Knowledge and data coupling driven drilling and completion fluid design expert system

Abstract

The embodiment of the invention provides a knowledge and data coupling driven drilling and completion fluid design expert system, and belongs to the technical field of reservoir protection in the petroleum industry, and the system comprises a total skin coefficient calculation module which is used for calculating the total skin coefficient of a target well; the optimization module is used for judging that the drilling fluid and the completion fluid corresponding to the target well are good in performance when the total skin coefficient of the target well is smaller than or equal to 0, and optimization design is not needed; and when the total skin coefficient of the target well is greater than 0, performing optimization design on drilling fluid and completion fluid corresponding to the target well according to the following mode: presetting drilling fluid formulas corresponding to different permeability and / or structural characteristics according to the permeability and / or structural characteristics of a reservoir corresponding to the target well, determining a target drilling fluid formula corresponding to the target well; and determining a target completion fluid formula corresponding to the target well according to the type of the completion fluid corresponding to the target well and completion fluid formulas corresponding to different preset completion fluid types.

Description

Technical Field

[0001] The present invention relates to the field of reservoir protection technology in the petroleum industry, and in particular to a method, device, processor, and computer program product for calculating the total skin factor of a complex well, as well as a drilling and completion fluid design expert method driven by knowledge and data coupling, and a drilling and completion fluid design expert system driven by knowledge and data coupling. Background Art

[0002] As oil and gas exploration and development gradually advance towards deep, ultra-deep, and low-permeability reservoirs, horizontal well technology has become a crucial tool for improving oil and gas recovery and optimizing reservoir development methods. Compared to vertical or directional wells, horizontal wells significantly increase the contact area with the reservoir, thereby increasing single-well productivity. However, due to the longer horizontal well sections and the increased number of factors controlling wellbore stability, traditional drilling and completion fluid designs are unable to meet the demands of modern, complex well conditions. This leads to frequent problems such as wellbore instability, lost circulation, well collapse, and reservoir damage, seriously impacting drilling safety and the profitability of oil and gas field development.

[0003] In existing technologies, the design of drilling and completion fluids primarily relies on engineers' experience and experimental data. Parameters such as density, viscosity, and fluid loss are adjusted based on formation characteristics, wellbore mechanics analysis, and rheological requirements. However, this empirical design approach has the following limitations: It is highly dependent on experience and difficult to adapt to changing well conditions. Due to the complex and variable formation characteristics, a single empirical method cannot provide the optimal drilling and completion fluid formula. This is especially true in special well conditions such as ultra-deep wells, high-pressure, high-temperature (HPHT) wells, and extended-reach wells. Empirical adjustments can easily lead to parameter mismatches, compromising drilling safety. Furthermore, traditional drilling and completion fluid optimization methods are typically based on static data calculations, making real-time optimization difficult and unable to dynamically adjust to changes in the downhole environment. This increases well control risks and the risk of reservoir damage. Summary of the Invention

[0004] The purpose of the embodiments of the present invention is to provide a method, apparatus, processor and computer program product for calculating the total skin factor of a complex well, as well as an expert method and system for drilling and completion fluid design driven by knowledge and data coupling, so as to solve or at least partially solve the above-mentioned defects of the prior art.

[0005] To achieve the above objectives, a first aspect of an embodiment of the present invention provides a method for calculating the total skin factor of a complex well, the method comprising: By coordinate transformation, the permeability ratio of any well section of the target well in the wellbore orthogonal plane in the isotropic coordinate system is determined; According to the following parameters corresponding to any well section: the ratio of the wellbore length and the permeability in the plane orthogonal to the wellbore in the isotropic coordinate system, the distribution of the radius of the damaged zone along the wellbore direction, and the following parameters corresponding to the target well: the wellbore radius The permeability of the formation before damage and the permeability of the formation after damage are used to determine the skin factor of the formation near any well section; determining an additional pressure drop corresponding to any well section based on a skin coefficient of a formation near the any well section and a reduced permeability of a formation before damage corresponding to the target well; and Determining a total skin factor of the target well based on the following parameters corresponding to any well section: oil and gas layer permeability, oil and gas layer thickness, pressure difference, the additional pressure drop, and the distribution of the damage zone radius along the wellbore direction, and the following parameters corresponding to the target well: total wellbore length and wellbore radius; Wherein, any well section of the target well is a vertical well section, a horizontal well section or a inclined well section.

