Well bottom flow pressure determination method based on multiphase flow, readable storage medium and device

Abstract

The application discloses a well bottom flow pressure determination method based on multiphase flow, a readable storage medium and a device, and belongs to the technical field of oil and gas field development. The method comprises the following steps: establishing a wellbore model, discretizing a target well section into continuous micro-element sections from a wellhead; calculating the oil, gas and water mixture density according to the pressure and temperature of the current micro-element section; determining the pressure of the current micro-element section based on the density and the relationship between the pressure and the dissolved gas-oil ratio; solving the pressure of the next micro-element section by using a numerical iteration method according to the pressure gradient relationship; and repeating the iteration until completion by taking the result as a new initial value. The readable storage medium stores the above method. The device provides software and hardware based on the above method. The application can consider the changes of well depth, pressure and temperature, fully consider the relationship between the well bottom flow pressure and the well bottom flow pressure, be more in line with the actual well bottom situation, more accurately determine the well bottom flow pressure, and then serve as a high-precision basis and reliable data basis for oil well production and injection-production, and improve the scientific nature of oil and gas development.

Description

TECHNICAL FIELD

[0001] The application belongs to the technical field of oil and gas field development, and particularly relates to a well bottom flow pressure determination method based on multiphase flow, a readable storage medium and a device. BACKGROUND

[0002] At present, the well bottom flow pressure calculation methods widely used in oilfield sites are mainly based on the static liquid column pressure formula, and the core assumption is that the fluid density is constant. However, in the actual oil and gas and water multiphase flow process, the fluid density is a function of pressure, temperature and volume fraction of each phase, and is a dynamic change parameter. Ignoring this dynamic characteristic is the root cause of calculation error. Although some multiphase flow models have tried to describe the process, they are usually complex in structure, large in calculation amount, and have not been organically combined with efficient numerical algorithms, making it difficult to form a set of solutions suitable for engineering practice.

[0003] As a core parameter for evaluating reservoir productivity, analyzing reservoir dynamic characteristics and optimizing production system, the calculation accuracy of well bottom flow pressure directly determines the scientificity, economy and safety of oil and gas exploitation. However, the existing technologies (such as the average density method and the empirical formula method) simplify the density of mixed fluid in the wellbore as a constant or use an overly simplified model, and fail to fully consider the dynamic characteristics of the density change with the well depth, pressure and temperature, resulting in a large deviation in the calculation results and failing to meet the needs of fine management of oilfields. In addition, the existing methods lack universality and are difficult to adapt to different types of production wells (such as flowing wells, screw pump wells and pumping wells), especially in the application of pumping wells. SUMMARY

[0004] The application aims to solve the technical problem that the dynamic characteristics of the density change with the well depth, pressure and temperature are not fully considered, resulting in a large deviation in the calculation results of well bottom flow pressure. To this end, the application provides a well bottom flow pressure determination method based on multiphase flow, a readable storage medium and a device, which can take into account the changes of well depth, pressure and temperature, fully consider the relationship between well bottom flow pressure, and more conform to the actual situation that well bottom flow pressure is affected by the coupling of multiple parameters, can more accurately determine the well bottom flow pressure, and then serve as a high-precision basis and reliable data basis for oil well production and injection-production, and improve the scientificity of oilfield development design.

[0005] In a first aspect, an embodiment of the application provides a well bottom flow pressure determination method based on multiphase flow, which comprises:

[0006] Establishing a wellbore model, taking the wellhead as the starting point, and discretizing the entire well section to be calculated into N continuous micro-element sections along the wellbore;

[0007] For the micro-element section currently calculated i , according to its corresponding pressure P i and temperature T i , the micro-element sectioni Density of the mixture of oil, gas, and water; initially i =1;

[0008] Based on the currently calculated micro-element segments i The density of the mixture, combined with infinitesimal elements i Pressure P i R of dissolved gas and oil S The relationship determines the infinitesimal segment. i Pressure P i ;

[0009] According to micro segment i With adjacent micro-element segments i The pressure gradient relationship of +1 is solved using the fourth-order Runge-Kutta method for adjacent infinitesimal segments. i +1 pressure P i+1 , i = i +1;

[0010] P i+1 The value assigned to P i Repeat the fourth-order Runge-Kutta method iteratively to solve for adjacent infinitesimal segments. i +1 pressure P i+1 until i =N.

