Gas-liquid two-phase flow pressure determination method and device suitable for coiled tubing

Abstract

The invention provides a gas-liquid two-phase flow pressure determining method and device suitable for a continuous pipe. The gas-liquid two-phase flow pressure determining method suitable for the continuous pipe comprises the steps that the continuous pipe is divided into a plurality of parts according to preset length intervals; determining the positions of the plurality of parts, hole deviation angles and internal fluid flowing directions; in a pre-generated pressure calculation model library, selecting a pressure calculation model of a corresponding part according to the position, the hole drift angle and the internal fluid flowing direction; and determining the pressure of the corresponding part according to the selected pressure calculation model. According to the method, the whole wellbore is reasonably divided into a plurality of well sections according to different flow working conditions, the optimal gas-liquid two-phase pressure calculation model is generated for each well section, and finally the pressure consumption calculation of the whole wellbore better conforming to the actual working conditions is obtained.

Description

Technical Field

[0001] The present invention relates to the field of petroleum development, and in particular to a method and device for determining the pressure of a gas-liquid two-phase flow applicable to a coiled tubing. Background Art

[0002] Gas-liquid two-phase flow models are widely used in drilling and workover operations such as coiled tubing gas lift, wellbore cleaning, and bridge plug drilling. Before and during operations, it is necessary to analyze the pressure loss generated by the operating fluid in the wellbore and calculate the wellbore pressure distribution to avoid complex situations such as formation leakage and wellbore overflow. To improve computational efficiency in engineering, the gas-liquid two-phase flow pressure drop models used are mostly classic empirical / semi-empirical models, and each model has its own scope of application. Currently, when calculating the pressure distribution throughout the wellbore, only one of these models is used to simulate the pressure of the entire wellbore. However, the working fluid in the entire wellbore may simultaneously experience multiple operating conditions, such as upward / downward flow in vertical sections, upward / downward flow in inclined sections, and horizontal flow. A single model can only meet one of these operating conditions, resulting in a certain error between the calculated results and actual field data. Summary of the Invention

[0003] The embodiments of the present invention provide a method and apparatus for determining the gas-liquid two-phase flow pressure in coiled tubing. These methods rationally divide the entire wellbore into multiple sections based on different flow conditions, and generate an optimal gas-liquid two-phase pressure calculation model for each section. Ultimately, this results in a pressure loss calculation for the entire wellbore that better reflects actual operating conditions.

[0004] On the one hand, an embodiment of the present invention provides a method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing.

[0005] dividing the coiled tube into a plurality of sections at intervals of preset lengths;

[0006] determining the positions of the plurality of sections, the well inclination angles, and the directions of fluid flow therein;

[0007] In a pre-generated pressure calculation model library, a corresponding pressure calculation model is selected according to the position, the well inclination angle, and the internal fluid flow direction;

[0008] The pressure of the corresponding part is determined according to the selected pressure calculation model.

[0009] In some embodiments of the present invention, a method for determining the pressure of a gas-liquid two-phase flow applicable to a coiled tubing further includes: generating the pressure calculation model library;

[0010] The generating of the pressure calculation model library comprises:

[0011] Calculating a first hydrostatic pressure drop according to the liquid holdup of a well section where the well inclination angle is less than a preset threshold;

[0012] respectively calculating a first friction pressure drop and a second friction pressure drop of the bubble flow and the mist flow in a well section where the well inclination angle is less than the preset threshold;

[0013] generating a first pressure calculation model according to the first hydrostatic pressure drop, the first friction pressure drop, and the second friction pressure drop;

[0014] Calculating a second hydrostatic pressure drop according to the liquid holdup of a well section where the well inclination angle is greater than a preset threshold;

[0015] respectively calculating the third friction pressure drop, the fourth friction pressure drop, and the fifth friction pressure drop of the bubble flow, the slug flow, and the annular flow in the well section where the well inclination angle is less than the preset threshold;

[0016] generating a second pressure calculation model according to the second hydrostatic pressure drop, the third friction pressure drop, the fourth friction pressure drop, and the fifth friction pressure drop;

[0017] The pressure calculation model library is generated according to the first pressure calculation model and the second pressure calculation model.

[0018] In some embodiments of the present invention, selecting a corresponding portion of the pressure calculation model from the pre-generated pressure calculation model library according to the position, the well inclination angle, and the internal fluid flow direction includes:

[0019] When the portion is located above the wellbore surface, the first pressure calculation model is selected.

[0020] In some embodiments of the present invention, selecting a corresponding portion of the pressure calculation model from the pre-generated pressure calculation model library according to the position, the well inclination angle, and the internal fluid flow direction further includes:

[0021] When the well inclination angle of the portion is less than the preset threshold and the internal fluid flows in an upward direction, the first pressure calculation model is selected.

[0022] In some embodiments of the present invention, selecting a corresponding portion of the pressure calculation model from the pre-generated pressure calculation model library according to the position, the well inclination angle, and the internal fluid flow direction further includes:

[0023] When the well inclination angle of the portion is less than the preset threshold and the internal fluid flows in a downward direction, the second pressure calculation model is selected.

[0024] In some embodiments of the present invention, selecting a corresponding portion of the pressure calculation model from the pre-generated pressure calculation model library according to the position, the well inclination angle, and the internal fluid flow direction further includes:

[0025] When the well inclination angle of the portion is greater than the preset threshold, the second pressure calculation model is selected.

[0026] In another aspect, an embodiment of the present invention provides a device for determining the pressure of a gas-liquid two-phase flow in a coiled tubing, comprising:

[0027] a coiled tubing dividing module, configured to divide the coiled tubing into a plurality of sections at intervals of preset lengths;

[0028] a part parameter determination module, for determining the positions of the plurality of parts, the well inclination angles, and the directions of fluid flow therein;

[0029] A model selection module is used to select a corresponding pressure calculation model from a pre-generated pressure calculation model library according to the position, the well inclination angle and the internal fluid flow direction;

[0030] The pressure calculation module is used to determine the pressure of the corresponding part according to the selected pressure calculation model.