[0006] Preferably, determining the permeability ratio of any well section of the target well in a wellbore orthogonal plane in an isotropic coordinate system comprises: According to any well section of the target well in the anisotropic coordinate system oxyz Bottom: Maximum horizontal permeability parallel to the fracture direction , minimum horizontal permeability perpendicular to the fracture direction , vertical permeability of the formation , well inclination angle , and in x - y The horizontal projection of the plane x Axis angle , determine the permeability ratio of any well section of the target well in the wellbore orthogonal plane in the isotropic coordinate system : .

[0007] Preferably, the wellbore length corresponding to any well section in the isotropic coordinate system is determined according to the following method: According to any well section of the target well in the anisotropic coordinate system oxyz The following parameters are given: Maximum horizontal permeability parallel to the fracture direction , minimum horizontal permeability perpendicular to the fracture direction , vertical permeability of the formation , determine the first parameter , the second parameter And the third parameter :

[0008] According to the first parameter The second parameter , the third parameter And any well section of the target well in the anisotropic coordinate system oxyz The following parameters are: Length , well inclination angle and in x - y The horizontal projection of the plane x Axis angle , determine the wellbore length in the isotropic coordinate system : .

[0009] Preferably, determining the skin coefficient of the formation near any well section includes: According to the following parameters corresponding to any well section: wellbore length in isotropic coordinate system Permeability ratio in the plane perpendicular to the wellbore , and the distribution of the damage zone radius along the wellbore direction , and the following parameters corresponding to the target well: wellbore radius Formation permeability before damage and the permeability of the damaged formation , determine the skin coefficient of the formation near any well section : ; in, Refers to the direction vector corresponding to the wellbore toe direction, Refers to any plane perpendicular to the wellbore corresponding to the stratum near any well section.

[0010] Preferably, the permeability of the formation before damage corresponding to the target well is It is determined in the following way: According to the target well The following parameters correspond to the well section: oil and gas layer permeability , oil and gas layer thickness and pressure difference , determine the pre-damage reduced permeability of the formation corresponding to the target well : ; in, is the total number of well sections of the target well.

[0011] Preferably, the permeability of the damaged formation corresponding to the target well is based on oxyz The three-dimensional steady-state partial differential equation of the single-phase incompressible liquid flow in the reservoir is determined in the coordinate system.

[0012] Preferably, the determining of the additional pressure drop corresponding to any well section includes: determining the skin coefficient of the formation near any well section according to the skin coefficient of the formation near any well section ,flow , fluid viscosity , volume coefficient , the reduced permeability of the formation before the damage , and the thickness of the oil and gas layer , determine the additional pressure drop : .

[0013] Preferably, determining the total skin factor of the target well includes: According to the following parameters corresponding to any well section: oil and gas layer permeability , oil and gas layer thickness , pressure difference , the additional pressure drop and the distribution of the damage zone radius along the wellbore direction , and the following parameters corresponding to the target well: total wellbore length and wellbore radius , determine the total skin factor of the target well :

[0014] in, is the total number of well sections of the target well.

[0015] Preferably, the distribution of the damage zone radius corresponding to any well section of the target well along the wellbore direction is determined according to an oscillation attenuation function model or an empirical formula model.

[0016] Preferably, the oscillation attenuation function model includes: ; in, Indicates the The radius of the damage zone corresponding to the well section is along the toe of the wellbore Distribution of directions; Refers to the direction vector corresponding to the wellbore toe direction; Indicates the The maximum damage zone radius corresponding to the wellbore of the section, Indicates the The minimum damage zone radius corresponding to the wellbore of the section. Preferably, the empirical formula model includes:

[0017] in; Indicates the radius of the damage zone; Represents the radius of the wellbore; represents porosity; 、 30 respectively min Static and dynamic filtration loss; , 、 are the time for the drilling fluid to soak into the target layer and the time for the drilling fluid to circulate through the target layer; 、 、 They are the amount of filtrate absorbed by the rock during soaking, the amount of filtrate absorbed by the rock during mud circulation, and the amount of filtrate in the external mud cake; is the core diameter; is the residual oil saturation; is the residual saturation of rock pores after filtrate invasion; It is the saturation of the original pore volume after the clay absorbs water and expands; Indicates the drilling fluid immersion time; is the average mechanical drilling speed; Refers to the drilling fluid immersion time The corresponding position.

[0018] A second aspect of an embodiment of the present invention provides a device for calculating the total skin coefficient of a complex well, comprising: a memory configured to store instructions; and a processor configured to call the instructions from the memory and implement the method for calculating the total skin coefficient of a complex well when executing the instructions.

