of an oil pipe, the time for lowering the oil pipe and the lowering depth of the oil pipe. Comprising the following steps that S1, the oil pipe diameter which considers that friction resistance pressure drop loss approaches to the minimum value and meets the requirement for the liquid-carrying sand discharging effect of the horizontal well is determined; s2, when the wellbore flow state of the horizontal well is changed from stable slug flow to unstable slug flow, determining the time for lowering the oil pipe; s3, determining the oil pipe tripping-in depth which considers the minimum liquid carrying flow of the horizontal well and the optimal production effect; and S4, the obtained oil pipe diameter, the oil pipe descending time and the oil pipe descending depth are configured as production parameters of the horizontal well oil pipe transfer. The problem that parameters are set according to experience in the prior art is solved, field production can be conveniently guided, and the production effect after the shale gas horizontal well is transferred into the oil pipe is effectively improved.

Description

TECHNICAL FIELD

[0001] The present application relates to the field of oil and gas exploitation, in particular to a method for determining production parameters of horizontal well tubing conversion, a device for determining production parameters of horizontal well tubing conversion, and an equipment and a computer readable storage medium for implementing the method for determining production parameters of horizontal well tubing conversion. BACKGROUND

[0002] China is rich in shale gas resources, and the proven reserves account for an increasing proportion of unconventional resources. Efficient development of shale gas is of great significance to improving China's energy structure in the future. At the initial stage of shale gas well production, the formation energy is sufficient, and the flowback fluid volume is large. Therefore, casing production is usually adopted to quickly discharge fracturing fluid in the near wellbore zone and fully release the gas well productivity. However, as the production time prolongs, the formation energy rapidly decays, and the gas well pressure, gas production and liquid production decrease significantly. Moreover, due to the influence of factors such as complex well profile of horizontal section and large size casing liquid carrying capacity, wellbore liquid loading time is advanced, and the gas well relies on casing stable flow production is restricted.

[0003] In order to solve the above problems of gas well, shale gas well tubing conversion production is currently used at home and abroad to improve the wellbore liquid carrying capacity and ensure the continuous development of gas well productivity. Shale gas well tubing conversion production mainly uses a pressure operating machine to lower a production tubing with a suitable size, and then converts to tubing production through the annulus. Although gas well tubing conversion production is an effective measure to ensure the continuous and stable production of shale gas well, the following problems still exist in this process: first, there is no unified method for optimizing the production parameters of shale gas well tubing conversion in China's major shale gas fields, and the relevant parameter calculation standard is not clear. In the actual production process, subjective experience is still used to guide practice; second, under different wellhead pressures, tubing depths, tubing sizes and wellbore corrosion prevention conditions, there are certain differences in the production conditions after gas well tubing conversion. The production of some gas wells increases after tubing conversion, and the liquid discharge effect is better. The production of some gas wells is difficult after tubing conversion, and the gas lift re-production effect is not good and the well is not alive after opening. Even the phenomenon of wellbore throttling occurs. SUMMARY

[0004] The present application aims to solve at least one of the above-mentioned deficiencies in the prior art. For example, one of the objectives of the present application is to provide a method for determining the optimal production parameters of horizontal well tubing conversion according to the geological conditions and production conditions of different blocks.

[0005] To achieve the above-mentioned objectives, the present application provides a method for determining the production parameters of horizontal well tubing conversion.

[0006] The method for determining the production parameters of horizontal well tubing conversion is achieved by determining the tubing diameter, tubing lowering time and tubing lowering depth, and includes the following steps:

[0007] S1. Determine the tubing diameter that takes into account the frictional pressure drop loss approaching the minimum value and meets the requirements of the horizontal well for fluid-carrying sand removal effect.

[0008] S2. When the flow state in the horizontal well changes from a stable slug flow to an unstable slug flow, the timing for running tubing is determined.

[0009] S3. Determine the tubing insertion depth that minimizes the fluid carrying capacity of the horizontal well and maximizes production efficiency.

[0010] S4. Configure the obtained tubing diameter, tubing running timing, and tubing running depth as the production parameters for the horizontal well tubing transfer.

[0011] In an exemplary embodiment of the method for determining production parameters of horizontal well tubing according to the present invention, in step S1, the frictional pressure drop can be determined based on a gas-liquid two-phase flow model, wherein the gas-liquid two-phase flow model can be:

[0012]

[0013] In equation (1), p is the average absolute pressure of the pipe, MPa; z is the axial distance of the flow, m; ρ l ρ g Liquid phase density, gas phase density, kg / m³ 3 ;ρ n Density of a non-slipping gas-liquid mixture, kg / m³ 3 H l The liquid holdup is the liquid holding ratio; g is the acceleration due to gravity, m / s². 2 θ is the angle between the pipeline and the horizontal direction, in degrees; λ is the friction factor, a dimensionless quantity; v m v is the average flow velocity of the mixture, in m / s; sg denoted as apparent gas velocity (m / s); D is the tubing diameter (m).