[0031] In some embodiments of the present invention, a gas-liquid two-phase flow pressure determination device applicable to a coiled tubing further includes: a model library generation module for generating the pressure calculation model library;

[0032] The model library generation module includes:

[0033] A first hydrostatic pressure drop calculation unit is configured to calculate a first hydrostatic pressure drop according to the liquid holdup of a well section where the well inclination angle is less than a preset threshold;

[0034] The first and second friction pressure drop calculation units are used to respectively calculate the first friction pressure drop and the second friction pressure drop of the bubble flow and the mist flow in the well section where the well inclination angle is less than the preset threshold;

[0035] a first pressure calculation model generating unit, configured to generate a first pressure calculation model according to the first hydrostatic pressure drop, the first friction pressure drop, and the second friction pressure drop;

[0036] A second hydrostatic pressure drop calculation unit is configured to calculate a second hydrostatic pressure drop according to the liquid holdup of a well section where the well inclination angle is greater than a preset threshold;

[0037] The third, fourth and fifth friction pressure drop calculation units are used to respectively calculate the third friction pressure drop, the fourth friction pressure drop and the fifth friction pressure drop of the bubble flow, the slug flow and the annular flow in the well section where the well inclination angle is less than the preset threshold;

[0038] a second pressure calculation model generating unit, configured to generate a second pressure calculation model according to the second hydrostatic pressure drop, the third friction pressure drop, the fourth friction pressure drop, and the fifth friction pressure drop;

[0039] A model library generating unit is configured to generate the pressure calculation model library according to the first pressure calculation model and the second pressure calculation model.

[0040] In some embodiments of the present invention, the model selection module includes:

[0041] The model selects the first unit, which is used to select the first pressure calculation model when the position of the portion is above the wellbore surface.

[0042] In some embodiments of the present invention, the model selection module further includes:

[0043] The model selection second unit is used to select the first pressure calculation model when the well inclination angle of the portion is less than the preset threshold and the internal fluid flow direction is upward flow.

[0044] In some embodiments of the present invention, the model selection module further includes:

[0045] The model selection third unit is used to select the second pressure calculation model when the well inclination angle of the portion is less than the preset threshold and the internal fluid flow direction is downward flow.

[0046] In some embodiments of the present invention, the model selection module further includes:

[0047] The fourth model selection unit is used to select the second pressure calculation model when the well inclination angle of the portion is greater than the preset threshold.

[0048] In a third aspect, the present invention provides a computer program product, comprising a computer program / instruction, which, when executed by a processor, implements the steps of a method for determining the pressure of a gas-liquid two-phase flow applicable to a coiled tubing.

[0049] In a fourth aspect, the present invention provides an electronic device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the program, the processor implements the steps of a method for determining the pressure of a gas-liquid two-phase flow applicable to a continuous pipe.

[0050] In a fifth aspect, the present invention provides a computer-readable storage medium having a computer program stored thereon, which, when executed by a processor, implements the steps of a method for determining the pressure of a gas-liquid two-phase flow applicable to a coiled tubing.

[0051] As can be seen from the foregoing description, embodiments of the present invention provide a method and apparatus for determining the pressure of a gas-liquid two-phase flow in a coiled tubing. The corresponding method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing includes: dividing the coiled tubing into multiple sections at predetermined length intervals; determining the positions, well inclination angles, and fluid flow directions within the multiple sections; selecting a pressure calculation model for the corresponding section from a pressure calculation model library based on the position, well inclination angle, and fluid flow direction within the section; and determining the pressure of the corresponding section based on the selected pressure calculation model.

[0052] The present invention rationally divides the entire wellbore into multiple sections according to different flow conditions, and generates an optimal gas-liquid two-phase pressure calculation model for each section, ultimately obtaining a pressure loss calculation for the entire wellbore that is more in line with actual conditions. BRIEF DESCRIPTION OF THE DRAWINGS

[0053] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the following briefly introduces the drawings required for use in the embodiments or the description of the prior art. Obviously, the drawings described below are some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying any creative work.

[0054] Figure 1 A schematic flow chart of a method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing provided in an embodiment of the present invention;

[0055] Figure 2 This is a schematic diagram of a second flow chart of a method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing provided in an embodiment of the present invention;

[0056] Figure 3 Schematic diagram of the flow of step 500 in a method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing provided in an embodiment of the present invention;

[0057] Figure 4 Schematic diagram of the flow of a method for calculating the hydrostatic pressure gradient of the first pressure calculation model provided in an embodiment of the present invention;

[0058] Figure 5 1 is a flow chart of step 500 in a method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing provided in an embodiment of the present invention;

[0059] Figure 6 1 is a second flow chart of step 500 in a method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing provided in an embodiment of the present invention;

[0060] Figure 73 is a schematic diagram of a third flow chart of step 500 in a method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing provided in an embodiment of the present invention;

[0061] Figure 8 4 is a schematic diagram of a fourth flow chart of step 500 in a method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing provided in an embodiment of the present invention;

[0062] Figure 9 A schematic diagram of an optimization criterion for a gas-liquid two-phase flow model provided in an embodiment of the present invention;

[0063] Figure 10 Schematic diagram of the wellbore structure for coiled tubing nitrogen injection and liquid drainage operations in a specific application example of the present invention;

[0064] Figure 11 Schematic diagram of the wellbore structure of a test well in a specific application example of the present invention;

[0065] Figure 12 Schematic diagram of various flow conditions under horizontal well conditions in a specific application example of the present invention;

[0066] Figure 13 This is a schematic diagram of the result of dividing the well profile into micro-element segments in a specific application example of the present invention;

[0067] Figure 14 Schematic diagram of comparison between calculation results of various algorithms and experimental values ​​in specific application examples of the present invention;

[0068] Figure 15 Schematic diagram of relative errors between the algorithm results and the test results in a specific application example of the present invention;

[0069] Figure 16 A schematic diagram of the calculation result of step S4 in a specific application example of the present invention;

[0070] Figure 17 This is a second schematic diagram of the calculation result of step S4 in a specific application example of the present invention;

[0071] Figure 18 Schematic diagram of a structure of a gas-liquid two-phase flow pressure determination device applicable to a coiled tubing in an embodiment of the present invention;

[0072] Figure 19 Schematic diagram of a second structure of a gas-liquid two-phase flow pressure determination device applicable to a coiled tubing in an embodiment of the present invention;

[0073] Figure 20 Schematic diagram of the structure of the model library generation module 50 in an embodiment of the present invention;

[0074] Figure 21A schematic structural diagram of the model selection module 20 in an embodiment of the present invention;

[0075] Figure 22 2 is a schematic diagram of a second structure of the model selection module 20 in an embodiment of the present invention;

[0076] Figure 23 2 is a third structural diagram of the model selection module 20 in an embodiment of the present invention;

[0077] Figure 24 4 is a schematic diagram of the structure of the model selection module 20 in the embodiment of the present invention;

[0078] Figure 25 It is a schematic diagram of the physical structure of an electronic device provided by an embodiment of the present invention. DETAILED DESCRIPTION

[0079] To make the objectives, technical solutions, and advantages of the embodiments of the present invention more clear, the technical solutions in the embodiments of the present invention will be clearly and completely described below in conjunction with the accompanying drawings of the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. All other embodiments obtained by ordinary technicians in this field based on the embodiments of the present invention without making any creative efforts shall fall within the scope of protection of the present invention.