[0019] A third aspect of an embodiment of the present invention provides a processor for running a program, wherein the program, when run, is used to execute: the method for calculating the total skin coefficient of a complex well.

[0020] A fourth aspect of an embodiment of the present invention provides a computer program product, comprising a computer program, which, when executed by a processor, implements the method for calculating the total skin factor of a complex well.

[0021] A fifth aspect of an embodiment of the present invention provides an expert method for drilling and completion fluid design driven by knowledge and data coupling, the method comprising: When the total skin coefficient of the target well is less than or equal to 0, it is determined that the drilling fluid and completion fluid corresponding to the target well have good performance and no optimization design is required; When the total skin factor of the target well is greater than 0, the drilling fluid and completion fluid corresponding to the target well are optimized according to the following method: Determining a target drilling fluid formulation corresponding to the target well based on the permeability and / or structural characteristics of the reservoir corresponding to the target well and preset drilling fluid formulations corresponding to different permeabilities and / or structural characteristics; and Determining a target completion fluid formula corresponding to the target well based on the type of completion fluid corresponding to the target well and preset completion fluid formulas corresponding to different completion fluid types; Among them, the structural characteristics of the reservoir include: non-fractured reservoir and fractured reservoir; the types of completion fluid include: solid-free completion fluid and low-damage surfactant completion fluid; the total skin coefficient of the target well is determined by the method for calculating the total skin coefficient of a complex well.

[0022] Preferably, determining the target drilling fluid formula corresponding to the target well includes: The permeability of the reservoir corresponding to the target well is greater than 500×10 -3 μm 2 When the reservoir is non-fractured, the target drilling fluid formula is: Formula 1: upper drilling fluid + (1-2)% oil film type reservoir protection new material LCM-8 + (2-3)% ideal filler; The permeability of the reservoir corresponding to the target well is greater than 500×10 -3 μm 2 When the reservoir is fractured, the target drilling fluid formula is: Formula 2: upper drilling fluid + 0.6% xanthan gum XG; The permeability of the reservoir corresponding to the target well is between 50 and 500×10 -3 μm 2 When the reservoir is between 100 and 150 nm and is non-fractured, the target drilling fluid formula is: Formula 3: upper drilling fluid + (2-4)% oil film type reservoir protection new material LCM-8; The permeability of the reservoir corresponding to the target well is between 50 and 500×10 -3 μm 2 When the reservoir is fractured, the target drilling fluid formula is: Formula 4: upper drilling fluid + 0.6% xanthan gum XG; and The permeability of the reservoir corresponding to the target well is less than 5.0×10 -3 μm 2 When the target drilling fluid formula is: Formula 5: upper drilling fluid + (2-3)% oil film type reservoir protection new material LCM-8 + (0.2-0.4)% surfactant FCS-08.

[0023] Preferably, determining the target completion fluid formula corresponding to the target well includes: When the completion fluid corresponding to the target well is a solid-free completion fluid, the target completion fluid formula is: Formula 6: clean water + 76% anti-collapse plugging agent KR + 3% fluid loss reducer ZT-2 + X% limestone powder; and When the completion fluid corresponding to the target well is a low-damage surfactant completion fluid, the target completion fluid formula is: Formula 7: clean water + 0.2% viscosity-increasing fluid loss reducer + 0.3% zwitterionic polymer FA367 + 3% cationic polymer clay stabilizer YNJ + 3% fine-mesh CaCO3 + 0.2% inhibitor SK-2 + 1% water-locking agent JSS + 1% corrosion inhibitor ZH-III + Y% weighting agent; The calculation formulas for X and Y in formulas 6 and 7 are as follows:

[0024]

[0025] Indicates the preset completion fluid density value.

[0026] A sixth aspect of an embodiment of the present invention provides a drilling and completion fluid design expert system driven by knowledge and data coupling, the system comprising: Total skin coefficient calculation module: used to calculate the total skin coefficient of the target well; Optimization module: used for determining that the drilling fluid and completion fluid corresponding to the target well have good performance and no optimization design is required when the total skin coefficient of the target well is less than or equal to 0; When the total skin factor of the target well is greater than 0, the drilling fluid and completion fluid corresponding to the target well are optimized according to the following method: Determining a target drilling fluid formulation corresponding to the target well based on the permeability and / or structural characteristics of the reservoir corresponding to the target well and preset drilling fluid formulations corresponding to different permeabilities and / or structural characteristics; and Determining a target completion fluid formula corresponding to the target well based on the type of completion fluid corresponding to the target well and preset completion fluid formulas corresponding to different completion fluid types; Among them, the structural characteristics of the reservoir include: non-fractured reservoir and fractured reservoir; the types of completion fluid include: solid-free completion fluid and low-damage surfactant completion fluid; the total skin coefficient of the target well is determined by the method for calculating the total skin coefficient of a complex well.