[0014] In an exemplary embodiment of the method for determining production parameters of horizontal well tubing according to the present invention, in step S2, the wellbore flow pattern of the horizontal well can be identified using a wellbore flow pattern identification model, wherein the wellbore flow pattern identification model may include a vertical section flow pattern identification model, an inclined section flow pattern identification model, and a horizontal section flow pattern identification model.

[0015] In an exemplary embodiment of the method for determining production parameters of horizontal well tubing according to the present invention, the vertical section flow regime identification model may be:

[0016]

[0017] In equation (2) above, N vg v is the gas phase velocity standard number; sgis the superficial gas velocity, m / s; N vl is the liquid phase velocity parameter; v sl is the superficial liquid velocity, m / s; σ is the surface tension of the liquid phase, N / m; ρ l is the density of the liquid phase, kg / m 3 ; g is the acceleration of gravity, m / s 2 .

[0018] The inclined section flow regime identification model can be:

[0019]

[0020] In the above formula (3), v SG is the gas phase superficial velocity, m / s; v SL is the liquid phase superficial velocity, m / s; g is the acceleration of gravity, m / s 2 ; σ is the interfacial tension, N / m; ρ g , ρ L are the gas density and liquid density, respectively, kg / m 3 ; θ is the inclination angle, °.

[0021] The horizontal section flow regime identification model can be:

[0022] V SL = α( V SG ) formula (4)

[0023] In the above formula (4), v SL is the liquid phase superficial velocity, m / s; v SG is the gas phase superficial velocity, m / s; α is a dimensionless factor.

[0024] In an exemplary embodiment of the method for determining the production parameters of the horizontal well tubing-conversion, the step S2 further comprises: the control variable method can be adopted to compare and analyze the well depth, wellhead pressure, platform pressure transmission or well type to adjust the tubing-conversion timing.

[0025] In an exemplary embodiment of the method for determining the production parameters of the horizontal well tubing-conversion, the adjustment of the tubing-conversion timing can further comprise:

[0026] When the well depth is 3000-4000 m, the tubing-conversion timing can be considered to be advanced; when the well depth is greater than 4000 m, if the well opening pressure is less than 14 Mpa and the pressure-control production requirement exists, the tubing-conversion timing can be considered to be advanced, otherwise, the tubing-conversion timing can be considered to be delayed.

[0027] When the difference between the platform delivery pressure and the wellhead pressure is higher than 1-2 MPa, the tubing running time can be considered to be advanced; when the platform delivery pressure is stable and the difference is lower than 1-2 MPa, the tubing running time can be considered to be delayed.

[0028] When the horizontal well is an up-dip well, the tubing running time can be considered to be delayed, and if the oil casing pressure difference continuously increases and the production decreases, the tubing production can be considered; when the horizontal well is a down-dip well, the tubing running time can be considered to be advanced.

[0029] In an exemplary embodiment of the method for determining the production parameters of the horizontal well tubing conversion, the step S3 further comprises:

[0030] When the well type is identified as an up-dip well, the tubing running depth can be located in the deviation range of the inclined well section or the first target point, and the deviation range can be determined according to the wellbore liquid volume.

[0031] When the well type is identified as a down-dip well, the tubing running depth can be located at 1 / 3-1 / 2 of the horizontal section starting point to the end point.

[0032] Another aspect of the present application provides a device for determining the production parameters of the horizontal well tubing conversion. The device for determining the production parameters of the horizontal well tubing conversion comprises a tubing diameter determination module, a tubing running time determination module, a tubing running depth determination module and a production parameter configuration module of the horizontal well tubing conversion.

[0033] The tubing diameter determination module is connected to the production parameter configuration module of the horizontal well tubing conversion and is configured to determine the tubing diameter that approaches the minimum value considering the friction pressure drop loss and meets the liquid-carrying sand-removal effect requirement of the horizontal well.

[0034] The tubing running time determination module is connected to the production parameter configuration module of the horizontal well tubing conversion and is configured to determine the tubing running time when the wellbore flow state of the horizontal well changes from stable plug flow to unstable plug flow.

[0035] The tubing running depth determination module is connected to the production parameter configuration module of the horizontal well tubing conversion and is configured to determine the tubing running depth that minimizes the liquid-carrying flow rate of the horizontal well and optimizes the production effect.

[0036] The production parameter configuration module of the horizontal well tubing conversion is connected to the tubing diameter determination module, the tubing running time determination module and the tubing running depth determination module respectively and is configured to configure the obtained tubing diameter, tubing running time and tubing running depth as the production parameters of the horizontal well tubing conversion.

