Shale oil reservoir drainage and mining optimization method based on serpentine well

Abstract

The invention relates to the technical field of oil and gas development, and provides a shale oil reservoir drainage and mining optimization method based on a serpentine well, and the method comprises the steps: obtaining basic parameters of the serpentine well, and arranging a solution node of a production system at the toe end of a horizontal section of the serpentine well; based on the shale oil reservoir productivity equation, an oil well inflow dynamic curve under the current average formation pressure is calculated; calculating an oil well outflow dynamic curve by taking the fixed wellhead pressure as a starting point; the inflow dynamic curve and the outflow dynamic curve are drawn in the same coordinate system, the intersection point of the inflow dynamic curve and the outflow dynamic curve is taken as a coordination point, and the yield and the pressure corresponding to the coordination point are the coordinated oil yield and the coordinated flowing bottomhole pressure under the current average pressure; setting a progressively decreased average formation pressure sequence to obtain a coordination point sequence, and drawing and displaying a relation curve between the coordinated oil production and the average formation pressure and a relation curve between the coordinated flowing bottomhole pressure and the average formation pressure. The method solves the problem that a traditional nodal analysis method is inaccurate in coordination point positioning when applied to the horizontal well with the complex structure.

Description

Technical Field

[0001] The embodiments of the present invention generally relate to the field of oil and gas development technology, and particularly to a method for optimizing the drainage and production of shale oil reservoirs based on meandering wells. Background Technology

[0002] Shale oil reservoirs, as typical unconventional oil and gas resources, rely heavily on horizontal well drilling and large-scale volumetric fracturing technology for their economical and effective development, aiming to create complex artificial fracture networks. Compared to conventional oil reservoirs, shale reservoirs have extremely low permeability at the nano-Darcy level and exhibit strong fluid-structure interaction during production, resulting in highly nonlinear flow patterns. Therefore, establishing a production prediction model that can accurately characterize the unique flow behavior of shale oil reservoirs and formulating a scientific drainage and production system accordingly has become a key technological challenge for achieving efficient shale oil development.

[0003] Nodal system analysis, a classic method in oil and gas well production optimization, essentially determines the optimal operating point of the system—the optimal production rate and corresponding bottomhole flowing pressure—by coordinating reservoir inflow dynamics and wellbore outflow dynamics. However, directly applying traditional nodal analysis to shale reservoirs, especially for horizontal wells with complex meandering morphologies, has significant limitations. Existing optimization methods often oversimplify the wellbore flow process or fail to set solution nodes at key locations that truly reflect the overall flow characteristics of the horizontal well, such as the toe of the horizontal section. This results in a significant deviation between the obtained coordination point and the actual production state. This systematic deviation directly leads to the failure of production control strategies, such as production differential pressure control strategies, based on this point to achieve the expected results. This not only restricts production release efficiency but may also accelerate production decline due to mismatched production systems, and even induce wellbore integrity risks. Summary of the Invention

[0004] To address the above issues, this invention employs precise simulation of the entire process from wellhead to the toe of the horizontal section to dynamically predict the optimal operating regime under different formation pressures. This overcomes the shortcomings of existing technologies, such as large model prediction bias, poor accuracy in predicting shale oil well productivity and node pressure, and limited practicality in optimizing drainage and production regimes.

[0005] According to an embodiment of the present invention, a method for optimizing shale oil reservoir drainage and production based on meandering wells is provided.

[0006] In a first aspect of the invention, a method for optimizing shale reservoir drainage and production based on meandering wells is provided. The method includes: Step S01: Obtain the basic parameters of the meandering well and set the solution node of the production system at the toe of the horizontal section of the meandering well; Step S02: Based on the shale reservoir productivity equation, calculate the dynamic curve of oil well inflow under the current average formation pressure; with a fixed wellhead pressure as the starting point, calculate the dynamic curve of oil well outflow. Step S03: Plot the inflow dynamic curve and the outflow dynamic curve on the same coordinate system, and take their intersection as the coordination point. The production and pressure corresponding to the coordination point are the coordinated oil production and coordinated bottom hole flowing pressure under the current average pressure. Step S04: Set a decreasing average formation pressure sequence, repeat steps S02-S03 to obtain a coordination point sequence, and plot and display the relationship curves between coordinated oil production and average formation pressure, and between coordinated bottom hole flowing pressure and average formation pressure.

[0007] Furthermore, the basic parameters mentioned in step S01 include: horizontal section length, number of horizontal section segments, wellbore diameter, inclination angle of each horizontal wellbore segment, fluid density, and fluid viscosity.

[0008] Furthermore, the specific steps for calculating the dynamic curve of oil well inflow under the current average formation pressure, as described in step S02, are as follows: Step 1: Construct a crack feature model, which should include at least the crack half-length, crack conductivity, and crack network complexity parameters. Step 2: Substitute the fracture characteristic model parameters into the preset shale reservoir productivity equation: , in, For shale oil reservoir production capacity, For the effective permeability of the reservoir, For reservoir thickness, To represent the average formation pressure, The pressure at the bottom of the well. To initiate the pressure gradient, To activate the pressure gradient effect term, Geological oil viscosity, This is the crude oil volume coefficient. To supply the boundary radius, Where is the wellbore radius; Step 3: Set the current average formation pressure, solve the shale oil reservoir production capacity corresponding to the bottom hole flowing pressure through the shale oil reservoir production capacity equation, and fit the curve of the relationship between bottom hole flowing pressure and oil production, i.e., the inflow dynamic curve.