[0080] It should be noted that the terms "including" and "having" and any variations thereof in the specification and claims of this application and the above-mentioned drawings are intended to cover non-exclusive inclusions. For example, a process, method, system, product or device that includes a series of steps or units is not necessarily limited to those steps or units clearly listed, but may include other steps or units that are not clearly listed or are inherent to these processes, methods, products or devices. The embodiments in this application and the features described in the embodiments may be combined with each other unless there is a conflict. The present application will be described in detail below with reference to the drawings and in conjunction with the embodiments.

[0081] The acquisition, storage, use, and processing of data in the technical solution of this application comply with relevant laws and regulations.

[0082] In existing technologies, coiled tubing operations (CTO) use a single model to simulate the entire wellbore flow, analyzing the pressure drop generated by the working fluid in the wellbore / annulus. However, due to the complexity of wellbore flow conditions, a single flow model is unable to effectively simulate the entire wellbore flow analysis. Therefore, there is an urgent need to address the problem that a single gas-liquid two-phase flow model only applies to a single flow condition and is difficult to match with the multiple flow conditions that exist in actual wellbores.

[0083] Based on this, see Figure 1An embodiment of the present invention provides a method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing, the method comprising:

[0084] Step 100: Dividing the coiled tubing into a plurality of sections at predetermined length intervals;

[0085] Step 200: Determine the positions of the multiple parts, the well inclination angle, and the direction of fluid flow therein;

[0086] Step 300: Selecting a corresponding pressure calculation model from a pre-generated pressure calculation model library according to the position, the well inclination angle, and the internal fluid flow direction;

[0087] Step 400: Determine the pressure of the corresponding part according to the selected pressure calculation model.

[0088] As can be seen from the foregoing description, an embodiment of the present invention provides a method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing, comprising: dividing the coiled tubing into multiple sections at predetermined length intervals; determining the positions, well inclination angles, and fluid flow directions within the multiple sections; selecting, from a pressure calculation model library, a pressure calculation model corresponding to the section based on the position, well inclination angle, and fluid flow direction within the section; and determining the pressure of the corresponding section based on the selected pressure calculation model.

[0089] The proposed method first verifies the optimal model under various flow conditions using experimental data, enabling accurate calculation of flow pressure loss for each segment. Building on this foundation, the proposed multi-model combined optimization method for calculating gas-liquid two-phase flow can rationally divide the entire wellbore into multiple sections based on different flow conditions. Each section uses the optimal gas-liquid two-phase model to ultimately calculate the pressure loss for the entire wellbore.

[0090] In step 100 , the coiled tubing may be divided into a plurality of sections or micro-segments at a preset length interval of 30 meters.

[0091] For step 200, after dividing the micro-segments, they are sorted from the wellhead downwards, that is, each micro-segment from the wellhead to the bottom of the well is numbered [0, 1, 2, 3, ... N-1]. The necessary parameters required for each micro-segment are calculated separately, including the average well inclination angle, average azimuth angle, hydraulic diameter, flow direction, etc. Specifically:

[0092] Well inclination refers to the angle of the wellbore axis relative to the vertical. It is understood that changes in well inclination affect the flow pattern and pressure distribution of the fluid in the well, as well as the difficulty of the drilling operation.

[0093] The mean azimuth is the direction of the wellbore trajectory in the horizontal plane. It is usually measured clockwise from the north as the reference to the projection of the wellbore trajectory.

[0094] The hydraulic diameter is a parameter used in fluid mechanics calculations for non-circular pipes (such as annular spaces). It is four times the area of ​​the fluid flow cross-section divided by the wetted perimeter (the circumference of the fluid contact). For a circular pipe, the hydraulic diameter D h Equal to the inner diameter of the pipe. For the specific calculation method, see formula (1):

[0095]

[0096] The hydraulic diameter is used to describe the characteristics of the annulus (the circular space between the drill pipe and the wellbore wall) and to calculate the fluid flow rate, pressure loss and flow pattern in the annulus.

[0097] In some embodiments of the present invention, see Figure 2 , a method for determining the pressure of a gas-liquid two-phase flow applicable to a coiled tubing, further comprising:

[0098] Step 500: Generate the pressure calculation model library;

[0099] The classical gas-liquid two-phase flow model is established under certain experimental conditions, and its scope of application is subject to certain limitations. In addition, there are multiple classical models that can be used under the same flow conditions. Therefore, the effects of various gas-liquid two-phase flow models should be evaluated under the same flow conditions, and the error between the test well data and the calculated model results should be calculated. With the minimum error as the evaluation criterion, the optimal gas-liquid two-phase flow model under the corresponding conditions should be selected to provide a basis for the next step of gas-liquid two-phase flow multi-model combination optimization.

[0100] Preferably, the pressure drop gradient formula of the gas-liquid two-phase flow model is:

[0101]

[0102] in, is the total pressure drop; The friction pressure drop caused by the shear stress on the pipe wall accounts for 5-20% of the total pressure drop. τ is the shear stress, N / m 2 ; d is the hydraulic diameter of the flow channel, m, A is the cross-sectional area of ​​the flow channel, m 2 ; ρgsinθ is the hydrostatic pressure / head loss, accounting for 80-95% of the total pressure drop, ρ is the mixture density, kg / m 3 ; g is the acceleration due to gravity, m / s 2 ;θ is the angle between the pipe and the horizontal direction, rad; is the acceleration pressure drop; v is the fluid flow rate, m / s;

[0103] It is understandable that the core of the calculation of hydrostatic pressure drop lies in the accurate calculation of liquid holdup / gas holdup. In this application, different models have different calculation criteria and methods.