[0037] Another aspect of the present application provides a computer device, which comprises:

[0038] The processor; a memory, which stores a computer program, when the computer program is executed by the processor, realizes the horizontal well tubing conversion production parameter determination method as described above.

[0039] Still another aspect of the present application provides a computer readable storage medium which stores a computer program, when the computer program is executed by the processor, realizes the horizontal well tubing conversion production parameter determination method as described above.

[0040] Compared with the prior art, the beneficial effects of the present application include:

[0041] The horizontal well tubing conversion production parameter determination method solves the problem of setting parameters by experience in the past, and effectively improves the production effect of the shale gas horizontal well after tubing conversion, by combining theoretical research calculation, relevant experimental simulation and field production cases, and setting specific quantitative parameters according to block, production condition, single well depth, wellbore pressure drop and tubing size and other factors. BRIEF DESCRIPTION OF DRAWINGS

[0042] The above and other objects and / or characteristics of the present application will become more apparent by describing in detail the present application with reference to the attached drawings, wherein:

[0043] Figure 1 A flowchart of an exemplary embodiment of the horizontal well tubing conversion production parameter determination method of the present application is shown.

[0044] Figure 2 A device connection diagram of an exemplary embodiment of the horizontal well tubing conversion production parameter determination method of the present application is shown.

[0045] Figure 3 A design flowchart of an embodiment of the horizontal well tubing conversion production parameter determination method of the present application is shown.

[0046] Figure 4 A vertical section flow pattern identification result diagram of an embodiment of the horizontal well tubing conversion production parameter determination method of the present application is shown.

[0047] Figure 5 A tilted section flow pattern identification result diagram of an embodiment of the horizontal well tubing conversion production parameter determination method of the present application is shown.

[0048] Figure 6 A horizontal section flow pattern identification result diagram of an embodiment of the horizontal well tubing conversion production parameter determination method of the present application is shown.

[0049] BRIEF DESCRIPTION OF DRAWINGS

[0050] 100 - tubing diameter determination module; 110 - tubing running opportunity determination module; 120 - tubing running depth determination module; 130 - production parameter configuration module for horizontal well tubing running. DETAILED DESCRIPTION

[0051] Hereinafter, the horizontal well tubing running production parameter determination method, device, equipment and medium of the present application will be described in detail in conjunction with exemplary embodiments.

[0052] It should be noted that "first", "second", "third" and the like are merely for the convenience of description and differentiation, and cannot be understood as indicating or implying relative importance. "S1", "S2", "S3" and the like are used to distinguish similar objects, and do not necessarily describe a specific order or sequence. "Up", "down", "front", "back", "left", "right", "inside", "outside" and the like are merely for the convenience of description and constitute relative positional relationships, and do not indicate or imply that the components referred to must have the specific orientation or position.

[0053] At present, there is no unified method for optimizing the process parameters of shale gas well tubing running in China's major shale gas fields. This is mainly due to the complexity, diversity of shale gas reservoirs and the difference in production conditions. Differences in geological conditions, mining technology, equipment configuration and other aspects of different gas fields make it difficult to develop a unified optimization method applicable to all gas fields. At the same time, the calculation standards of related parameters are not clear, such as the setting and optimization of tubing size, running depth, wellhead pressure and other parameters, which are mostly dependent on subjective experience and field tests. This leads to a lack of scientific basis and unified standards in the setting and adjustment of parameters in actual production. In the absence of a unified method and clear standards, parameter optimization in actual production relies heavily on the subjective experience of technical personnel and the actual situation on site. This approach, while having some flexibility, can also lead to unstable production efficiency and increased production costs.

[0054] To address the above problems, the inventors have proposed a horizontal well tubing running production parameter determination method that can determine the most suitable tubing running production parameters for different geological conditions and production conditions, providing an effective technical means to ensure the sustained and stable performance of shale gas wells.

[0055] To achieve the above purpose, the present application provides, in one aspect, a horizontal well tubing running production parameter determination method.

[0056] Exemplary Embodiment 1

[0057] In this exemplary embodiment, a horizontal well tubing running production parameter determination method is provided, which is realized by determining the tubing diameter, tubing running opportunity and tubing running depth, as shown in Figure 1 the figure, comprising the following steps:

[0058] S1. Determine the tubing diameter that takes into account the frictional pressure drop loss approaching the minimum value and meets the requirements of fluid-carrying sand removal effect in horizontal wells.