[0009] Furthermore, the specific steps for calculating the dynamic curve of oil well outflow, starting from a fixed wellhead pressure, as described in step S02, are as follows: Step S021: Starting with a fixed wellhead pressure, set an oil production rate, perform flow calculations on the vertical well section from the wellhead to the bottom of the well to obtain the bottom-hole pressure and production capacity; Step S022: Starting with the bottom hole pressure and production capacity, calculate the relationship between pressure and flow rate at the toe of the meandering well by solving the node from the bottom hole to the horizontal section; Step S023: Change different oil production setpoints and repeat steps S021 to S022 to obtain the corresponding data sequence of oil production and solution node pressure, and fit to generate outflow dynamic curve.

[0010] Furthermore, the specific steps for performing flow calculations on the vertical well section from the wellhead to the bottom of the well, as described in step S021, are as follows: 1) Based on the total length of the pipeline and depth calculation step size Divide the pipeline into Specifically, for a flow channel, the total length of the channel is exactly divisible by the depth calculation step size. When the total length of the pipeline cannot be divided evenly by the depth calculation step size, Among them, the depth calculation step size rice; 2) Give the first to the second Assign coordinates to the cross-section of each flow channel ,in, Assign coordinates to the cross-section of the last flow channel. ; 3) Calculate the average pressure of the current flow channel. ,in, This is for the pressure at the upper end of the next flow channel. This refers to the pressure at the lower end of the previous flow channel; 4) Based on the current flow channel depth and the temperature at the top of the flow channel Using a gas well temperature distribution calculation model, the fluid temperature at this depth is calculated. Then calculate the average temperature of the current flow channel. for: ; 5) Calculate the average pressure of the fluid in the current flow channel based on the gas-liquid parameter calculation model. and the average temperature of the current flow channel The following physical properties include: gas density Liquid density Gas viscosity Gas compressibility factor Liquid viscosity and liquid surface tension ; 6) Solve for the pressure gradient based on the pressure distribution calculation model. According to the channel depth The pressure drop in the flow channel is calculated using the pressure gradient. The current pressure drop in the flow channel is: ; 7) Calculate the pressure at the bottom of the current flow channel: ; 8) Verify the calculated value of the lower pressure; if... ,but Otherwise Repeat the calculations from 1 to 8; 9) Set the pressure at the upper end of the first flow channel to the wellhead oil pressure. Let the pressure at the upper end of the next flow channel be equal to the pressure at the lower end of the current flow channel: Repeat the calculation process from 1) to 9) until the pressure at the lower end of the last flow channel is obtained, which is the pressure at the bottom of the well. .

[0011] Furthermore, the gas-liquid parameter calculation model is specifically as follows: The empirical formula for calculating the gas compressibility factor at a given temperature and pressure is: , ,

[0012] in, To compare the pressure, This is the critical pressure at which the gas exists. The absolute pressure of the gas. For temperature comparison, Let be the absolute temperature of the gas. This is the critical temperature of the gas.

[0013] Gas density can be expressed as: , in, The molar mass of the gas. The compressibility factor of a gas. This is the universal gas constant.

[0014] Gas viscosity can be expressed as: , in, , , ; The density of the liquid phase can be expressed as: , in, The initial density of the liquid phase. This represents the percentage of gas volume. The viscosity of the liquid phase is: .

[0015] in, This represents the initial viscosity of the liquid phase.

[0016] Furthermore, the logic of the calculation method described in step S022 for obtaining the relationship between pressure and flow rate at the toe of the meandering well by solving the node from the bottom of the well to the toe of the horizontal section is as follows: 1) Divide the horizontal section of the meandering well into There are several small segments, each with a length of [length missing]. ; 2) Assume the pressure at the upstream inlet of the horizontal section is... For the first paragraph ( ), calculate its average pressure ,in for Initial estimated pressure at the downstream export end of the segment; 3) Based on average pressure Determine the production pressure differential for this section and calculate the inflow rate for this section: , in, This refers to the volume of fluid flowing from the reservoir into a unit length of meandering well; This refers to the toe of the horizontal section of the meandering well. The pressure supplied to the reservoir is usually considered to be constant. This refers to the bottom hole flow pressure; The horizontal arc length of the meandering well. The flow conductivity coefficient of the wellbore; 4) Calculate the pressure drop using the meandering well pressure drop calculation model. pressure drop of the segment ; 5) Comparison and If the given error range is met, proceed to the next segment. Otherwise, with As a new Recalculate until the requirements are met; 6) Calculate the pressure drop of each section along the horizontal section of the meandering well, until the last section. This refers to the pressure at the toe of the serpentine well.