[0104]

[0105] ρ M_Slip =ρ L ·H L +ρ G ·H G (4)

[0106] Where: ρ M_Slip is the liquid volume fraction, dimensionless; ρ L is the density of the liquid, kg / m 3 ρ G is the density of the gas, kg / m 3 ;H L is the liquid holdup, dimensionless; H G is the air holdup rate, dimensionless.

[0107] The friction pressure gradient is calculated using the following formula: friction coefficient f, fluid velocity v. Different models use different calculation methods.

[0108]

[0109] Where f is the flow friction coefficient, dimensionless;

[0110] Next, see Figure 3 , step 500 includes:

[0111] Step 501: Calculating a first hydrostatic pressure drop according to the liquid holdup of a well section where the well inclination angle is less than a preset threshold;

[0112] Specifically, the calculation method for calculating the liquid holdup of the first hydrostatic pressure drop is shown in formula (6):

[0113]

[0114] Where V slip is the slip velocity of gas-liquid phase, m / s; V M is the flow rate of the mixture, m / s; V SL is the superficial velocity of the liquid phase, m / s;

[0115] Step 502: Calculating the first friction pressure drop and the second friction pressure drop of the bubble flow and the mist flow in the well section where the well inclination angle is less than the preset threshold respectively;

[0116] Specifically, in step 502, the friction pressure drop is calculated using the split flow method:

[0117] For bubbly flow, the following formula is used for calculation:

[0118]

[0119]

[0120] Where f is the total friction coefficient, dimensionless; f1 is the Moody friction coefficient, dimensionless; f2 can be obtained through literature search, dimensionless; ρ L is the density of the liquid, kg / m 3 ; V SL is the liquid phase velocity, m / s; V M is the flow velocity of the mixture, m / s; d is the hydraulic diameter of the flow channel, m.

[0121] Preferably, in step 502, the friction pressure drop can also be calculated using formula (7) and formula (8) for the slug flow.

[0122] For mist flow, the following formula is used for calculation:

[0123]

[0124] Where f is the Moody friction coefficient, dimensionless, and ρ G is the density of the gas, kg / m 3 ; V SG is the gas velocity, m / s, and d is the hydraulic diameter of the flow channel, m.

[0125] Step 503: Generate a first pressure calculation model according to the first hydrostatic pressure drop, the first friction pressure drop, and the second friction pressure drop;

[0126] It should be noted that the first pressure calculation model defines the dimensionless slip velocity Where, σ L is the surface tension of the liquid, N / m; through indoor experiments, the empirical formula of the dimensionless slip velocity S under different flow patterns is established to solve the slip velocity V slip , further use formula (6) to calculate the liquid holdup. Finally, the mixed density and hydrostatic pressure drop are calculated. The calculation process of the hydrostatic pressure drop of the first pressure calculation model is as follows: Figure 4 shown.

[0127] Step 504: Calculate a second hydrostatic pressure drop according to the liquid holdup of the well section where the well inclination angle is greater than a preset threshold;

[0128] For step 503, the liquid holdup calculation formula is as follows:

[0129]

[0130] Among them, C1, C2, and C3 are the empirical coefficients of liquid holdup, which are dimensionless; is the angle between the pipe and the horizontal direction, rad;

[0131] The liquid holdup under the corresponding flow direction and flow pattern is calculated using formula (10), and finally the two-phase slip density ρ is obtained by formula (4): M_Slip , substituted into formula (3) to finally obtain the hydrostatic pressure gradient (the accurate calculation of the hydrostatic pressure drop gradient determines the error in the calculation of the entire wellbore pressure drop).

[0132] Step 505: Calculating the third friction pressure drop, the fourth friction pressure drop, and the fifth friction pressure drop of the bubble flow, the slug flow, and the annular flow in the well section where the well inclination angle is less than the preset threshold, respectively;

[0133] For bubbly flow and slug flow, the friction pressure drop is calculated using formula (11):

[0134]

[0135] Where: f is the Moody friction coefficient, dimensionless; ρ M_Slip is the average density without slip, kg / m 3 ; V m is the mixed liquid flow rate, m / s; d is the inner diameter of the pipe, m.

[0136] For annular flow:

[0137]

[0138] Where: ρ M_NSlip Average density without slip, kg / m 3 ; V m Mixed liquid flow rate, m / s; d pipe inner diameter, m; f c is the friction coefficient, dimensionless:

[0139] Step 506: Generate a second pressure calculation model according to the second hydrostatic pressure drop, the third friction pressure drop, the fourth friction pressure drop, and the fifth friction pressure drop;

[0140] Step 507: Generate the pressure calculation model library according to the first pressure calculation model and the second pressure calculation model.

[0141] In some embodiments of the present invention, see Figure 5 , step 200 includes:

[0142] Step 201: When the position of the portion is above the wellbore surface, the first pressure calculation model is selected.

[0143] In some embodiments of the present invention, see Figure 6 , step 200 further includes:

[0144] Step 202: When the well inclination angle of the portion is less than the preset threshold and the internal fluid flow direction is upward, the first pressure calculation model is selected.

[0145] Preferably, the preset threshold in step 202 is 80°.

[0146] In some embodiments of the present invention, see Figure 7 , step 200 further includes:

[0147] Step 203: When the well inclination angle of the portion is less than the preset threshold and the internal fluid flow direction is downward, select the second pressure calculation model.

[0148] In some embodiments of the present invention, see Figure 8 , step 200 further includes:

[0149] Step 204: When the well inclination angle of the portion is greater than the preset threshold, the second pressure calculation model is selected.

[0150] For steps 201 to 204, see Table 1 and Figure 9 For the drum section above the ground, the first pressure calculation model is used. For the wellbore section below the ground, the optimal model matching each microelement segment is determined using the optimization criteria for the gas-liquid two-phase flow model established in steps 201 to 204. When the wellbore inclination angle of the i-th section (wellbore section) is greater than 80°, that is, the flow condition is horizontal gas-liquid two-phase flow, the optimal flow model is the second pressure calculation model. When the wellbore inclination angle is less than 80° and the flow direction is downward, the optimal flow model is the first pressure calculation model; when the flow direction is upward, the optimal flow model is the first pressure calculation model.