[0027] The knowledge and data coupling-driven drilling and completion fluid design expert method provided by the embodiment of the present invention calculates the total skin coefficient of the target well and provides corresponding optimization decisions for the drilling fluid and completion fluid corresponding to the target well based on the total skin coefficient of the target well. On the one hand, it can solve the problems of difficulty, poor adaptability, and reliance on experience in the optimization design of drilling fluid and completion fluid under complex formation conditions. On the other hand, the total skin coefficient of the target well can be used to obtain real-time changes in the downhole environment, thereby making dynamic adjustments based on changes in the downhole environment and reducing well control risks and reservoir damage risks.

[0028] Other features and advantages of the embodiments of the present invention will be described in detail in the subsequent detailed description. BRIEF DESCRIPTION OF THE DRAWINGS

[0029] The accompanying drawings are used to provide a further understanding of the embodiments of the present invention and constitute a part of the specification. Together with the following detailed description, they are used to explain the embodiments of the present invention, but do not constitute a limitation of the embodiments of the present invention. In the accompanying drawings: Figure 1 1 is a flow chart of a method for calculating the total skin factor of a complex well provided by an embodiment of the present invention; Figure 2 The embodiment of the present invention provides oxyz Position relationship diagram of deviated well sections in anisotropic reservoirs under coordinate system; Figure 3 The embodiment of the present invention provides Position relationship diagram of deviated well sections in isotropic reservoirs under coordinate system; Figure 4 The embodiment of the present invention provides Position relationship diagram of deviated well sections in isotropic reservoirs under coordinate system; Figure 5 The embodiment of the present invention provides Position relationship diagram of deviated well sections in isotropic reservoirs under coordinate system; Figure 6 Schematic diagram of damage in a plane orthogonal to a wellbore in an anisotropic oil reservoir provided by an embodiment of the present invention; Figure 7 Schematic diagram of damage in a plane orthogonal to a wellbore in an isotropic oil reservoir provided by an embodiment of the present invention; Figure 8 Schematic diagram of conformal transformation within a plane orthogonal to a wellbore in an isotropic oil reservoir provided by an embodiment of the present invention; Figure 9 2. This is a schematic diagram of a linear distribution model of the radius of the damage zone along the wellbore provided by an embodiment of the present invention; Figure 10 Schematic diagram of a parabolic distribution model of the radius of the damage zone along the wellbore provided by an embodiment of the present invention; Figure 11 Schematic diagram of the distribution of the radius of the damage zone along the wellbore of a complex well type provided by an embodiment of the present invention; Figure 12 is a schematic diagram of an oscillation attenuation function model provided by an embodiment of the present invention; Figure 13 It is a schematic diagram of a horizontal well provided by an embodiment of the present invention. DETAILED DESCRIPTION

[0030] The following describes the specific implementation of the embodiment of the present invention in detail with reference to the accompanying drawings. It should be understood that the specific implementation described herein is only used to illustrate and explain the embodiment of the present invention and is not used to limit the embodiment of the present invention.

[0031] It should be noted that the acquisition, transmission, storage, use, and processing of data in the technical solution of this application are in compliance with the relevant provisions of laws and regulations. In the embodiments of this application, certain software, components, models, and other existing solutions in the industry may be mentioned. These should be considered as exemplary. Their purpose is only to illustrate the feasibility of implementing the technical solution of this application, but it does not mean that the applicant has or will necessarily use such solutions.