[0017] In a second aspect of the invention, an apparatus for optimizing shale reservoir drainage and production based on meandering wells is provided. The apparatus includes: Data input module: used to input basic parameters; Inflow dynamic calculation module: connected to the data input module, with built-in shale oil production capacity equation, used to receive formation pressure parameters, calculate and generate inflow dynamic characteristic curve data; Outflow dynamic calculation module: connected to the data input module, with a built-in wellbore multiphase flow calculation program, used to calculate wellbore pressure loss in segments starting from the wellhead, and finally generate outflow dynamic characteristic curve data at the solution node; Coordination point analysis module: connected to the inflow dynamic calculation module and the outflow dynamic calculation module, used to receive inflow dynamic characteristic curve data and outflow dynamic characteristic curve data, identify coordination points, and map the corresponding output production and bottom hole flowing pressure according to the location of the coordination point; Dynamic prediction and visualization module: connected to the coordination point analysis module, used to cyclically call the data input module, inflow dynamic calculation module, outflow dynamic calculation module and coordination point analysis module to complete the calculation under different formation pressures, and draw inflow dynamic characteristic curves and outflow dynamic characteristic curves; Results output module: Used to output key forecast data, charts, and optimization suggestion reports.

[0018] In a third aspect of the invention, an electronic device is provided. The electronic device includes a memory and a processor, the memory storing a computer program, the processor executing the program to implement the method according to a first aspect of the invention.

[0019] In a fourth aspect of the invention, a computer-readable storage medium is provided having a computer program stored thereon, which, when executed by a processor, implements the method according to a first aspect of the invention.

[0020] This invention achieves precise simulation of the entire process from wellhead to the toe of the horizontal section, dynamically predicting the optimal operating regime under different formation pressures. This overcomes the shortcomings of existing technologies, such as large model prediction deviations, poor accuracy in predicting shale oil well productivity and node pressures, and limited practicality in optimizing drainage and production regimes.

[0021] It should be understood that the description in the Summary of the Invention is not intended to limit the key or essential features of the embodiments of the present invention, nor is it intended to restrict the scope of the invention. Other features of the invention will become readily apparent from the following description.

[0022] The beneficial effects of this invention are: 1. By setting the solution node at the toe of the horizontal section and systematically coupling the reservoir inflow dynamics and wellbore outflow dynamics, the coordination point is accurately determined in a unified coordinate system. This effectively overcomes the fundamental defect of inaccurate positioning of coordination points when the traditional node analysis method is applied to horizontal wells with complex structures, and directly obtains the accurate coordinated oil production and coordinated bottom hole flowing pressure under the current formation pressure. 2. By setting a series of decreasing average formation pressure values ​​and repeatedly calculating, the coordinated working points at different development stages can be accurately located, and the corresponding optimal production and optimal bottom hole flowing pressure can be dynamically mapped. The resulting curves showing the relationship between coordinated bottom hole flowing pressure and coordinated oil production and formation pressure changes fully reveal the changing patterns of the optimal drainage system and key node pressures throughout the entire production life cycle. This provides a key basis for scientifically formulating dynamic adjustment strategies and avoids the optimization deviation caused by the dynamic disconnect between inflow and outflow in traditional methods. 3. The optimization device of the present invention integrates complex data calculation, curve analysis, result output and report generation processes into one through integrated functional modules and a visual management interface, realizing full-process automation. This not only greatly improves analysis efficiency and reduces human error, but its intuitive chart display also clearly presents the dynamic trends of production and optimization results, greatly facilitating on-site engineers to make quick and accurate decisions and carry out refined management. Attached Figure Description

[0023] The above and other features, advantages, and aspects of the various embodiments of the present invention will become more apparent from the accompanying drawings and the following detailed description. Wherein: Figure 1 A flowchart illustrating a method for optimizing shale reservoir drainage and production based on meandering wells according to an embodiment of the present invention is shown. Figure 2 A fracture feature diagram of oil well A according to Embodiment 1 of the present invention is shown; Figure 3 An inflow dynamic curve diagram according to Embodiment 1 of the present invention is shown; Figure 4 The outflow dynamic curve is shown in Embodiment 1 of the present invention; Figure 5 The diagram shows the results of the optimization analysis of the sampling system according to Embodiment 1 of the present invention; Figure 6 The diagram showing the relationship between average formation pressure and optimal bottom hole flowing pressure according to Embodiment 1 of the present invention is illustrated. Figure 7 A graph showing the relationship between average formation pressure and optimal production according to Embodiment 1 of the present invention is shown; Figure 8 A schematic diagram of the device interface according to Embodiment 2 of the present invention is shown; Figure 9 A schematic diagram of a primary interface according to Embodiment 2 of the present invention is shown; Figure 10 A schematic diagram of a secondary interface according to Embodiment 2 of the present invention is shown.

[0024] The diagram is labeled as follows: 1. Data Input Module, 2. Inflow Dynamic Calculation Module, 3. Outflow Dynamic Calculation Module, 4. Coordination Point Analysis Module, 5. Dynamic Prediction and Visualization Module, 51. First-Level Interface, 52. Second-Level Interface, 53. Input Parameter Unit, 54. Inflow Dynamic Characterization Unit, 55. Outflow Dynamic Characterization Unit, 56. Chart Display Characterization Unit, 57. Data Table Display Characterization Unit, 6. Result Output Module. Detailed Implementation

[0025] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0026] According to an embodiment of the present invention, a method for optimizing shale oil reservoir drainage and production based on meandering wells is proposed. By accurately simulating the entire process from the wellhead to the toe of the horizontal section, the optimal operating regime under different formation pressures is dynamically predicted, overcoming the shortcomings of existing technologies such as large model prediction deviations, poor accuracy in predicting shale oil well productivity and node pressures, and weak practicality of drainage and production regime optimization.