[0151] Table 1

[0152]

[0153] For further explanation of this scheme, see Figure 10 、 Figure 11 as well as Figure 12 The present invention also takes the nitrogen injection and liquid removal operation of a coiled tubing as an example to provide a specific application example of a method for determining the pressure of a gas-liquid two-phase flow applicable to a coiled tubing.

[0154] S1: Divide the current wellbore profile into N segments according to the specified length.

[0155] Specifically, before using the multi-model combination gas-liquid two-phase flow model for calculation, the current wellbore profile is first divided into N segments according to the specified length (generally 30m). After the micro-segments are divided, they are sorted from the wellhead downwards, that is, each micro-segment from the wellhead to the bottom of the well is numbered [0, 1, 2, 3, ... N-1], and the necessary parameters required for each micro-segment are calculated separately, including the average well inclination angle, average azimuth angle, hydraulic diameter, flow direction, etc. Figure 13 shown.

[0156] S2: Select the gas-liquid two-phase flow model under different flow conditions.

[0157] S3: Establish a calculation model for gas-liquid two-phase flow in coiled tubing operations based on a multi-model combination.

[0158] like Figure 10 、 Figure 11 as well as Figure 12 As shown in the figure, in actual wellbores, fluids in coiled tubing operations typically experience coiled tubing drum bends, vertical upward / downward flow, inclined upward / downward flow, and horizontal flow. Combining the applicable scope of each model with the optimal model under different flow conditions, the entire wellbore (inside the tubing / annulus) is divided into multiple sections based on well inclination and flow direction. Each section uses a corresponding optimal model to meet the various complex flow conditions that exist simultaneously throughout the wellbore.

[0159] Specifically, before establishing a multi-model combined calculation method for gas-liquid two-phase flow in coiled tubing operations, it is necessary to identify the optimal flow model corresponding to different flow conditions and verify the calculation accuracy of different models by collecting gas-liquid two-phase flow test data. Figure 11 The figure shows the wellbore structure of a test well. It is a vertical well with positive circulation (tubing injection and annular return). The wellhead pressure is 74.7 psi. The calculation accuracy of the first pressure calculation model, the second pressure calculation model Hagedorn and Brown, Beggs and Brill, and Gray five models in vertical wellbore is verified. The results are shown as follows: Figure 14 、 Figure 15 As shown, the results of the first pressure calculation model agree well with the experimental data, with an average relative error of 0.3%. Therefore, the first pressure calculation model should be used to calculate flow pressure loss in vertical wells. The same method is used to evaluate the calculation accuracy of the model in inclined and horizontal well sections and under different flow directions, and to determine the optimal model for different flow conditions, providing a basis for the establishment of a combined model.

[0160] S4: Calculate the wellbore pressure loss based on the gas-liquid two-phase flow calculation model selected in step S3.

[0161] See also Figure 16 as well as Figure 17The formulas used by different models to calculate wellbore pressure loss are slightly different, but they all consist of three parts: hydrostatic pressure drop, friction pressure drop, and acceleration pressure drop. Formula (13) is the total pressure drop formula.

[0162]

[0163] Among them, hydrostatic pressure drop accounts for 80-95% of the total wellbore pressure drop. Therefore, the accurate calculation of hydrostatic pressure drop has an important impact on the calculation of total pressure drop. In terms of calculating hydrostatic pressure drop, different gas-liquid two-phase models mainly use different methods to calculate liquid holdup and gas holdup.

[0164] Based on the same inventive concept, embodiments of the present application also provide a device for determining the pressure of a gas-liquid two-phase flow in a coiled tubing system, which can be used to implement the methods described in the above embodiments, as shown in the following embodiments. Since the principles for solving the problem solved by the device for determining the pressure of a gas-liquid two-phase flow in a coiled tubing system are similar to those of the method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing system, the implementation of the device for determining the pressure of a gas-liquid two-phase flow in a coiled tubing system can refer to the implementation of the method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing system, and any repetitions will not be repeated. As used below, the terms "unit" or "module" may refer to a combination of software and / or hardware that implements a predetermined function. Although the systems described in the following embodiments are preferably implemented in software, implementation in hardware, or a combination of software and hardware, is also possible and contemplated.

[0165] The embodiment of the present invention provides a specific embodiment of a gas-liquid two-phase flow pressure determination device applicable to a coiled tubing, which can realize a gas-liquid two-phase flow pressure determination method applicable to a coiled tubing, wherein, referring to Figure 18 A device for determining the pressure of a gas-liquid two-phase flow in a coiled tubing system includes:

[0166] The coiled tubing dividing module 10 is used to divide the coiled tubing into a plurality of sections according to preset length intervals;

[0167] a part parameter determination module 20 for determining the positions of the plurality of parts, the well inclination angles, and the fluid flow directions therein;

[0168] A model selection module 30 is configured to select a corresponding pressure calculation model from a pre-generated pressure calculation model library according to the position, the well inclination angle, and the internal fluid flow direction;

[0169] The pressure calculation module 40 is configured to determine the pressure of the corresponding portion according to the selected pressure calculation model.

[0170] In some embodiments of the present invention, see Figure 19, a gas-liquid two-phase flow pressure determination device applicable to a coiled tubing, further comprising: a model library generation module 50, for generating the pressure calculation model library;

[0171] See also Figure 20 , the model library generation module 50 includes:

[0172] A first hydrostatic pressure drop calculation unit 50a is configured to calculate a first hydrostatic pressure drop according to the liquid holdup of a well section where the well inclination angle is less than a preset threshold;

[0173] The first and second friction pressure drop calculation units 50b are used to respectively calculate the first friction pressure drop and the second friction pressure drop of the bubble flow and the mist flow in the well section where the well inclination angle is less than the preset threshold;

[0174] a first pressure calculation model generating unit 50c, configured to generate a first pressure calculation model according to the first hydrostatic pressure drop, the first friction pressure drop, and the second friction pressure drop;

[0175] A second hydrostatic pressure drop calculation unit 50d is configured to calculate a second hydrostatic pressure drop according to the liquid holdup of a well section where the well inclination angle is greater than a preset threshold;

[0176] The third, fourth and fifth friction pressure drop calculation units 50e are used to respectively calculate the third friction pressure drop, the fourth friction pressure drop and the fifth friction pressure drop of the bubble flow, the slug flow and the annular flow in the well section where the well inclination angle is less than the preset threshold;

[0177] a second pressure calculation model generating unit 50f, configured to generate a second pressure calculation model according to the second hydrostatic pressure drop, the third friction pressure drop, the fourth friction pressure drop, and the fifth friction pressure drop;

[0178] The model library generating unit 50g is configured to generate the pressure calculation model library according to the first pressure calculation model and the second pressure calculation model.