[0059] S11, Frictional pressure drop can be determined based on the gas-liquid two-phase flow model, which can be:

[0060]

[0061] In equation (1), p is the average absolute pressure of the pipe, MPa; z is the axial distance of the flow, m; ρ l ρ g Liquid phase density, gas phase density, kg / m³ 3 ;ρ n Density of a non-slipping gas-liquid mixture, kg / m³ 3 H l The liquid holdup is the liquid holding ratio; g is the acceleration due to gravity, m / s². 2 θ is the angle between the pipeline and the horizontal direction, in degrees; λ is the friction factor, a dimensionless quantity; v m v is the average flow velocity of the mixture, in m / s; sg denoted as apparent gas velocity (m / s); D is the tubing diameter (m).

[0062] S2. When the flow state in a horizontal well changes from a stable slug flow to an unstable slug flow, it is determined to be the time to run tubing.

[0063] S21. The wellbore flow pattern of a horizontal well can be identified using a wellbore flow pattern identification model, wherein the wellbore flow pattern identification model may include a vertical section flow pattern identification model, an inclined section flow pattern identification model, and a horizontal section flow pattern identification model.

[0064] Alternatively, the vertical segment flow pattern identification model can be:

[0065]

[0066] In equation (2) above, N vg v is the gas phase velocity standard number; sg The apparent airflow velocity is in m / s; N vl v is the liquid phase velocity number; sl ρ is the apparent liquid velocity, m / s; σ is the surface tension of the liquid phase, N / m; l The density of the liquid phase is kg / m³. 3 g is the acceleration due to gravity, in m / s². 2 .

[0067] The flow regime identification model for the inclined section can be:

[0068]

[0069] In the above formula (3), v SG is the gas phase superficial velocity, m / s; v SL is the liquid phase superficial velocity, m / s; g is the gravitational acceleration, m / s 2 ; σ is the interfacial tension, N / m; ρ g , ρ L are the gas and liquid densities, kg / m 3 ; θ is the inclination angle, °.

[0070] The horizontal section flow regime identification model can be:

[0071] V SL = α( V SG ) formula (4)

[0072] In the above formula (4), v SL is the liquid phase superficial velocity, m / s; v SG is the gas phase superficial velocity, m / s; α is a dimensionless factor.

[0073] S22, the control variable method can be adopted to compare and analyze the well depth, wellhead pressure, platform pressure transmission or well type to adjust the tubing running time.

[0074] S221, adjusting the tubing running time can further include: when the well depth is 3000-4000 m, the tubing running time can be considered to be advanced; when the well depth is greater than 4000 m, if the well opening pressure is less than 14 Mpa and there is a pressure control production demand, the tubing running time can be considered to be advanced, otherwise, the tubing running time can be considered to be delayed.

[0075] When the difference between the platform pressure transmission and the wellhead pressure is higher than 1-2 Mpa, the tubing running time can be considered to be advanced; when the platform pressure transmission is stable and the difference is lower than 1-2 Mpa, the tubing running time can be considered to be delayed.

[0076] When the horizontal well is an upward inclined well, the tubing running time can be considered to be delayed, if the oil casing pressure difference continues to increase and the production decreases, the tubing production is considered; when the horizontal well is a downward inclined well, the tubing running time can be considered to be advanced.

[0077] S3, the tubing running depth considering the minimum liquid carrying capacity of the horizontal well and the best production effect is determined.

[0078] S31, when the well type is identified as an upward inclined well, the tubing running depth can be located in the deviation range of the inclined well section or the first target point, and the deviation range can be determined according to the wellbore liquid volume; when the well type is identified as a downward inclined well, the tubing running depth can be located at 1 / 3-1 / 2 of the horizontal section starting point to its end point.

[0079] S4, the obtained tubing diameter, tubing running time and tubing running depth are configured as the production parameters of the horizontal well tubing conversion.

[0080] Example Embodiment 2

[0081] In the present example embodiment, a horizontal well tubing conversion production parameter determination apparatus is provided, as shown in the accompanying drawings, comprising a tubing diameter determination module 100, a tubing running timing determination module 110, a tubing running depth determination module 120, and a horizontal well tubing conversion production parameter configuration module 130. Figure 2 The tubing diameter determination module 100 is connected to the horizontal well tubing conversion production parameter configuration module 130 and is configured to determine a tubing diameter that considers the frictional pressure drop loss approaching a minimum value and meets the liquid-carrying and sand-removing effect requirements of the horizontal well.

[0082] The tubing running timing determination module 110 is connected to the horizontal well tubing conversion production parameter configuration module 130 and is configured to determine the tubing running timing when the wellbore flow regime of the horizontal well changes from stable plug flow to unstable plug flow.

[0083] The tubing running depth determination module 120 is connected to the horizontal well tubing conversion production parameter configuration module 130 and is configured to determine a tubing running depth that considers the minimum liquid-carrying flow rate and the best production effect of the horizontal well.

[0084] The tubing running depth determination module 120 is connected to the horizontal well tubing conversion production parameter configuration module 130 and is configured to determine a tubing running depth that considers the minimum liquid-carrying flow rate and the best production effect of the horizontal well.