[0032] Example 1 The skin coefficient is a dimensionless parameter used to describe the change in flow resistance of the formation surrounding the wellbore due to drilling, completion, and other operations. The skin coefficient quantifies the extent of reservoir damage inflicted during drilling and completion. A larger positive skin coefficient indicates more severe reservoir damage and greater resistance to oil and gas flow. By monitoring changes in the skin coefficient, the effectiveness of reservoir protection measures can be assessed, allowing timely adjustments to drilling and completion plans to minimize reservoir damage. Existing techniques for calculating the skin factor of complex wells based on oil well production models typically assume homogeneous and isotropic formations, with consistent formation conditions around the wellbore. However, complex wells, such as horizontal and multilateral wells, often exhibit heterogeneity, anisotropy, and permeability variations along the wellbore, leading to inaccurate skin factor calculations. Therefore, embodiments of the present invention provide a method for calculating the total skin factor of complex wells, enabling more accurate calculations of the skin factor for complex well types, thereby providing a scientific basis for rationally formulating reservoir protection measures. Before describing the implementation of the method for calculating the total skin factor of complex wells provided by embodiments of the present invention, a detailed introduction to horizontal wells is provided. A horizontal well refers to a wellbore section in which the wellbore trajectory remains horizontal or nearly horizontal (typically with an inclination angle greater than 85°) within the target formation. A horizontal well typically consists of a vertical section (also known as a vertical well section), a deflection section (also known as a deflected well section), and a horizontal section (also known as a horizontal well section). Each section of a horizontal well has different functions and characteristics. Specifically, the vertical section is located from the wellhead to the inclination point, the wellbore trajectory is basically vertical, and the drilling process is similar to that of a vertical well, which is used to quickly penetrate the surface and shallow formations; the inclination section is located from the inclination point to the landing point, and the well inclination angle gradually increases from vertical to horizontal. The drilling is difficult and directional drilling tools are required; the horizontal section is located from the landing point to the end point of the horizontal well, and the wellbore trajectory remains horizontal or near horizontal, extending from hundreds to thousands of meters. The horizontal section is completely located within the target reservoir, with a large contact area with the reservoir, and is a key part of improving the recovery rate.

[0033] Furthermore, taking the calculation of the total skin coefficient corresponding to a horizontal well as an example, the method for calculating the total skin coefficient of a complex well provided by the embodiment of the present invention is specifically described.

[0034] Figure 1 FIG. 1 is a flow chart of a method for calculating the total skin factor of a complex well provided by an embodiment of the present invention. Figure 1 As shown, the method for calculating the total skin factor of a complex well may include: S101, determining the permeability ratio of any well section of the target well in a wellbore orthogonal plane in an isotropic coordinate system through coordinate transformation; It should be noted that any well section of the target well is a vertical well section, a horizontal well section or a inclined well section.

[0035] In some embodiments, determining the permeability ratio of any well section of the target well in a plane orthogonal to the wellbore in an isotropic coordinate system comprises: According to any well section of the target well in the anisotropic coordinate system oxyz Bottom: Maximum horizontal permeability parallel to the fracture direction , minimum horizontal permeability perpendicular to the fracture direction , vertical permeability of the formation , well inclination angle , and in x - y The horizontal projection of the plane x Axis angle , determine the permeability ratio of any well section of the target well in the wellbore orthogonal plane in the isotropic coordinate system : ; (1) Furthermore, taking the solution of the permeability of the inclined well section in the wellbore orthogonal plane in the isotropic coordinate system as an example, the derivation process of formula (1) is explained in detail.

[0036] Due to the uneven distribution of ground stress, anisotropy is common in oil reservoirs, and the direction of maximum permeability is generally consistent with the direction of maximum horizontal principal stress. Assuming the thickness of the oil and gas layer is h There is a well with a length of The inclined well section has a wellbore radius of , defined as Figure 2 The conventional coordinate system shown oxyz ,in oz Perpendicular to the stratum plane, x - y The plane is horizontal. Assume that the permeabilities in the three coordinate axes of the coordinate system are the maximum horizontal permeability parallel to the fracture direction , minimum horizontal permeability perpendicular to the fracture direction and vertical permeability of the formation ( > > ), the well inclination angle is ,exist x - y The horizontal projection of the well is x The angle between the axes, that is, the azimuth angle is ,in , .

[0037] In this coordinate system, the three-dimensional steady-state partial differential equation for the flow of a single-phase incompressible liquid in an oil reservoir is: ; (2) make , substituting into (2), we get: ; (3) (3) is expressed as The three-dimensional steady-state partial differential equation of seepage in the coordinate system is transformed by using the above relationship. oxyz Coordinate system conversion to Coordinate system, that is: ; (4) in, .

[0038] After coordinate transformation, The permeability tensor in the coordinate system is transformed into: ; (5) It can be seen that after coordinate transformation, the original anisotropic permeability space is converted into an equivalent isotropic permeability space. Figure 3 As shown, in the isotropic coordinate space, the new well inclination angle, azimuth angle, wellbore length, wellbore radius, and permeability are expressed as 、 、 、 、 , the corresponding conversion formula is shown in formula (6).