[0179] In some embodiments of the present invention, see Figure 21 , the model selection module 20 includes:

[0180] The first model selection unit 20a is used to select the first pressure calculation model when the position of the portion is above the wellbore surface.

[0181] In some embodiments of the present invention, see Figure 22 , the model selection module 20 further includes:

[0182] The second model selection unit 20b is configured to select the first pressure calculation model when the well inclination angle of the portion is less than the preset threshold and the flow direction of the internal fluid is upward.

[0183] In some embodiments of the present invention, see Figure 23 , the model selection module 20 further includes:

[0184] The model selection third unit 20c is used to select the second pressure calculation model when the well inclination angle of the portion is less than the preset threshold and the flow direction of the internal fluid is downward flow.

[0185] In some embodiments of the present invention, see Figure 24 , the model selection module 20 further includes:

[0186] The fourth model selection unit 20d is configured to select the second pressure calculation model when the well inclination angle of the portion is greater than the preset threshold.

[0187] As can be seen from the foregoing description, an embodiment of the present invention provides a gas-liquid two-phase flow pressure determination apparatus suitable for coiled tubing, comprising: a coiled tubing segmentation module for segmenting the coiled tubing into multiple sections at preset length intervals; a section parameter determination module for determining the positions, well inclination angles, and fluid flow directions within the multiple sections; a model selection module for selecting a pressure calculation model for a corresponding section from a pressure calculation model library based on the position, well inclination angle, and fluid flow direction within the section; and a pressure calculation module for determining the pressure of the corresponding section based on the selected pressure calculation model.

[0188] The present invention rationally divides the entire wellbore into multiple sections according to different flow conditions, and generates an optimal gas-liquid two-phase pressure calculation model for each section, ultimately obtaining a pressure loss calculation for the entire wellbore that is more in line with actual conditions.

[0189] The present application also provides a specific embodiment of an electronic device capable of implementing all steps of the method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing according to the above embodiment, see Figure 25 , electronic equipment specifically includes the following:

[0190] The electronic device 600 may further include: a communication module 110, an input unit 120, an audio processing unit 130, a display 160, and a power supply 170. It is worth noting that the electronic device 600 does not necessarily have to include Figure 25 In addition, the electronic device 600 may also include all components shown in Figure 25 For components not shown in the figure, reference may be made to the prior art. It should be noted that this figure is exemplary; other types of structures may be used to supplement or replace this structure to implement telecommunication functions or other functions.

[0191] like Figure 25As shown, the processor 100 is sometimes also referred to as a controller or operation control, and may include a microprocessor or other processor device and / or logic device. The processor 100 receives input and controls the operation of various components of the electronic device 600 .

[0192] Memory 140 may be, for example, one or more of a cache, flash memory, a hard drive, removable media, volatile memory, non-volatile memory, or other suitable devices. It may store the aforementioned failure-related information and may also store a program for executing the relevant information. Processor 100 may execute the program stored in memory 140 to implement information storage or processing.

[0193] Input unit 120 provides input to processor 100. Input unit 120 is, for example, a keypad or touch input device. Power supply 170 is used to provide power to electronic device 600. Display 160 is used to display objects such as images and text. Display 160 can be, for example, an LCD display, but is not limited thereto.

[0194] The memory 140 may be a solid-state memory, such as a read-only memory (ROM), a random access memory (RAM), or a SIM card. Alternatively, it may be a memory that retains information even when power is off, can be selectively erased, and is provided with more data. Examples of memory 140 are sometimes referred to as EPROMs. The memory 140 may also be some other type of device. The memory 140 includes a buffer 141 (sometimes referred to as a buffer memory). The memory 140 may include an application / function storage unit 142 for storing application programs and function programs or processes for executing the operation of the electronic device 600 via the processor 100.

[0195] The memory 140 may also include a data storage unit 143 for storing data, such as contacts, digital data, pictures, sounds, and / or any other data used by the electronic device. The driver storage unit 144 of the memory 140 may include various driver programs for communication functions of the electronic device and / or for executing other functions of the electronic device (such as messaging applications, address book applications, etc.).

[0196] The communication module 110 includes a transmitter / receiver for transmitting and receiving signals via an antenna 111. The communication module 110 is coupled to the processor 100 to provide input signals and receive output signals, which may be the same as in the case of a conventional mobile communication terminal.

[0197] Based on different communication technologies, multiple communication modules 110 may be provided in the same electronic device, such as a cellular network module, a Bluetooth module, and / or a wireless local area network module. The communication module 110 is also coupled to a speaker 131 and a microphone 132 via an audio processor 130 to provide audio output via the speaker 131 and receive audio input from the microphone 132, thereby implementing common telecommunication functions. The audio processor 130 may include any suitable buffer, decoder, amplifier, etc. Furthermore, the audio processor 130 is coupled to the processor 100, enabling local recording via the microphone 132 and playback of stored audio via the speaker 131.

[0198] The various embodiments in this specification are described in a progressive manner. Similar portions between the various embodiments can be referenced to each other. Each embodiment focuses on the differences between the other embodiments. In particular, the hardware + program embodiments are generally similar to the method embodiments, so their description is relatively simple. For relevant portions, refer to the description of the method embodiments.

[0199] The foregoing description of this specification describes specific embodiments. Other embodiments are within the scope of the appended claims. In some cases, the actions or steps recited in the claims can be performed in an order different from that described in the embodiments and still achieve the desired results. Furthermore, the processes depicted in the accompanying drawings do not necessarily require the specific order shown or the sequential order to achieve the desired results. In certain embodiments, multitasking and parallel processing are also possible or may be advantageous.

[0200] Although the present application provides method operation steps as described in the embodiments or flowcharts, more or fewer operation steps may be included based on conventional or non-creative work. The order of steps listed in the embodiments is only one way of executing the steps among many steps and does not represent the only execution order. When the actual device or client product is executed, it can be executed in sequence or in parallel according to the method shown in the embodiments or the drawings (for example, in a parallel processor or multi-threaded processing environment).