[0027] The principles and spirit of the present invention will be explained in detail below with reference to several representative embodiments.

[0028] Figure 1 This is a schematic flowchart of a method for optimizing shale oil reservoir drainage and production based on meandering wells, according to an embodiment of the present invention. The method includes: Step S01: Obtain the basic parameters of the meandering well and set the solution node of the production system at the toe of the horizontal section of the meandering well; Step S02: Based on the shale reservoir productivity equation, calculate the dynamic curve of oil well inflow under the current average formation pressure; with a fixed wellhead pressure as the starting point, calculate the dynamic curve of oil well outflow. Step S03: Plot the inflow dynamic curve and the outflow dynamic curve on the same coordinate system, and take their intersection as the coordination point. The production and pressure corresponding to the coordination point are the coordinated oil production and coordinated bottom hole flowing pressure under the current average pressure. Step S04: Set a decreasing average formation pressure sequence, repeat steps S02-S03 to obtain a coordination point sequence, and plot and display the relationship curves between coordinated oil production and average formation pressure, and between coordinated bottomhole flowing pressure and average formation pressure. By employing a coordination point analysis method, the inflow dynamics (IPR) and outflow dynamics (DPR) are systematically coupled. Specifically, the inflow dynamic curve of the oil well is calculated based on the shale reservoir production capacity equation, and the outflow dynamic curve is calculated starting from a fixed wellhead pressure. The intersection point, or coordination point, of these two curves is determined by plotting them on the same coordinate system. This yields the coordinated production rate and coordinated bottomhole flowing pressure under the current formation pressure, effectively solving the problem of inaccurate coordination point location in traditional node analysis methods applied to complex horizontal well structures. This method can accurately locate the coordination working point under different formation pressures, thereby dynamically mapping the corresponding optimal production rate and bottomhole flowing pressure. Furthermore, by setting a series of decreasing average formation pressure values ​​and repeating the above calculation process, a series of coordination point data can be obtained. This allows for the plotting of the relationship curves between coordinated bottomhole flowing pressure and coordinated production rate as a function of formation pressure. This invention can generate a complete production dynamic prediction curve, accurately revealing the optimal production and drainage system and the changing patterns of node pressures throughout the entire production lifecycle. This provides crucial decision-making basis for the efficient and scientific development of shale reservoirs, effectively avoiding the optimization deviation problem caused by the disconnect between inflow and outflow dynamics in traditional methods.

[0029] It should be noted that although the operation of the method of the present invention has been described in a specific order in the above embodiments and figures, this does not require or imply that the operations must be performed in that specific order, or that all the operations shown must be performed to achieve the desired result. Additionally or alternatively, certain steps may be omitted, multiple steps may be combined into one step, and / or one step may be broken down into multiple steps.

[0030] To provide a clearer explanation of the above-mentioned method for optimizing shale reservoir drainage and production based on meandering wells, two specific embodiments are described below. However, it is worth noting that these embodiments are only for better illustrating the present invention and do not constitute an improper limitation of the present invention.

[0031] Example 1

[0032] This embodiment provides a method for optimizing shale reservoir drainage and production based on meandering wells, and the steps are as follows.

[0033] Step S01: Obtain the basic parameters of the meandering well and set the solution node of the production system at the toe of the horizontal section of the meandering well.

[0034] The basic parameters include: horizontal section length, number of horizontal sections, wellbore diameter, inclination angle of each horizontal wellbore section, fluid density, and fluid viscosity.

[0035] Step S02: Based on the shale reservoir productivity equation, calculate the current average formation pressure. The dynamic curve of oil well inflow; with a fixed wellhead pressure. Starting from the point, calculate the dynamic curve of oil well outflow.

[0036] The specific steps for calculating the dynamic curve of oil well inflow under the current mean formation pressure are as follows: Step 1: Construct a crack feature model. The crack feature model should include at least the crack half-length, crack conductivity, and crack network complexity parameters. The crack network complexity parameters include at least one of crack density, crack connectivity, and crack orientation distribution.

[0037] Step 2: Substitute the fracture characteristic model parameters into the preset shale reservoir productivity equation: , in, For shale oil reservoir production capacity, For the effective permeability of the reservoir, For reservoir thickness, To represent the average formation pressure, The pressure at the bottom of the well. To initiate the pressure gradient, To activate the pressure gradient effect term, Geological oil viscosity, This is the crude oil volume coefficient. To supply the boundary radius, Where is the radius of the wellbore.

[0038] The shale oil reservoir productivity equation is a nonlinear equation that takes into account the coupling of fracture seepage and matrix seepage.

[0039] Step 3: Set the current average formation pressure, solve the shale oil reservoir production capacity corresponding to the bottom hole flowing pressure through the shale oil reservoir production capacity equation, and fit the curve of the relationship between bottom hole flowing pressure and oil production, i.e., the inflow dynamic curve.

[0040] With a fixed wellhead pressure Starting from this point, the specific steps for calculating the dynamic curve of oil well outflow are as follows: Step S021: Starting with a fixed wellhead pressure, set an oil production rate, perform flow calculations on the vertical well section from the wellhead to the bottom of the well to obtain the bottom-hole pressure and production capacity.