[0011] In some implementations, the fourth-order Runge-Kutta method is used to solve for adjacent infinitesimal segments. i +1 pressure P i+1 Specifically:

[0012] Solve for F( x n , y n )exist( x n , y n slope at ) k 1;

[0013] Solve for F( x n , y n )exist slope at k 2;

[0014] Repeatedly solve F( x n , y n )exist The slope at point is denoted as k 3;

[0015] Solve for F(x n , y n ) at the slope k 4;

[0016] The average slope is solved based on the slopes k 1、 k 2、 k 3、 k 4, multiplied by the well depth increment , used to represent the pressure increment ;

[0017] The average pressure increment is substituted into the pressure gradient formula to obtain the pressure P i +1 of the micro-element section i+1 ;

[0018] Wherein, the function F( x n , y n ) represents the relationship between the bottom hole flowing pressure P and the well depth h ; h represents the well depth; n represents the micro-element section number.

[0019] In some embodiments, the pressure increment is:

[0020]

[0021] In some embodiments, the slopes k 1、 k 2、 k 3、 k 4 are respectively:

[0022]

[0023] In some embodiments, when determining the pressure increment , if the daily liquid production is greater than or equal to 100 m 3 / d, the pressure increment is:

[0024]

[0025] Wherein, the pressure increment of the wellbore friction resistance is .

[0026] In some embodiments, when determining the pressure increment , if the daily liquid production is less than 100 m​3 ΔP is:

[0027]

[0028] wherein, ν mix (P i , fw) is the kinematic viscosity of the mixture, m 2 / s, μ w μ o μ g are the dynamic viscosities of water, crude oil, and natural gas, respectively, Pa·s .

[0029] In some embodiments, the microelement segment i has a mixture density of oil, gas, and water of:

[0030]

[0031] wherein, ρ mix (P i , fw) is the wellbore mixture density of the microelement segment, kg / m 3 . P i is the pressure of the microelement segment, MPa; ρ w (P i ) is the density of water at the pressure of the microelement segment, kg / m 3 ; fw is the water cut measured at the wellbore, %; ρ 0(P i ) is the density of crude oil at the pressure of the microelement segment, kg / m 3 ; R S is the dissolved gas-oil ratio, m 3 / t; ρ g (P i ) is the density of natural gas at the pressure of the microelement segment, kg / m 3 .

[0032] In some embodiments, the dissolved gas-oil ratio R S has a value of:

[0033] If the wellbore pressure of the microelement segment i is greater than the saturation pressure, R S is the original dissolved gas-oil ratio of the reservoir;

[0034] ​​​If the infinitesimal segment i When the wellbore pressure is less than the saturation pressure, R S for:

[0035]

[0036] Where C1, C2, and C3 represent the constants for the empirical fit of the Vasquez-Beggs empirical formula; T i This indicates the temperature of the infinitesimal segment, in °C. API This indicates the density of the crude oil.

[0037] Secondly, embodiments of this application provide a readable storage medium storing a computer program, which, when executed, performs the wellbore pressure determination method based on multiphase flow as described above.

[0038] Thirdly, embodiments of this application provide a bottom-hole flowing pressure determination device based on multiphase flow, including a memory, a processor, and a terminal program stored in the memory and executable in the processor, the terminal program including an input module, a calculation module, and an output module;

[0039] The input module is used to acquire wellbore structure data, production data, and formation fluid PVT property data;

[0040] The calculation module is used to receive data from the input module and perform the corresponding steps using the above-mentioned method for determining bottom hole flowing pressure based on multiphase flow.

[0041] The output module is used to obtain the output results of the calculation module and output graphs or tables.

[0042] As can be seen from the above technical solution, the beneficial effects of this application are as follows:

[0043] 1. The method of this application, by establishing a wellbore model and discretizing it into micro-elements, provides a refined description of the wellbore data, thereby enabling a continuous description of the density of the oil, gas, and water mixture within the wellbore. This is achieved by simultaneously establishing micro-elements. i The relationship between pressure and dissolved gas ratio can determine the micro-element. iThe pressure is calculated by incorporating temperature parameters into the dissolved gas-oil ratio, thus fully considering the dynamic changes in fluid density and dissolved gas-oil ratio within the wellbore with pressure and temperature. This allows for dynamic characterization of the pressure in each micro-segment within the wellbore. Furthermore, the fourth-order Runge-Kutta method, combined with pressure gradient relationships, determines the variation relationships between adjacent micro-segments. Repeated iterative solutions allow for continuous iterative calculation of the bottom-hole flowing pressure from the surface to the bottom of the well. This approach incorporates well depth, pressure, and temperature variations, fully considering their relationship with bottom-hole flowing pressure. This better reflects the actual situation where bottom-hole flowing pressure is affected by multiple coupled parameters, enabling more accurate determination of the bottom-hole flowing pressure. The calculation error is reduced from 5%-10% in traditional methods to within 1%-2%, providing a reliable data foundation for production decisions. This serves as a high-precision and reliable data basis for oil well production and injection / production, improving the scientific nature of oilfield development design.

[0044] 2. The readable storage medium of this application provides a storage medium for storing the bottom hole pressure determination method based on multiphase flow, thereby enabling the method to be software-based. This method can cover wells with three main oil production methods: self-flowing, screw pump, and pumping unit, and can be applied to various electronic devices, reducing application complexity and improving the universality of the method.

[0045] 3. The device of this application exists as a computer program for determining the bottom hole flowing pressure based on multiphase flow. The execution process of the computer program is stored in the memory. By executing the computer program through the processor, the bottom hole flowing pressure can be determined quickly. It has a high degree of automation, can quickly solve the bottom hole flowing pressure, and output the visualization results of the chart. The input and output results are clear and easy to integrate into the existing production analysis platform or digital system of the oilfield to realize real-time or near real-time calculation and monitoring of bottom hole flowing pressure. Attached Figure Description

[0046] To more clearly illustrate the technical solutions in the embodiments of this application, the accompanying drawings used in the description of the embodiments will be briefly introduced one by one below. Obviously, the accompanying drawings described below are some embodiments of this application. For those skilled in the art, other embodiments and drawings can be obtained based on these drawings without creative effort. Various schematic diagrams according to the embodiments of this application are shown in the accompanying drawings. These drawings are not necessarily drawn to scale. For the purpose of clarity, some details have been enlarged and some details may have been omitted.

[0047] Figure 1 A schematic diagram illustrating an embodiment of the method for determining bottom hole flowing pressure based on multiphase flow according to the present invention is shown;

[0048] Figure 2A comparison chart of calculation and measured results is shown in an application embodiment of the wellbore pressure determination method based on multiphase flow of the present invention;

[0049] Figure 3 The software output diagram shows an application embodiment of the wellbore bottom pressure determination method based on multiphase flow of the present invention. Detailed Implementation

[0050] The technical solutions in the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. The detailed description of the embodiments of this application provided in the drawings is not intended to limit the scope of the claimed application. The described embodiments are only a part of the embodiments of this application, not all of them. Based on the embodiments in this application, they can be arranged and designed in various different configurations. All other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this application.

[0051] This application is described below with reference to the accompanying drawings and specific embodiments:

[0052] Please refer to Figure 1 The first aspect of this application provides a method for determining bottom hole flowing pressure based on multiphase flow, which is solved using the approach of infinitesimal element discretization, dynamic density, and numerical integration. Specifically, it includes:

[0053] S1. Establish a wellbore model. Starting from the wellhead, discretize the entire well section to be calculated into N continuous micro-elements along the wellbore downwards. Divide the entire wellbore model from the wellhead to the bottom of the well (or from the pump hanger depth to the bottom of the well) into several sufficiently small micro-elements. A sufficiently small micro-element is relative to the depth of an oil well, which is generally over 2000 meters, and may even reach six or seven thousand meters or more. The length of each micro-element is 1 meter. Then, the ratio Δ of the average pressure increment to the bottom hole flowing pressure... P / P, taking a certain well in this embodiment as an example, i.e. Δ P The error rate ( / P) is 1 / 2825 < 0.04%, which is sufficient for field use. Within each micro-element segment, the fluid properties and flow parameters can be considered uniform and stable, which is the basis for modeling. This step assumes that the wellbore data is known; relevant wellbore model data can be obtained beforehand or input by the user.