[0201] Although the present specification embodiment provides the method operation steps as described in the embodiment or flow chart, more or less operation steps may be included based on conventional or non-creative means. The order of steps listed in the embodiment is only one way in the order of execution of many steps and does not represent a unique execution order. When the device or terminal product in practice is executed, it can be performed in sequence or in parallel according to the method shown in the embodiment or the accompanying drawings (such as a parallel processor or a multi-threaded processing environment, or even a distributed data processing environment). The term "comprise", "comprising" or any other variant thereof is intended to cover non-exclusive inclusion, so that the process, method, product or equipment including a series of elements not only include those elements, but also include other elements not clearly listed, or also include elements inherent to such process, method, product or equipment. In the absence of more restrictions, it is not excluded that there are other identical or equivalent elements in the process, method, product or equipment including the elements.

[0202] For the convenience of description, the above devices are described in terms of functions divided into various modules. Of course, when implementing the embodiments of this specification, the functions of each module can be implemented in the same or multiple software and / or hardware, or the modules that implement the same function can be implemented by a combination of multiple sub-modules or sub-units, etc. The device embodiments described above are merely schematic. For example, the division of the units is only a logical function division. In actual implementation, there may be other division methods, such as multiple units or components can be combined or integrated into another system, or some features can be ignored or not executed. Another point is that the mutual coupling or direct coupling or communication connection shown or discussed can be an indirect coupling or communication connection through some interfaces, devices or units, which can be electrical, mechanical or other forms.

[0203] Those skilled in the art will also appreciate that, in addition to implementing the controller in pure computer-readable program code, it is entirely possible to implement the same functionality by logically programming the method steps in the form of logic gates, switches, application-specific integrated circuits, programmable logic controllers, embedded microcontrollers, and the like. Therefore, such a controller can be considered a hardware component, and the devices included therein for implementing various functions can also be considered structures within the hardware component. Alternatively, the devices for implementing various functions can be considered both software modules implementing the method and structures within the hardware component.

[0204] The present invention is described with reference to flowcharts and / or block diagrams of methods, devices (systems), and computer program products according to embodiments of the present invention. It should be understood that each process and / or block in the flowcharts and / or block diagrams, as well as combinations of processes and / or blocks in the flowcharts and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing device to produce a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the processes in the flowcharts and / or block diagrams. Figure 1 a process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0205] These computer program instructions may also be stored in a computer readable memory that can direct a computer or other programmable data processing device to work in a specific manner, so that the instructions stored in the computer readable memory produce an article of manufacture comprising an instruction device, which implements the process Figure 1 a process or multiple processes and / or boxes Figure 1 The function specified in one or more boxes.

[0206] These computer program instructions can also be loaded onto a computer or other programmable data processing device so that a series of operational steps are executed on the computer or other programmable device to produce a computer-implemented process, thereby providing the instructions executed on the computer or other programmable device for implementing the process. Figure 1 a process or multiple processes and / or boxes Figure 1 A step that specifies a function in one or more boxes.

[0207] In a typical configuration, a computing device includes one or more processors (CPUs), input / output interfaces, network interfaces, and memory.

[0208] Memory may include non-permanent storage in a computer-readable medium, random access memory (RAM) and / or non-volatile memory in the form of read-only memory (ROM) or flash RAM. Memory is an example of a computer-readable medium.

[0209] Computer-readable media includes permanent and non-permanent, removable and non-removable media that can be implemented by any method or technology to store information. The information can be computer-readable instructions, data structures, program modules or other data. Examples of computer storage media include, but are not limited to, phase change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), other types of random access memory (RAM), read-only memory (ROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other memory technology, compact disc read-only memory (CD-ROM), digital versatile disc (DVD) or other optical storage, magnetic cassettes, magnetic disk storage or other magnetic storage devices or any other non-transmission media that can be used to store information that can be accessed by a computing device. As defined herein, computer-readable media does not include transitory computer-readable media (transitory media), such as modulated data signals and carrier waves.

[0210] Those skilled in the art will appreciate that the embodiments of this specification may be provided as methods, systems, or computer program products. Therefore, the embodiments of this specification may take the form of a complete hardware embodiment, a complete software embodiment, or an embodiment combining software and hardware. Furthermore, the embodiments of this specification may take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to magnetic disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0211] Embodiments of this specification may be described in the general context of computer-executable instructions executed by a computer, such as program modules. Generally, program modules include routines, programs, objects, components, data structures, and the like that perform specific tasks or implement specific abstract data types. Embodiments of this specification may also be practiced in distributed computing environments where tasks are performed by remote processing devices connected via a communications network. In distributed computing environments, program modules may be located in local and remote computer storage media, including storage devices.

[0212] The various embodiments in this specification are described in a progressive manner. Similar or identical parts between the various embodiments can be referenced across them. Each embodiment focuses on the differences from the other embodiments. In particular, since the system embodiments are generally similar to the method embodiments, their description is relatively simple. For relevant parts, reference can be made to the description of the method embodiments. Throughout this specification, reference to the terms "one embodiment," "some embodiments," "example," "specific example," or "some examples" means that the specific features, structures, materials, or characteristics described in conjunction with that embodiment or example are included in at least one embodiment or example of the embodiments in this specification. In this specification, the schematic representations of these terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in any one or more embodiments or examples. Furthermore, those skilled in the art may combine and integrate the different embodiments or examples, and features of different embodiments or examples, described in this specification, without conflict.

[0213] The above description is merely an example of the embodiments of this specification and is not intended to limit the embodiments of this specification. For those skilled in the art, various modifications and variations of the embodiments of this specification are possible. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the embodiments of this specification shall be included within the scope of the claims of the embodiments of this specification.

Claims

1. A method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing, characterized in that: include: dividing the coiled tube into a plurality of sections at intervals of preset lengths; determining the positions of the plurality of sections, the well inclination angles, and the directions of fluid flow therein; In a pre-generated pressure calculation model library, a corresponding pressure calculation model is selected according to the position, the well inclination angle, and the internal fluid flow direction; The pressure of the corresponding part is determined according to the selected pressure calculation model.