[0085] The horizontal well tubing conversion production parameter configuration module 130 is connected to the tubing diameter determination module 100, the tubing running timing determination module 110, and the tubing running depth determination module 120, respectively, and is configured to configure the obtained tubing diameter, tubing running timing, and tubing running depth as the production parameters of the horizontal well tubing conversion.

[0086] Example Embodiment 3

[0087] In the present example embodiment, a computer device is also provided. The computer device comprises a processor and a memory. The memory is used to store a computer program. The computer program is executed by the processor to cause the processor to execute the computer program according to the horizontal well tubing conversion production parameter determination method of the example embodiment 1.

[0088] Example Embodiment 4

[0089] In the present exemplary embodiment, a computer-readable storage medium storing a computer program is also provided. The computer-readable storage medium stores a computer program which, when executed by a processor, causes the processor to perform the method for determining production parameters of a horizontal well tubing conversion according to the exemplary embodiment 1. The computer-readable recording medium is any data storage device that can store data read by a computer system. Examples of the computer-readable recording medium include a read-only memory, a random access memory, a read-only optical disc, a magnetic tape, a floppy disc, an optical data storage device, and a carrier wave such as data transmission through an Internet via a wired or wireless transmission path.

[0090] In order to better understand the above exemplary embodiments of the present application, the following further illustrates them in connection with specific embodiments and drawings, but the examples are not limiting to the present application.

[0091] Embodiment 1

[0092] The present embodiment is a shale gas block in area A Actual gas well tubing conversion production case, the process is as shown in Figure 3 The determination of the production parameters of the horizontal well tubing conversion of the present embodiment is realized by the following steps:

[0093] S1, based on the requirement of minimum friction loss and full development of gas well productivity, the best tubing size is determined: the reasonable tubing diameter is selected by comprehensively considering the tubing pressure drop, friction loss, liquid carrying capacity and erosion resistance and other factors.

[0094] A gas-liquid two-phase flow model is established to calculate the wellbore pressure distribution, and the gas-liquid two-phase flow model is:

[0095]

[0096] In formula (5), p is the average absolute pressure of the pipeline, MPa; z is the axial distance of flow, m; p l , p g is the liquid density, the gas density, kg / m 3 ; p n is the no-slip gas-liquid mixture density, kg / m 3 ; H l is the liquid holdup; g is the acceleration of gravity, m / s 2 ; θ is the angle between the pipeline and the horizontal direction, degree; λ is the friction resistance coefficient, dimensionless; v m is the average flow velocity of the mixture, m / s; v sg is the apparent flow velocity of the gas phase, m / s; D is the tubing diameter, m.

[0097] The wellbore pressure drop under different tubing diameters can be determined using a gas-liquid two-phase flow model. Larger tubing diameters result in lower tubing friction pressure drop losses, thus maximizing gas well productivity. However, as the tubing inner diameter gradually increases, the rate of decrease in pressure drop friction losses with increasing inner diameter tends to level off. Further increasing the tubing inner diameter has little effect on increasing production or reducing friction pressure drop losses. The suitable range for friction pressure drop losses in gas well production tubing under different production conditions is generally 0.1–0.3 MPa / d. Choosing too small a tubing inner diameter will limit gas well productivity and hinder efficient gas well development. Furthermore, under the same wellhead flowing pressure and formation pressure conditions, the ratio of wellhead gas velocity to erosion rate decreases with increasing tubing diameter. Whether the tubing diameter meets the objective criteria for wellbore fluid and sand removal depends primarily on specific conditions such as tubing size and formation parameters, including tubing inner diameter, wellbore diameter, fluid viscosity, and sand particle size. The evaluation standard is typically based on whether the tubing diameter allows for the smooth passage of fluid and sand particles without causing wellbore damage or blockage. Currently, tubing diameters meeting these requirements are generally between 50 and 75 mm, but adjustments can be made based on different formation conditions. Therefore, selecting a tubing diameter that minimizes frictional pressure drop and achieves optimal wellbore fluid and sand removal is the best tubing size based on minimizing frictional loss and maximizing production capacity.

[0098] S2. Determine the most suitable time to run tubing based on improving gas well production: By combining the wellbore flow regime change law and pressure gradient change trend of gas well casing at different production stages, when the wellbore flow regime changes from stable slug flow to unstable slug flow, it is the more suitable time to run tubing. Therefore, it is necessary to accurately identify the wellbore flow regime.