[0054] S2, for the currently calculated infinitesimal segment i According to its corresponding pressure P i and temperature T i Calculate the infinitesimal segment i Density of the mixture of oil, gas, and water; initially i =1; for each micro-element segment iBased on the current estimated pressure and temperature of this segment, the volume fraction and physical property parameters of each phase (oil, gas, and water) are calculated in real time, thereby accurately solving for this micro-element segment. i The density of the mixed fluid within the well. This process fully considers key factors such as the dissolved gas-oil ratio and wellbore friction. Based on the required calculation accuracy, the length of the micro-segment is set (e.g., 1 meter, 10 meters, etc.). In this embodiment, the micro-segment length is 1 meter, and N is taken as 2000 or higher; in this embodiment, N is 2825.

[0055] S3, Micro-segment based on current calculation i The density of the mixture, combined with infinitesimal elements i Pressure P i R of dissolved gas and oil S The relationship determines the infinitesimal segment. i Pressure P i .

[0056] S4, based on the infinitesimal segment i With adjacent micro-element segments i The pressure gradient relationship of +1 is solved using the fourth-order Runge-Kutta method for adjacent infinitesimal segments. i +1 pressure P i+1 , i = i +1; Starting from a known pressure point (such as wellhead oil pressure, pump outlet pressure), the high-precision numerical algorithm of fourth-order Runge-Kutta (RK4) is used, employing the multiphase pipe flow pressure gradient equation. Based on the pressure gradient relationship, the micro-element segment... i +1 pressure P i+1 for: .

[0057] S5, P i+1 The value assigned to P i Repeat the fourth-order Runge-Kutta method iteratively to solve for adjacent infinitesimal segments. i +1 pressure P i+1 until i =N; Iterate through each infinitesimal segment from segment 1 to segment N to calculate the pressure of the next adjacent infinitesimal segment until the integration reaches the target depth (bottom of the well), finally obtaining a high-precision bottom-hole flowing pressure value P. N For bottomhole flowing pressure calculations that require determining the target well depth from the wellhead or pump hanger depth, N iterative calculations are needed, thus requiring a method for iterative calculation.

[0058] The bottom hole flowing pressure obtained through steps S1-S5 of this application has high accuracy. Based on the above-mentioned high-accuracy bottom hole flowing pressure data, the technical solution of this invention fundamentally improves the data quality of oilfield development decisions, thereby generating the following significant industrial application value:

[0059] (1) It can provide a reliable data foundation for optimizing the production system of oil wells, ensure that oil wells operate under optimal conditions, improve recovery rate and reduce energy consumption.

[0060] (2) It can accurately evaluate the driving pressure difference between injection and production wells, providing a scientific basis for the evaluation and adjustment of water injection development effect and avoiding ineffective water injection.

[0061] (3) Its output results can be used as key input parameters for reservoir numerical simulation and pressure field analysis, providing core data support for the demonstration of well network deployment in new blocks and well spacing adjustment in old blocks, demonstrating reasonable well network density and well spacing, thereby improving the scientific nature of oilfield development design.

[0062] In some implementations, for first-order ordinary differential equations Given the initial conditions y ( x 0) =y 0, to calculate y exist Approximate value at y n+1 , This represents the well depth increment, i.e., the step size. The fourth-order Runge-Kutta method is used to solve for adjacent infinitesimal segments. i +1 pressure P i+1 Specifically:

[0063] S41, Solve for F( x n , y n )exist( x n , y n slope at ) k 1:

[0064]

[0065] S42, Solve for F( x n , y n )exist slope at k 2, which is equivalent to a preliminary estimate of the slope at the midpoint of the interval:

[0066]

[0067] S43, Repeatedly solve F( x n , y n )exist The slope at point is denoted as k 3. Estimate the slope at the midpoint of the interval again:

[0068]

[0069] S44, Solve for F( x n , y n )exist slope at k 4:

[0070]

[0071] Based on slope k 1. k 2. k 3. k 4. Solve for the average slope and multiply it by the well depth increment. Used to characterize pressure increment ;

[0072] Average pressure increment Substituting into the pressure gradient formula, we obtain the infinitesimal segment. i +1 pressure P i+1 ;

[0073] Among them, the function F( x n , y n () indicates bottom hole flowing pressure P with well depth h Relationship; h Indicates the depth of the well; n Indicates the sequence number of the micro-element segment.

[0074] The fourth-order Runge-Kutta method is more accurate than the Euler method (first-order method). Through four-fold slope calculation and weighted averaging, it has the advantages of high accuracy and good stability. In many practical problems, it can obtain relatively accurate numerical solutions with less computation. Its advantages are high accuracy (fourth-order convergence), good stability (applicable to most non-rigid equations), and ease of implementation.