[0041] Specifically, the steps for performing flow calculations on the vertical section from the wellhead to the bottom of the well are as follows: 1) Based on the total length of the pipeline and depth calculation step size Divide the pipeline into Specifically, for a flow channel, the total length of the channel is exactly divisible by the depth calculation step size. When the total length of the pipeline cannot be divided evenly by the depth calculation step size, Among them, the depth calculation step size rice.

[0042] 2) Give the first to the second Assign coordinates to the cross-section of each flow channel ,in, Assign coordinates to the cross-section of the last flow channel. .

[0043] 3) Calculate the average pressure of the current flow channel. ,in, This is for the pressure at the upper end of the next flow channel. This is the pressure at the lower end of the previous flow channel.

[0044] 4) Based on the current flow channel depth and the temperature at the top of the flow channel Using a gas well temperature distribution calculation model, the fluid temperature at this depth is calculated. Then calculate the average temperature of the current flow channel. for: .

[0045] 5) Calculate the average pressure of the fluid in the current flow channel based on the gas-liquid parameter calculation model. and the average temperature of the current flow channel The following physical properties include: gas density Liquid density Gas viscosity Gas compressibility factor Liquid viscosity and liquid surface tension .

[0046] 6) Solve for the pressure gradient based on the pressure distribution calculation model. According to the channel depth The pressure drop in the flow channel is calculated using the pressure gradient. The current pressure drop in the flow channel is: .

[0047] 7) Calculate the pressure at the bottom of the current flow channel: .

[0048] 8) Verify the calculated value of the lower pressure; if... ,but Otherwise Repeat the calculations from 1 to 8. Specifically, The value is typically set to 0.01.

[0049] 9) Set the pressure at the upper end of the first flow channel to the wellhead oil pressure. Let the pressure at the upper end of the next flow channel be equal to the pressure at the lower end of the current flow channel: Repeat the calculation process from 1) to 9) until the pressure at the lower end of the last flow channel is obtained, which is the pressure at the bottom of the well. .

[0050] Specifically, the gas-liquid parameter calculation model works as follows: Since the gas experiences different pressures at different locations in the wellbore, its properties also differ. Based on empirical formulas, the gas compressibility factor and viscosity can be calculated from temperature, pressure, and molar mass. Based on the equation of state, the changes in gas and liquid density can be calculated from temperature, pressure, molar mass, and compressibility factor.

[0051] The empirical formula for calculating the gas compressibility factor at a given temperature and pressure is: , ,

[0052] in, To compare the pressure, This is the critical pressure at which the gas exists. The absolute pressure of the gas. For temperature comparison, Let be the absolute temperature of the gas. This is the critical temperature of the gas.

[0053] Gas density can be expressed as: , in, The molar mass of the gas. The compressibility factor of a gas. This is the universal gas constant; Gas viscosity can be expressed as: , in, , , ; The density of the liquid phase can be expressed as: , in, The initial density of the liquid phase. This represents the percentage of gas volume. The viscosity of the liquid phase is: .

[0054] in, This represents the initial viscosity of the liquid phase.

[0055] Step S022: Starting with the bottom hole pressure and production capacity, calculate the relationship between pressure and flow rate at the toe of the meandering well by solving the node from the bottom hole to the horizontal section.

[0056] In this embodiment, the calculation logic for the relationship between pressure and flow rate at the toe of the meandering well, obtained by solving the node from the bottom of the well to the toe of the horizontal section, is as follows: 1) Divide the horizontal section of the meandering well into There are several small segments, each with a length of [length missing]. .

[0057] 2) Assume the pressure at the upstream inlet of the horizontal section is... For the first paragraph ( ), calculate its average pressure ,in for Initial estimated pressure at the downstream export end of the segment.

[0058] 3) Based on average pressure Determine the production pressure differential for this section and calculate the inflow rate for this section: , in, This refers to the volume of fluid flowing from the reservoir into a unit length of meandering well; This refers to the toe of the horizontal section of the meandering well. The pressure supplied to the reservoir is usually considered to be constant. This refers to the bottom hole flow pressure; The horizontal arc length of the meandering well. The flow conductivity coefficient of the wellbore.

[0059] 4) Calculate the pressure drop using the meandering well pressure drop calculation model. pressure drop of the segment .

[0060] 5) Comparison and If the given error range is met, proceed to the next segment. Otherwise, with As a new Recalculate until the requirements are met.

[0061] 6) Calculate the pressure drop of each section along the horizontal section of the meandering well, until the last section. This refers to the pressure at the toe of the serpentine well.

[0062] It should be understood that the calculation of single-phase flow in the horizontal section in this embodiment is derived and modified using Darcy's formula or homogeneous flow model in the prior art, which will not be elaborated here.

[0063] Step S023: Change different oil production setpoints and repeat steps S021 to S022 to obtain the corresponding data sequence of oil production and solution node pressure, and fit to generate outflow dynamic curve.

[0064] Step S03: Plot the inflow dynamic curve and the outflow dynamic curve on the same coordinate system, and take their intersection point as the coordination point. The output and pressure corresponding to the coordination point are the current average pressure. Coordinate oil production and bottom hole flowing pressure.