[0099] More specifically, the wellbore flow regime can be identified based on flow regime identification models for the vertical section, inclined section, and horizontal section. The identification results are as follows: Figures 4 to 6 As shown, where, Figure 4 The image shows the flow pattern identification results for the vertical section, with the horizontal axis Nvg representing the gas phase velocity standard and the vertical axis Nvl representing the liquid phase velocity standard. Figure 5 This is a diagram showing the flow pattern recognition results for the inclined segment, with its horizontal axis V. sg V represents the apparent velocity of the gas phase, in m / s, with the vertical axis being V. sl The apparent flow rate of the liquid phase is m / s; Figure 6 This is a diagram showing the flow pattern recognition results for the horizontal segment, with its horizontal axis V. sg V represents the apparent velocity of the gas phase, in m / s, with the vertical axis being V. sl ρ is the apparent flow rate of the liquid phase, in m / s.

[0100] The vertical segment flow pattern identification model can be:

[0101]

[0102] In equation (6) above, Nvg is the gas phase velocity number; v sg is the superficial gas velocity, m / s; N vl is the liquid phase velocity number; v sl is the superficial liquid velocity, m / s; σ is the surface tension of the liquid phase, N / m; ρ l is the density of the liquid phase, kg / m 3 ; g is the acceleration of gravity, m / s 2 .

[0103] The inclined section flow regime identification model can be:

[0104]

[0105] In the above formula (7), v SG is the gas phase superficial velocity, m / s; v SL is the liquid phase superficial velocity, m / s; g is the acceleration of gravity, m / s 2 ; σ is the interfacial tension, N / m; ρ g , ρ L are the gas density and liquid density, respectively, kg / m 3 ; θ is the inclination angle, °.

[0106] The horizontal section flow regime identification model can be:

[0107] V SL = α( V SG ) Formula (8)

[0108] In the above formula (8), v SL is the liquid phase superficial velocity, m / s; v SG is the gas phase superficial velocity, m / s; α is a dimensionless factor.

[0109] Further, after the wellbore flow regime is identified, various factors such as block distribution, wellhead pressure, platform pressure transmission, and wellbore corrosion can be considered to determine the most appropriate tubing running time, so as to effectively improve the production of shale gas wells.

[0110] More specifically, the most appropriate tubing running time can be obtained by comparative analysis through the control variable method, which can include:

[0111] ①Consider the factors of block distribution: Because the friction loss of the block with deep well depth increases greatly after tubing change, the delay tubing time is more conducive to the production of gas well with liquid. For the block with deep well depth, low opening well pressure and pressure control production, the early tubing time can prevent the liquid accumulation caused by the high critical liquid-carrying flow rate of annular production. The friction loss of the block with shallow well depth increases relatively small, so the tubing time can be appropriately advanced. Generally, the opening well pressure of gas well greater than or equal to 18 MPa belongs to high pressure range, and the pressure in the range of 14 MPa to 18 MPa belongs to medium range, and the rest belongs to low pressure range. Pressure control production means that in order to ensure the continuous production of gas well, the size of oil nozzle or the opening degree of needle valve is usually optimized to be not too large, so that the pressure of gas well can be kept in a high range for a long time or the pressure drop rate and production decline rate are reduced, so as to achieve long-term stable production and full play of production capacity. The specific early or delayed tubing time can be determined according to the production situation of gas well.

[0112] More specifically, by taking comparative analysis by control variable method, it can be concluded that:

[0113] The suitable tubing time for the block with shallow well depth (3000-4000m): the pressure of gas well is 10-15 MPa, and the daily gas production is 60-100 thousand square meters.

[0114] The suitable tubing time for the block with deep well depth (>4000m): the pressure of gas well is 8-12 MPa, and the daily production is 50-70 thousand square meters.

[0115] The suitable tubing time for the block with deep well depth (>4000m) and pressure control production: the pressure of gas well is higher than 15 MPa, and the daily production is less than 100 thousand square meters.

[0116] ②Consider the factors of platform pressure transmission: the production of gas well with high pressure transmission platform is prone to liquid accumulation, so the tubing time can be advanced to maintain high pressure and high instantaneous production of gas well. The production pressure difference of gas well with low pressure transmission platform is large, and it is not easy to accumulate liquid, so the tubing time can be delayed to fully play the advantage of casing production with liquid.

[0117] More specifically, the difference between platform pressure transmission and wellhead pressure of gas well can be used to determine whether the platform pressure transmission is conducive to the production of gas well. If the platform pressure transmission gradually rises to more than 1-2 MPa higher than the wellhead pressure of gas well, the gas well is prone to liquid accumulation and poor production condition if it continues to use oil casing annular production, so the tubing time can be advanced. If the platform pressure transmission is relatively stable and 1-2 MPa lower than the wellhead pressure of gas well, the oil casing annular production of gas well is relatively stable and not prone to liquid accumulation, so the tubing time can be delayed. If the platform pressure transmission gradually rises to close to or exceed the wellhead pressure, the tubing time can be considered to be advanced in time to prevent the production of gas well from liquid accumulation or flow interruption due to high back pressure.