[0075] In some implementations, the average slope is obtained by weighted averaging. Then the pressure increment for:

[0076]

[0077] In some implementations, the slope k 1. k 2. k 3. k 4 are respectively:

[0078]

[0079] In some implementations, the pressure increment Δ is determined. P At that time, if the daily liquid production is greater than or equal to 100m³ 3 When the pressure is / d, wellbore friction and pressure increment need to be considered. for:

[0080]

[0081] Where fw is the water content measured in the wellbore, % g The acceleration due to gravity is 9.8 N / kg; the pressure increment due to frictional resistance in the wellbore is... for:

[0082]

[0083] in, Pressure increment, MPa; Let m be the increment of well depth for the micro-element segment; g The acceleration due to gravity is 9.8 N / kg. The pressure increment representing frictional resistance, in MPa; f H is the Darcy friction coefficient; pump D is the flow path length, in meters; D is the pipe inner diameter, in meters. V The velocity inside the oil pipe is m / s.

[0084] In some implementations, the pressure increment is determined. If the daily liquid production is less than 100m³ 3 Pressure increment at / d for:

[0085]

[0086] Where fw is the water content measured in the wellbore, % g The acceleration due to gravity is 9.8 N / kg. ν mix (P i , fw) is the kinematic viscosity of the mixture, m 2 / s, for ; μ w , μ o , μ g The dynamic viscosities are those of water, crude oil, and natural gas, respectively. Pa·s .

[0087] In some implementations, the relationship between the density of the oil well mixture and its water cut, gas content, and depth is complex and can usually be approximated by the following formula: (micro-element segment) i The density of the mixture of oil, gas, and water is:

[0088]

[0089] in, ρ mix (P i , fw) represents the density of the wellbore mixture in this micro-element segment, in kg / m³. 3 ; P i The pressure of this micro-element segment is MPa; ρ w (P i () represents the density of water under the pressure of this infinitesimal element, in kg / m³. 3 fw represents the water content measured in the wellbore, in percentages (%). ρ 0(P i ( ) represents the density of the crude oil under the pressure of this micro-element segment, in kg / m³. 3 ;R S For the dissolved gas-oil ratio, m 3 / t; ρ g (P i () represents the density of natural gas under the pressure of this micro-element segment, in kg / m³. 3 .

[0090] In some implementations, the dissolved gas-oil ratio R S The value is:

[0091] If the infinitesimal segment i When the wellbore pressure is greater than the saturation pressure, R S The original dissolved gas-oil ratio of the reservoir;

[0092] If the infinitesimal segment i When the wellbore pressure is less than the saturation pressure, R S for:

[0093]

[0094] Where C1, C2, and C3 represent the constants for the empirical fit of the Vasquez-Beggs empirical formula; T i This indicates the temperature of the infinitesimal segment, in °C. API Indicates the density of crude oil. .like API≤ 30 (heavy oil), C1, C2, and C3 are 0.0362, 1.0937, and 25.724 respectively; when API>30 (light oil), C1, C2, and C3 are 0.0178, 1.1870, and 23.931, respectively.

[0095] A second aspect of this application provides a readable storage medium storing a computer program. When executed, the computer program performs the bottom hole pressure determination method based on multiphase flow as described in any of the above embodiments. If the bottom hole pressure determination method based on multiphase flow is implemented as a software functional unit and sold or used as an independent product, it can be stored in a readable storage medium. Based on this understanding, all or part of the processes of the methods described in the above embodiments can also be implemented by a computer program instructing related hardware. The computer program can be stored in a readable storage medium. When executed by a processor, the computer program can implement the steps of each method in the above embodiments. When the computer program is executed by a processor, the specific implementation of each step and the resulting technical effects are the same as in the aforementioned method embodiments. For the sake of brevity, any parts not mentioned in this embodiment can be referred to the corresponding content in the aforementioned method embodiments.

[0096] The wellbore model created in step S1 and the processes executed in steps S1-S5 are software-based in the form of a Matlab program and stored in a readable storage medium. When the computer program is executed, it performs the bottom hole flowing pressure determination method based on multiphase flow as described above. This method is applicable to three types of oil and gas wells in the oilfield (such as flowing wells, screw pump wells, and pumping unit wells) and can quickly solve the bottom hole flowing pressure in these three types of oil and gas wells.