[0065] Step S04: Set the decreasing mean formation pressure Repeat steps S02-S03 to obtain the coordination point sequence, and plot and display the coordination oil production and mean formation pressure. Coordinate bottom hole flowing pressure with mean formation pressure The relationship curve.

[0066] Taking well A of group X in a certain region of northern China as an example, the depth is about 3500m, the horizontal section is 2000m long, the formation pressure is 40MPa, the porosity is 5%, the permeability is 0.03mD, the crude oil viscosity is 0.2mPa·s, and the compressibility coefficient of shale oil is 0.000245MPa. ¹, The rock compressibility of the fracture is 0.000255 MPa. ¹, The compressibility of the shale matrix is ​​0.000245 MPa. ¹, The stress sensitivity coefficient of the matrix is ​​0.035 MPa. ¹, The stress sensitivity coefficient of the crack is 0.15 MPa. ¹, The inner diameter of the casing is 0.118m, and the outer diameter of the casing is 0.133m. Specific parameters are shown in Table 1: Table 1

[0067] At this time, the fracture distribution in the reservoir is as follows: Figure 2 As shown, the optimization method of this application is used to optimize the optimal production pressure and output, and the resulting inflow curve is as follows. Figure 3 As shown, the outflow curve is as follows Figure 4 As shown. Specifically, the results of the optimization analysis of the sampling system are as follows: Figure 5 As shown, in actual reservoir production, formation pressure decreases continuously as production time progresses. Assuming a linear decrease in formation pressure over time, the optimal bottomhole flowing pressure changes as follows: Figure 6 As shown in the figure, when the average formation pressure is 25 MPa, the optimal bottomhole flowing pressure is approximately 12.52 MPa. The variation pattern of the optimal production rate is as follows. Figure 7 As shown, it can be read that when the average pressure of the local formation is 25 MPa, the optimal oil production is approximately 14.65 tons / day.

[0068] Example 2

[0069] like Figure 8As shown, this embodiment provides a device for optimizing shale reservoir drainage and production based on meandering wells. The device includes: a data input module 1, an inflow dynamic calculation module 2, an outflow dynamic calculation module 3, a coordination point analysis module 4, a dynamic prediction and visualization module 5, and a result output module 6.

[0070] Data input module 1 is used to input basic parameters, including formation pressure data, shale reservoir physical properties, wellbore structure parameters, fluid PVT parameters, and a fixed wellhead pressure. Inflow dynamic calculation module 2 is connected to data input module 1, contains a built-in shale oil production capacity equation, and is used to receive formation pressure parameters, calculate, and generate IPR curve data. Outflow dynamic calculation module 3 is connected to data input module 1, contains a built-in wellbore multiphase flow calculation program, and is used to calculate wellbore pressure loss segment by segment starting from the wellhead, ultimately generating DPR curve data at the solution node. Coordination point analysis module 4 is connected to both inflow dynamic calculation module 2 and outflow dynamic calculation module 3. The dynamic calculation module 3 is connected to receive IPR curve data and DPR curve data, confirms the coordination point, and maps the corresponding output production and bottom hole flowing pressure according to the location of the coordination point. The dynamic prediction and visualization module 5 is connected to the coordination point analysis module 4 and is used to cyclically call the data input module 1, the inflow dynamic calculation module 2, the outflow dynamic calculation module 3, and the coordination point analysis module 4 to complete the calculation under different formation pressures and draw the IPR / DPR curve, Pw_opt-Pr relationship diagram, and Qo_opt-Pr relationship diagram. The result output module 6 is used to output the key data, charts, and optimization suggestion report of the prediction.

[0071] The optimization device in this embodiment is equipped with a coordination point analysis module 4, which integrates and analyzes the IPR curve data generated by the inflow dynamic calculation module 2 and the DPR curve data generated by the outflow dynamic calculation module 3 to accurately determine the location of the coordination point. Then, the corresponding output production and bottom hole flowing pressure are mapped according to the location of the coordination point. The dynamic prediction and visualization module 5 then integrates and analyzes the calculation data of the data input module 1, the inflow dynamic calculation module 2, the outflow dynamic calculation module 3 and the coordination point analysis module 4 to complete the calculation under different formation pressures and accurately predict the optimal production and optimal bottom hole flowing pressure.

[0072] In this embodiment, confirming the coordination point includes the following: plotting the IPR curve data and DPR curve data on the same coordinate system, and the intersection of the two curves is the coordination point under the formation pressure.

[0073] like Figure 9 and Figure 10As shown, the dynamic prediction and visualization module 5 in this embodiment includes: a primary interface 51 and a secondary interface 52; an input parameter unit 53, an inflow dynamic representation unit 54, and an outflow dynamic representation unit 55 set on the primary interface 51; and a chart display representation unit 56 and a data table display representation unit 57 set on the secondary interface 52. In this embodiment, the secondary interface 52 and the primary interface 51 are in a progressive display relationship.