[0118] ③Consider the different well type factors:

[0119] When it is an up-dip well, the liquid of the up-dip well is mainly concentrated near the A target point (the first endpoint of the well trajectory, which is the first target point reached according to the predetermined plan, and is usually the starting point of the horizontal section of the horizontal well), and is more likely to carry liquid than the down-dip well, and the production is more stable, and the frequency of liquid loading and flow interruption is lower, so when the oil casing pressure difference of the up-dip well is small and the production is stable, the tubing can be temporarily not produced, and the tubing conversion time can be appropriately delayed. The casing production in the early stage is more conducive to liquid carrying, and when the oil casing pressure difference continues to increase and the production decreases significantly, the tubing production is considered in time.

[0120] When it is a down-dip well, the liquid of the down-dip well is mainly concentrated near the B target point (the second endpoint of the well trajectory, which is usually reached after the A target point and is located at the end of the horizontal section of the horizontal well), and the wellbore is prone to liquid loading. When the down-dip well has an increased oil casing pressure difference, liquid loading and flow interruption occur frequently, and the tubing conversion time is considered to be advanced. Tubing production can more stably carry liquid.

[0121] ④Consider the corrosion of the wellbore: Currently, the downhole tubing mainly has internal coating corrosion protection, and the annulus production time is too long (>4 months), which can easily lead to corrosion and perforation of the outside of the tubing, affecting the normal production of the gas well, so it is necessary to strictly control the tubing to be converted to tubing production in a short time (<4 months) after being lowered.

[0122] S3, based on improving the liquid carrying effect and keeping the wellbore unblocked to determine the best tubing depth: Considering the influence of multiple factors such as wellbore liquid carrying, pipe string stress, wellbore pressure drop and friction, and the risk of wellbore sand plug, the production situation of shale gas horizontal wells with different tubing depths can be summarized by analyzing the gas-water flow test results: With the increase of the depth of the smaller tubing, the position is closer to the B target point, the friction and pressure drop are larger, and when the position is near the A target point (such as 30-50m, the specific distance can be adjusted according to the liquid volume of the wellbore of the gas well), the position range is between 67° and 88°, and the wellbore pressure drop is the smallest.

[0123] The liquid carrying flow of the down-dip well is smaller than that of the up-dip well, and the liquid carrying flow of the down-dip well is the smallest when the tubing is lowered into the horizontal section 1 / 3-1 / 2, and the production effect is the best.

[0124] The liquid carrying flow of the up-dip well tubing lowered into the deviated well section or near the A target point (such as 30-50m, the specific distance can be adjusted according to the liquid volume of the wellbore of the gas well) is the smallest, and the production effect is the best. The cumulative gas production of the up-dip well is significantly greater than that of the down-dip well.

[0125] S4, configure the obtained optimal tubing size, the most suitable tubing switchover time, the optimal tubing depth and the annulus production time after the tubing is run into as the production parameters of the tubing switchover of the horizontal well.

[0126] In summary, the method for determining the tubing switchover production parameter of the shale gas horizontal well has the preferred standard, that is, under the determination of the reservoir and the gas well production characteristics, the optimal parameter selection method that meets the better production effect after the tubing switchover of the shale gas well, that is, the optimal parameter configuration composed of the optimal tubing size based on the minimum friction loss and the full development of the production capacity, the most suitable tubing switchover time based on the improvement of the production effect of the gas well and the optimal tubing depth based on the improvement of the liquid carrying effect and the unobstructed wellbore.

[0127] Although the present application has been described in connection with the exemplary embodiments and the accompanying drawings, it will be apparent to those skilled in the art that various modifications can be made to the embodiments without departing from the spirit and scope of the claims.

Claims

1. A method for determining production parameters for a horizontal well tubing conversion, characterized in that, The method for determining the production parameters of the horizontal well tubing conversion comprises the following steps: S1, determining the tubing diameter which considers the frictional pressure drop loss tending to be minimum and meets the liquid-carrying sand washing effect requirement of the horizontal well; S2, determining the tubing running time when the wellbore flow state of the horizontal well changes from stable slug flow to unstable slug flow; S3, determining the tubing running depth which considers the minimum liquid-carrying flow rate and the best production effect of the horizontal well; and S4, configuring the obtained tubing diameter, tubing running time and tubing running depth as the production parameters of the horizontal well tubing conversion.

2. The method of determining production parameters for a horizontal well tubing changeover according to claim 1, wherein, In the step S1, the frictional pressure drop is determined according to a gas-liquid two-phase flow model, and the gas-liquid two-phase flow model is as follows: In formula (1), p is the average absolute pressure of the pipeline, MPa; z is the axial distance of the flow, m; p l , p g is the liquid phase density, the gas phase density, kg / m 3 ; p n ρ 3 ; H l ; g 2 ; θ λ is the friction factor, dimensionless; v m is the average flow velocity of the mixture, m / s;v sg is the superficial gas velocity, m / s; D is the pipe diameter, m.