[0097] A third aspect of this application provides a device for determining bottom hole flowing pressure based on multiphase flow, including a memory, a processor, and a terminal program stored in the memory and executable in the processor. The terminal program includes an input module, a calculation module, and an output module.

[0098] The input module is used to acquire wellbore structure data, production data, and formation fluid PVT property data. The input module can acquire relevant parameters of the wellbore model or necessary parameters input by the user, including: wellbore structure data (tubing inner diameter, well depth, vertical depth curve), production data (fluid production, gas production, water production, water cut, gas-oil ratio), and formation fluid PVT property data (crude oil density, natural gas relative density, dissolved gas-oil ratio as a function of pressure, oil-water viscosity, etc.).

[0099] The calculation module is used to receive data from the input module and execute the corresponding steps using the above-mentioned method for determining bottom hole pressure based on multiphase flow. The calculation module can be divided into multiple parts according to the corresponding steps, such as the modeling part for step S1, the part for calculating the mixed liquid density for step S2, the part for solving the pressure for step S3, the part for solving the RK4 method for step S4, and the loop execution part containing the above steps S1-S4 (corresponding to step S5).

[0100] The output module is used to obtain the output results from the calculation module and output graphs or tables. For example, it can save the bottomhole flowing pressure data at the target well depth calculated by the software as an Excel file, display the results as curves, and provide the polynomial formula and goodness-of-fit R-squared for fitting the relevant curves. 2 .

[0101] In some embodiments, the aforementioned bottom hole pressure determination device based on multiphase flow can be a desktop computer, laptop, industrial computer, handheld computer, tablet computer, or other mobile terminal, as well as a cloud server or other computer equipment, and is not limited to any particular operating system. Those skilled in the art will understand that the above does not constitute a limitation on the bottom hole pressure determination device based on multiphase flow, and may include more or fewer components, or combinations of certain components, or different components. For example, the X device may also include input devices, output devices, network access devices, buses, etc.

[0102] Based on the above method, a computational software written in MATLAB code was developed and verified by examples.

[0103] The field data was taken from well Sa106 in the ST block of the Junggar Basin. This well began fracturing and self-flowing production on a certain day, and oil was encountered 5 days later. The vertical depth of the oil layer in the fracturing section was 2808m. 70 days later, a test at a vertical depth of 2825m showed a flowing pressure of 26.54MPa, a casing pressure of 1.5MPa, a water cut of 35%, and a surface density of 885kg / m³. 3 The crude oil compressibility coefficient is 8.8 × 10⁻⁶. -4 MPa -1 The geothermal gradient is 2.675℃ / 100m, and the surface density of water is 1000kg / m³. 3 The compressibility of water is 4.5 × 10⁻⁶. -10 MPa -1 , , g =9.81 m / s 2 .

[0104] By inputting the relevant parameters into the software and iterating with RK4, the bottom hole flowing pressure at the target well depth of 2825m was calculated to be 26.56MPa. Compared with the measured value, the error was only 0.02MPa, which meets the high precision requirements of oil and gas fields.

[0105] Please refer to Figure 2 To verify the accuracy of this calculation method, in addition to the example well, six other flowing pressure test wells in the ST block were provided for comparison of measured and calculated values. The program inputs the relevant parameters for each well and calculates the bottomhole flowing pressure at the target well depth. A comparison with the measured values ​​is detailed in Table 1. The calculation results show that the absolute error averages 0.39 MPa, and the average error is 1.42%, which is very small and applicable to oil and gas field practice. Figure 3 The graph shows the relationship between well depth and bottom hole flowing pressure at 100-meter intervals in a single well. The graph indicates that the method used has a high degree of fit, closely approximating the original data points. Specifically, the empirical formula obtained by fitting the bottom hole flowing pressure of this well using software is as follows:

[0106] .

[0107] Table 1 Examples of Bottomhole Flow Pressure Calculation in ST Block

[0108]

[0109] The example of well Sa106 mentioned above is a concrete test data demonstration. In addition, the average error between the calculated and measured data of the seven wells in the ST block provided in Table 1 is less than 1.5%.