[0074] The result output module 6 includes a unit representing the average formation pressure and bottom hole flowing pressure set on the secondary interface, a unit representing the average formation pressure and predicted production set on the secondary interface, and an optimization suggestion report. The unit representing the average formation pressure and bottom hole flowing pressure, the unit representing the average formation pressure and predicted production, and the optimization suggestion report are all connected to the dynamic prediction and visualization module 5. The key data includes inflow dynamic curve data and outflow dynamic curve data under different average formation pressures, optimal production, optimal bottom hole flowing pressure, and formation pressure-optimal production relationship curve data and formation pressure-optimal bottom hole flowing pressure relationship curve data obtained by fitting a series of coordination points.

[0075] Based on the optimization method and apparatus described in this application, and using the production capacity equation and outflow dynamic model of shale oil reservoirs, nodal analysis is employed to optimize the characteristics of the oil well production system. By analyzing the intersection of the inflow and outflow characteristic curves, the optimal production rate and bottom hole flowing pressure of the oil well under different formation pressures are determined. The influence of formation pressure on production capacity and bottom hole flowing pressure is incorporated to rationally adjust the bottom hole flowing pressure and production regime, thereby significantly improving the production capacity and recovery rate of the oil well.

[0076] Furthermore, although the operations are described in a specific order, this should be understood as requiring that such operations be performed in the specific order shown or in sequential order, or requiring that all illustrated operations be performed to achieve the desired result. In certain environments, multitasking and parallel processing may be advantageous. Similarly, although several specific implementation details are included in the above discussion, these should not be construed as limiting the scope of the invention. Certain features described in the context of individual embodiments may also be implemented in combination in a single implementation. Conversely, various features described in the context of a single implementation may also be implemented individually or in any suitable sub-combination in multiple implementations.

[0077] Although the subject matter has been described using language specific to structural features and / or methodological logic, it should be understood that the subject matter defined in the appended claims is not necessarily limited to the specific features or actions described above. Rather, the specific features and actions described above are merely illustrative examples of implementing the claims.

Claims

1. A method for optimizing shale oil reservoir drainage and production based on meandering wells, characterized in that, The method includes: Step S01: Obtain the basic parameters of the meandering well and set the solution node of the production system at the toe of the horizontal section of the meandering well; Step S02: Based on the shale reservoir productivity equation, calculate the dynamic curve of oil well inflow under the current average formation pressure; starting from a fixed wellhead pressure, calculate the dynamic curve of oil well outflow. Step S03: Plot the inflow dynamic curve and the outflow dynamic curve on the same coordinate system, and take their intersection as the coordination point. The production and pressure corresponding to the coordination point are the coordinated oil production and coordinated bottom hole flowing pressure under the current average pressure. Step S04: Set a decreasing average formation pressure sequence, repeat steps S02-S03 to obtain a coordination point sequence, and plot and display the relationship curves between coordinated oil production and average formation pressure, and between coordinated bottom hole flowing pressure and average formation pressure.

2. The method for optimizing shale reservoir drainage and production based on meandering wells according to claim 1, characterized in that, The basic parameters mentioned in step S01 include: horizontal section length, number of horizontal sections, wellbore diameter, inclination angle of each horizontal wellbore section, fluid density, and fluid viscosity.

3. The method for optimizing shale reservoir drainage and production based on meandering wells according to claim 1, characterized in that, The specific steps for calculating the dynamic curve of oil well inflow under the current mean formation pressure, as described in step S02, are as follows: Step 1: Construct a crack feature model, which should include at least the crack half-length, crack conductivity, and crack network complexity parameters. Step 2: Substitute the fracture characteristic model parameters into the preset shale reservoir productivity equation: ， in, For shale oil reservoir production capacity, For the effective permeability of the reservoir, For reservoir thickness, To represent the average formation pressure, The pressure at the bottom of the well. To initiate the pressure gradient, To activate the pressure gradient effect term, Geological oil viscosity, This is the crude oil volume coefficient. To supply the boundary radius, Where is the wellbore radius; Step 3: Set the current average formation pressure, solve the shale oil reservoir production capacity corresponding to the bottom hole flowing pressure through the shale oil reservoir production capacity equation, and fit the curve of the relationship between bottom hole flowing pressure and oil production, i.e., the inflow dynamic curve.

4. The method for optimizing shale oil reservoir drainage and production based on meandering wells according to claim 1, characterized in that, The specific steps for calculating the dynamic curve of oil well outflow, starting from a fixed wellhead pressure, as described in step S02, are as follows: Step S021: Starting with a fixed wellhead pressure, set an oil production rate, perform flow calculations on the vertical section from the wellhead to the bottom of the well to obtain the bottom-hole pressure and production capacity; Step S022: Starting with the bottom hole pressure and production capacity, calculate the relationship between pressure and flow rate at the toe of the meandering well by solving the node from the bottom hole to the horizontal section; Step S023: Change different oil production setpoints and repeat steps S021 to S022 to obtain the corresponding data sequence of oil production and solution node pressure, and fit to generate the outflow dynamic curve.