2. The method for determining the gas-liquid two-phase flow pressure of a coiled tubing according to claim 1, characterized in that: Also includes: generating the pressure calculation model library; The generating of the pressure calculation model library comprises: Calculating a first hydrostatic pressure drop according to the liquid holdup of a well section where the well inclination angle is less than a preset threshold; respectively calculating a first friction pressure drop and a second friction pressure drop of the bubble flow and the mist flow in a well section where the well inclination angle is less than the preset threshold; generating a first pressure calculation model according to the first hydrostatic pressure drop, the first friction pressure drop, and the second friction pressure drop; Calculating a second hydrostatic pressure drop according to the liquid holdup of a well section where the well inclination angle is greater than a preset threshold; respectively calculating the third friction pressure drop, the fourth friction pressure drop, and the fifth friction pressure drop of the bubble flow, the slug flow, and the annular flow in the well section where the well inclination angle is less than the preset threshold; generating a second pressure calculation model according to the second hydrostatic pressure drop, the third friction pressure drop, the fourth friction pressure drop, and the fifth friction pressure drop; The pressure calculation model library is generated according to the first pressure calculation model and the second pressure calculation model.

3. The method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing according to claim 2, wherein: The pressure calculation model of the corresponding part is selected in the pre-generated pressure calculation model library according to the position, the well inclination angle and the internal fluid flow direction, including: When the portion is located above the wellbore surface, the first pressure calculation model is selected.

4. The method for determining the gas-liquid two-phase flow pressure of a coiled tubing according to claim 2, wherein: The pressure calculation model of the corresponding part is selected in the pre-generated pressure calculation model library according to the position, the well inclination angle and the internal fluid flow direction, and further includes: When the well inclination angle of the portion is less than the preset threshold and the internal fluid flows in an upward direction, the first pressure calculation model is selected.

5. The method for determining the gas-liquid two-phase flow pressure of a coiled tubing according to claim 2, wherein: The pressure calculation model of the corresponding part is selected in the pre-generated pressure calculation model library according to the position, the well inclination angle and the internal fluid flow direction, and further includes: When the well inclination angle of the portion is less than the preset threshold and the internal fluid flows in a downward direction, the second pressure calculation model is selected.

6. The method for determining the pressure of a gas-liquid two-phase flow in a coiled tubing according to claim 2, wherein: The pressure calculation model of the corresponding part is selected in the pre-generated pressure calculation model library according to the position, the well inclination angle and the internal fluid flow direction, and further includes: When the well inclination angle of the portion is greater than the preset threshold, the second pressure calculation model is selected.

7. A gas-liquid two-phase flow pressure determination device suitable for coiled tubing, characterized in that: include: a coiled tubing dividing module, configured to divide the coiled tubing into a plurality of sections at intervals of preset lengths; a part parameter determination module, for determining the positions of the plurality of parts, the well inclination angles, and the directions of fluid flow therein; A model selection module is used to select a corresponding pressure calculation model from a pre-generated pressure calculation model library according to the position, the well inclination angle and the internal fluid flow direction; The pressure calculation module is used to determine the pressure of the corresponding part according to the selected pressure calculation model.

8. The gas-liquid two-phase flow pressure determination device applicable to a coiled tubing according to claim 7, characterized in that: Also includes: A model library generation module, used to generate the pressure calculation model library; The model library generation module includes: A first hydrostatic pressure drop calculation unit is configured to calculate a first hydrostatic pressure drop according to the liquid holdup of a well section where the well inclination angle is less than a preset threshold; The first and second friction pressure drop calculation units are used to respectively calculate the first friction pressure drop and the second friction pressure drop of the bubble flow and the mist flow in the well section where the well inclination angle is less than the preset threshold; a first pressure calculation model generating unit, configured to generate a first pressure calculation model according to the first hydrostatic pressure drop, the first friction pressure drop, and the second friction pressure drop; A second hydrostatic pressure drop calculation unit is configured to calculate a second hydrostatic pressure drop according to the liquid holdup of a well section where the well inclination angle is greater than a preset threshold; The third, fourth and fifth friction pressure drop calculation units are used to respectively calculate the third friction pressure drop, the fourth friction pressure drop and the fifth friction pressure drop of the bubble flow, the slug flow and the annular flow in the well section where the well inclination angle is less than the preset threshold; a second pressure calculation model generating unit, configured to generate a second pressure calculation model according to the second hydrostatic pressure drop, the third friction pressure drop, the fourth friction pressure drop, and the fifth friction pressure drop; A model library generating unit is configured to generate the pressure calculation model library according to the first pressure calculation model and the second pressure calculation model.

9. The gas-liquid two-phase flow pressure determination device applicable to a coiled tubing according to claim 8, characterized in that: The model selection module includes: The model selects the first unit, which is used to select the first pressure calculation model when the position of the portion is above the wellbore surface.

10. The gas-liquid two-phase flow pressure determination device applicable to a coiled tubing according to claim 8, characterized in that: The model selection module also includes: The model selection second unit is used to select the first pressure calculation model when the well inclination angle of the portion is less than the preset threshold and the internal fluid flow direction is upward flow.

11. The gas-liquid two-phase flow pressure determination device applicable to coiled tubing according to claim 8, characterized in that: The model selection module also includes: The model selection third unit is used to select the second pressure calculation model when the well inclination angle of the portion is less than the preset threshold and the internal fluid flow direction is downward flow.

12. The gas-liquid two-phase flow pressure determination device applicable to a coiled tubing according to claim 8, characterized in that: The model selection module also includes: The fourth model selection unit is used to select the second pressure calculation model when the well inclination angle of the portion is greater than the preset threshold.

13. A computer program product comprising a computer program / instructions, characterized in that When the computer program / instructions are executed by a processor, the steps of the method for determining the pressure of a gas-liquid two-phase flow applicable to a coiled tubing according to any one of claims 1 to 6 are implemented.

14. An electronic device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein: When the processor executes the program, the steps of the method for determining the pressure of a gas-liquid two-phase flow applicable to a coiled tubing according to any one of claims 1 to 6 are implemented.

15. A computer-readable storage medium having a computer program stored thereon, characterized in that: When the computer program is executed by a processor, the steps of the method for determining the pressure of a gas-liquid two-phase flow applicable to a coiled tubing according to any one of claims 1 to 6 are implemented.

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