[0110] Regarding the specific implementation methods of this application, it should be noted that:

[0111] In the description of this application, the terms "wellhead," "well bottom," "downward along the wellbore," "well depth," and "well depth increment," etc., indicate the position or parameter relationships based on the actual wellbore structure and the calculation logic settings. They are only for the convenience of describing the well bottom pressure determination method and simplifying the description of this application, and do not indicate or imply that the constructed wellbore model or micro-segment division must have a specific orientation, be arranged in a specific sequence, or be operated. Therefore, they should not be construed as limitations on this application. All parameter indications related to well depth and micro-segments are only used to explain the relative positional relationship and pressure transmission relationship between micro-segments under a certain calculation process. If the calculation starting point (such as different wellbore models) or the micro-segment sequence number changes, the parameter indication will also be adjusted accordingly.

[0112] In the description of this application, the terms "variable of the function," "pressure of the infinitesimal segment," and "temperature of the infinitesimal segment," etc., indicate parameter correspondences based on the multiphase flow numerical calculation logic. These correspondences are merely for the convenience of describing the iterative solution process and simplifying the description, and do not indicate or imply that these parameters must have specific variable symbols or a specific calculation order (e.g., must be calculated from...). i =1 to start iteration) to build associations, therefore should not be construed as a limitation of this application. All parameter-related instructions are only used to explain the computational dependencies between variables within a certain iteration period (e.g., P i for P i+1 (Based on the calculation), if the variable symbol is replaced, the parameter indication will also be adjusted accordingly.

[0113] In the description of this application, the use of terms such as "some embodiments," "optional embodiments," "example," "specific example," "optional example," or "optional embodiment," etc., indicates that a specific feature, structure, material, or characteristic described in connection with that embodiment or example is included in at least one embodiment or example of this application, but does not imply that these embodiments illustrate and describe all possible forms of the invention. In this specification, the illustrative expressions of the above terms do not necessarily refer to the same embodiment or example. Moreover, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in one or more embodiments or examples. Furthermore, those skilled in the art can combine and integrate the different embodiments or examples described in this specification.

[0114] The present invention has been described in detail above with reference to specific embodiments and exemplary examples. The above description is exemplary and not exhaustive, and is not limited to the disclosed embodiments; the above description should not be construed as a limitation of the present invention. Technical solutions between various embodiments can be combined with each other, but must be based on the ability of those skilled in the art to implement them. When the combination of technical solutions is contradictory or cannot be implemented, it should be considered that such a combination of technical solutions does not exist and is not within the scope of protection claimed in this application. Although embodiments of the present application have been shown and described, various changes, modifications, substitutions, and variations can be made to these embodiments without departing from the principles and spirit of the present application. Those skilled in the art will understand that various other specific changes and combinations of embodiments based on the technical teachings disclosed in this application, without departing from the essence of the present application, are still within the scope of protection defined by the claims of the present invention and their equivalent technical solutions.

Claims

1. A method for determining bottom hole flowing pressure based on multiphase flow, characterized in that, include: Establish a wellbore model, starting from the wellhead and moving downwards along the wellbore, discretize the entire well section to be calculated into N continuous micro-elements; For the currently calculated infinitesimal segment i Let P be the pressure corresponding to it. i And the temperature is set to T i Calculate the infinitesimal segment i Density of the mixture of oil, gas, and water; initially i =1; Based on the currently calculated micro-element segments i The density of the mixture, combined with infinitesimal elements i Pressure P i R of dissolved gas and oil S The relationship determines the infinitesimal segment. i Pressure P i ; according to Micro segment i With adjacent micro-element segments i The pressure gradient relationship of +1 is solved using the fourth-order Runge-Kutta method for adjacent infinitesimal segments. i +1 pressure P i+1 , i = i +1; P i+1 The value assigned to P i Repeat the fourth-order Runge-Kutta method to iteratively solve for adjacent infinitesimal segments. i +1 pressure P i+1 until i =N.