5. The method for optimizing shale oil reservoir drainage and production based on meandering wells according to claim 4, characterized in that, The specific steps for performing flow calculations on the vertical well section from the wellhead to the bottom of the well, as described in step S021, are as follows: 1) Based on the total length of the pipeline and depth calculation step size Divide the pipeline into Specifically, for a flow channel, the total length of the channel is exactly divisible by the depth calculation step size. ; When the total length of the pipeline cannot be divided evenly by the depth calculation step size Among them, the depth calculation step size rice; 2) Give the first to the second Assign coordinates to the cross-section of each flow channel ,in, Assign coordinates to the cross-section of the last flow channel. ; 3) Calculate the average pressure of the current flow channel. ,in, This is to adjust the pressure at the upper end of the next flow channel. This refers to the pressure at the lower end of the previous flow channel; 4) Based on the current flow channel depth and the temperature at the top of the flow channel Using a gas well temperature distribution calculation model, the fluid temperature at this depth is calculated. Then calculate the average temperature of the current flow channel. for: ; 5) Calculate the average pressure of the fluid in the current flow channel based on the gas-liquid parameter calculation model. and the average temperature of the current flow channel The following physical properties include: gas density Liquid density Gas viscosity Gas compressibility factor Liquid viscosity and liquid surface tension ; 6) Solve for the pressure gradient based on the pressure distribution calculation model. According to the channel depth The pressure drop in the flow channel is calculated using the pressure gradient. The current pressure drop in the flow channel is: ; 7) Calculate the pressure at the bottom of the current flow channel: ; 8) Verify the calculated value of the lower pressure; if... ,but Otherwise Repeat the calculations from 1 to 8; 9) Set the pressure at the upper end of the first flow channel to the wellhead oil pressure. Let the pressure at the upper end of the next flow channel be equal to the pressure at the lower end of the current flow channel: Repeat the calculation process from 1) to 9) until the pressure at the lower end of the last flow channel is obtained, which is the pressure at the bottom of the well. .

6. The method for optimizing shale reservoir drainage and production based on meandering wells according to claim 5, characterized in that, The specific gas-liquid parameter calculation model is as follows: The empirical formula for calculating the gas compressibility factor at a given temperature and pressure is: ， ， in, To compare the pressure, This is the critical pressure at which the gas exists. The absolute pressure of the gas. For temperature comparison, Let be the absolute temperature of the gas. This is the critical temperature of the gas. Gas density can be expressed as: ， in, The molar mass of the gas. The compressibility factor of a gas. This is the universal gas constant; Gas viscosity can be expressed as: ， in, ， ， ； The density of the liquid phase can be expressed as: ， in, The initial density of the liquid phase. This represents the percentage of gas volume. The viscosity of the liquid phase is: ， in, This represents the initial viscosity of the liquid phase.

7. The method for optimizing shale oil reservoir drainage and production based on meandering wells according to claim 4, characterized in that, The calculation method for obtaining the relationship between pressure and flow rate at the toe of the meandering well by solving the node calculation from the bottom of the well to the toe of the horizontal section in step S022 is as follows: 1) Divide the horizontal section of the meandering well into There are several small segments, each with a length of [length missing]. ; 2) Assume the pressure at the upstream inlet of the horizontal section is... For the first paragraph ( ), calculate its average pressure ,in for Initial estimated pressure at the downstream export end of the segment; 3) Based on average pressure Determine the production pressure differential for this section and calculate the inflow rate for this section: ， in, This refers to the volume of fluid flowing from the reservoir into a unit length of meandering well; This refers to the toe of the horizontal section of the meandering well. The pressure supplied to the reservoir is usually considered a constant; This refers to the bottom hole flow pressure; The horizontal arc length of the meandering well. The flow conductivity coefficient of the wellbore; 4) Calculate the pressure drop using the meandering well pressure drop calculation model. pressure drop of the segment ; 5) Comparison and If the given error range is met, proceed to the next segment. Otherwise, with As a new Recalculate until the requirements are met; 6) Calculate the pressure drop of each section along the horizontal section of the meandering well, until the last section. This refers to the pressure at the toe of the serpentine well.

8. A device for optimizing shale oil reservoir drainage and production based on meandering wells, characterized in that, The device implements the method as described in any one of claims 1 to 7, comprising: Data input module (1): Used to input basic parameters; Inflow dynamic calculation module (2): connected to the data input module (1), with built-in shale oil production capacity equation, used to receive formation pressure parameters, calculate and generate inflow dynamic characteristic curve data; Outflow dynamic calculation module (3): connected to the data input module (1), with a built-in wellbore multiphase flow calculation program, used to calculate wellbore pressure loss in segments starting from the wellhead, and finally generate outflow dynamic characteristic curve data at the solution node; Coordination point analysis module (4): connected to the inflow dynamic calculation module (2) and the outflow dynamic calculation module (3), used to receive inflow dynamic characteristic curve data and outflow dynamic characteristic curve data, confirm coordination points, and map the corresponding output production and bottom hole pressure according to the location of the coordination points; Dynamic prediction and visualization module (5): connected to the coordination point analysis module (4), used to cyclically call the data input module (1), inflow dynamic calculation module (2), outflow dynamic calculation module (3) and coordination point analysis module (4) to complete the calculation under different formation pressures and draw the inflow dynamic characteristic curve and the outflow dynamic characteristic curve; Results output module (6): Used to output key data, charts and optimization suggestions reports for prediction.

9. An electronic device comprising a memory and a processor, wherein the memory stores a computer program, characterized in that, When the processor executes the program, it implements the method as described in any one of claims 1 to 7.

10. A computer-readable storage medium having a computer program stored thereon, characterized in that, When the program is executed by the processor, it implements the method as described in any one of claims 1 to 7.

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