3. The method of determining production parameters for a horizontal well tubing conversion according to claim 1, wherein, In the step S2, the wellbore flow state of the horizontal well is identified by using a wellbore flow state identification model, wherein the wellbore flow state identification model comprises a vertical section flow state identification model, an inclined section flow state identification model and a horizontal section flow state identification model.

4. The method of determining production parameters for a horizontal well tubing conversion of claim 3, wherein, The vertical section flow state identification model is as follows: In the above formula (2), N vg is the gas phase Froude number; v sg is the superficial gas velocity, m / s; N vl is the liquid phase Froude number; v sl is the superficial liquid velocity, m / s; σ is the surface tension of the liquid phase, N / m; p l is the density of the liquid phase, kg / m 3 ; g is the acceleration due to gravity, m / s 2 ; The inclined section flow state identification model is as follows: In the above formula (3), v SG is the gas phase superficial velocity, m / s; v SL is the liquid phase superficial velocity, m / s; g is the acceleration of gravity, m / s 2 ; σ is the interfacial tension, N / m; p g , p L are the gas and liquid densities, respectively, kg / m 3 ; θ is the inclination angle, °; The horizontal section flow state identification model is as follows: V SL = a(V SG ) Equation (4) In the above formula (4), v SL is the liquid phase superficial velocity, m / s; v SG is the gas phase superficial velocity, m / s; and a is a dimensionless factor.

5. The method of determining production parameters for a horizontal well tubing conversion of claim 1, wherein, The step S2 further comprises: adopting a control variable method to compare and analyze the well depth, well opening pressure, gas well pressure, pressure control production requirement, platform pressure transmission or well type of the horizontal well to adjust the tubing running time.

6. The method of determining production parameters for a horizontal well tubing conversion of claim 5, wherein, The adjustment of the tubing running time further comprises: when the well depth is 3000-4000 m, the tubing running time is considered to be advanced; when the well depth is greater than 4000 m, if the well opening pressure is less than 14 Mpa and the pressure control production requirement is met, the tubing running time is considered to be advanced, otherwise, the tubing running time is considered to be delayed; when the difference between the platform pressure transmission and the wellhead pressure is higher than 1-2 Mpa, the tubing running time is considered to be advanced; when the platform pressure transmission is stable and the difference is lower than 1-2 Mpa, the tubing running time is considered to be delayed; when the horizontal well is an upward inclined well, the tubing running time is considered to be delayed, and if the oil casing pressure difference continuously increases and the production decreases, the tubing conversion production is considered; when the horizontal well is a downward inclined well, the tubing running time is considered to be advanced.

7. The method of horizontal well tubing conversion production parameter determination of claim 1, wherein, The step S3 further comprises: when the well type is identified as an upward inclined well, the tubing running depth is located in the deviation range of the inclined well section or the first target point, and the deviation range is determined according to the liquid volume of the wellbore; when the well type is identified as a downward inclined well, the tubing running depth is located at 1 / 3-1 / 2 of the horizontal section starting point to the end point.

8. A horizontal well swabbing production parameter determination device, characterized in that, The device for determining the production parameters of the horizontal well tubing conversion comprises a tubing diameter determination module, a tubing running time determination module, a tubing running depth determination module and a production parameter configuration module, wherein the tubing diameter determination module is connected with the production parameter configuration module and is configured to determine the tubing diameter which considers the frictional pressure drop loss tending to be minimum and meets the liquid-carrying sand washing effect requirement of the horizontal well; The tubing running time determination module is connected with the production parameter configuration module of the horizontal well tubing running, and is configured to determine the tubing running time when the wellbore flow state of the horizontal well changes from stable slug flow to unstable slug flow; The tubing running depth determination module is connected with the production parameter configuration module of the horizontal well tubing running, and is configured to determine the tubing running depth considering the minimum liquid carrying flow rate and the best production effect of the horizontal well; The production parameter configuration module of the horizontal well tubing running is connected with the tubing diameter determination module, the tubing running time determination module and the tubing running depth determination module, and is configured to configure the obtained tubing diameter, tubing running time and tubing running depth as the production parameters of the horizontal well tubing running.

9. A computer device, comprising: The computer device comprises: at least one processor; and a memory storing program instructions configured to be executed by the at least one processor, the program instructions comprising instructions for executing the method for determining the production parameters of the horizontal well tubing running according to any one of claims 1-7.

10. A computer-readable storage medium having stored thereon computer program instructions, wherein, The computer program instructions, when executed by the processor, implement the method for determining the production parameters of the horizontal well tubing running according to any one of claims 1-7.

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