2. The method for determining bottom hole flowing pressure based on multiphase flow according to claim 1, characterized in that, The fourth-order Runge-Kutta method is used to solve adjacent infinitesimal segments. i +1 pressure P i+1 Specifically: Solve for F( x n , y n )exist( x n , y n slope at ) k 1; Solve for F( x n , y n )exist( x n +Δ h / 2, y n +Δ h / 2* k slope at 1) k 2; Repeatedly solve F( x n , y n )exist( x n +Δ h / 2, y n +Δ h / 2* k The slope at point 2) is denoted as k 3; Solve for F( x n , y n )exist( x n +Δ h , y n +Δ h * k 3) Slope k 4; Based on slope k 1. k 2. k 3. k 4. Solve for the average slope and multiply it by the well depth increment Δ. h Used to characterize pressure increment Δ P ; The average pressure increment Δ P Substituting into the pressure gradient formula, we obtain the infinitesimal segment. i +1 pressure P i+1 ; Among them, the function F( x n , y n () indicates bottom hole flowing pressure P with well depth h Relationship; h Indicates the depth of the well; n Indicates the sequence number of the micro-element segment.

3. The method for determining bottom hole flowing pressure based on multiphase flow according to claim 2, characterized in that, The pressure increment Δ P for: 。 4. The method for determining bottom hole flowing pressure based on multiphase flow according to claim 2, characterized in that, The slope k 1. k 2. k 3. k 4 are respectively: 。 5. The method for determining bottom hole flowing pressure based on multiphase flow according to any one of claims 2-4, characterized in that, Determine the pressure increment Δ P At that time, if the daily liquid production is greater than or equal to 100m³ 3 When / d, the pressure increment Δ P for: Where fw is the water content measured in the wellbore, % g The acceleration due to gravity is 9.8 N / kg; the pressure increment of the wellbore friction resistance is Δ. P f for ρ mix (P i , fw) represents the density of the wellbore mixture in this micro-element segment, in kg / m³. 3 ; P i The pressure of this micro-element segment is MPa; ρ w (P i () represents the density of water under the pressure of this infinitesimal element, in kg / m³. 3 ; f H is the Darcy friction coefficient; pump D is the flow path length, in meters; D is the pipe inner diameter, in meters. V The velocity inside the oil pipe is m / s.

6. The method for determining bottom hole flowing pressure based on multiphase flow according to any one of claims 2-4, characterized in that, Determine the pressure increment Δ P If the daily liquid production is less than 100m³ 3 When / d, the pressure increment Δ P for: Where fw is the water content measured in the wellbore, % g The acceleration due to gravity is 9.8 N / kg. ν mix (P i , fw) is the kinematic viscosity of the mixture, m 2 / s, for ; μ w , μ o , μ g The dynamic viscosities are those of water, crude oil, and natural gas, respectively. Pa·s .

7. The method for determining bottom hole flowing pressure based on multiphase flow according to claim 1, characterized in that, The micro segment i The density of the mixture of oil, gas, and water is: in, ρ mix (P i , fw) represents the density of the wellbore mixture in this micro-element segment, in kg / m³. 3 ; P i The pressure of this micro-element segment is MPa; ρ w (P i () represents the density of water under the pressure of this infinitesimal element, in kg / m³. 3 fw represents the water content measured in the wellbore, in percentages (%). ρ 0(P i ( ) represents the density of the crude oil under the pressure of this micro-element segment, in kg / m³. 3 ;R S For the dissolved gas-oil ratio, m 3 / t; ρ g (P i () represents the density of natural gas under the pressure of this micro-element segment, in kg / m³. 3 .

8. The method for determining bottom hole flowing pressure based on multiphase flow according to claim 7, characterized in that, The dissolved gas-oil ratio R S The value is: If the infinitesimal segment i When the wellbore pressure is greater than the saturation pressure, R S The original dissolved gas-oil ratio of the reservoir; If the infinitesimal segment i When the wellbore pressure is less than the saturation pressure, R S for: Where C1, C2, and C3 represent the constants for the empirical fit of the Vasquez-Beggs empirical formula; T i This indicates the temperature of the infinitesimal segment, in °C. API This indicates the density of the crude oil.

9. A readable storage medium storing a computer program, characterized in that, When the computer program is executed, it performs the bottom hole flowing pressure determination method based on multiphase flow as described in any one of claims 1-8.

10. A device for determining bottom hole flowing pressure based on multiphase flow, comprising a memory, a processor, and a terminal program stored in the memory and executable in the processor, characterized in that, The terminal program includes an input module, a calculation module, and an output module; The input module is used to acquire wellbore structure data, production data, and formation fluid PVT property data; The calculation module is used to receive data from the input module and perform the corresponding steps using the bottom hole flowing pressure determination method based on multiphase flow as described in any one of claims 1-8. The output module is used to obtain the output results of the calculation module and output a graph or table.

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