[0039]

[0040]

[0041]

[0042]

[0043] ; (6) In formula (6), is the formation anisotropy coefficient: , is the horizontal permeability of the formation: .

[0044] In an isotropic reservoir, since the isobars surrounding the wellbore always lie in a plane perpendicular to the wellbore, and wellbore damage is directly related to pressure, the coordinate system is rotated so that one of the coordinate axes is parallel to the axial direction of the deviated wellbore. This allows the pressure distribution in the formation surrounding the wellbore to be expressed using two quantities within a single coordinate plane.

[0045] for Figure 3 In order to make the coordinates The coordinate axis is parallel to the wellbore direction. The axis direction is the axis, noodle( Clockwise rotation Angle, converted to Coordinate system, such as Figure 4 shown.

[0046] The coordinate transformation relationship is: ; (7) Then The axis direction is the axis, noodle( (face) counterclockwise rotation Angle, converted to Coordinate system, such as Figure 5 shown.

[0047] The coordinate transformation relationship is: ; (8) Then finally oxyz Coordinate system to The transformation relationship of the coordinate system is: ; (9) use Represents the transformed coordinate axis , then the oil reservoir is The coordinate system is isotropic, where The axis is always parallel to the deviated section under study, and The surface is perpendicular to the wellbore of the studied inclined well section. The plane shows the distribution of formation pressure field or damage near the deviated well section. ouvw The coordinate system is oxyz The coordinate system is obtained by rotating the coordinate system. wThe axis is always parallel to the deviated section under study, and uv The surface is perpendicular to the wellbore of the studied inclined well section. The reservoir below it is an anisotropic reservoir with unconverted permeability. uv The plane can also represent the formation seepage characteristics near the deviated well section or the distribution of wellbore damage. The conversion relationship between the two coordinate systems and the permeability conversion relationship are shown in Equations (10) to (13).

[0048] ; (10) ; (11) ; (12) ; (13) S102, based on the following parameters corresponding to any well section: the ratio of the wellbore length in the isotropic coordinate system to the permeability in the wellbore orthogonal plane, the distribution of the damage zone radius along the wellbore direction, and the following parameters corresponding to the target well: the wellbore radius The permeability of the formation before damage and the permeability of the formation after damage are used to determine the skin factor of the formation near any well section; In some embodiments, determining the skin coefficient of the formation near any well section includes: according to the following parameters corresponding to any well section: the wellbore length in the isotropic coordinate system; Permeability ratio in the plane perpendicular to the wellbore , and the distribution of the damage zone radius along the wellbore direction , and the following parameters corresponding to the target well: wellbore radius Formation permeability before damage and the permeability of the damaged formation , determine the skin coefficient of the formation near any well section : ; (14) in, Refers to the direction vector corresponding to the wellbore toe direction, Refers to any plane perpendicular to the wellbore corresponding to the stratum near any well section.

[0049] First, the derivation process of formula (14) is explained in detail based on the distribution characteristics of oil and gas damage zones in the inclined well section of complex well types.

[0050] In anisotropic reservoirs ouvw In the coordinate system uv In the plane, w is a constant, the steady-state seepage equation can be expressed as: ; (15) The above equation is a common second-order linear elliptic partial differential equation, and the internal boundary conditions of the equation are: ; ; (16) Where, is the formation pressure, MPa ; is the bottom hole pressure, MPa ; is the wellbore radius. According to equation (18) and boundary condition (19), in anisotropic reservoirs, the isobars around the wellbore are a series of concentric ellipses. The closer to the wellbore, the closer the ratio of the major axis to the minor axis of the elliptical isobars is to 1, until it reaches a circular wellbore. The schematic diagram of the distribution of isobars and damage of wellbore in anisotropic reservoirs is shown in Figure 6 shown.

[0051] After coordinate transformation, the anisotropic reservoir is converted to For an equivalent isotropic reservoir in the new coordinate system, in the orthogonal plane of the wellbore, the transformation relationship between the two coordinate systems is: ; (17) In an isotropic reservoir, u'-v' The steady-state seepage equation in the plane becomes: ; (18) This equation is the Laplace equation. At the same time, the corresponding internal boundary conditions are converted to: ; (19) Through equation (18) and boundary conditions (19), it can be found that in the equivalent isotropic reservoir, the isobars around the wellbore are a series of confocal concentric ellipses. The expression of the inner boundary condition after coordinate transformation shows that the wellbore shape is transformed into the focus at The ellipse on the axis (from formula (15) ), the farther away from the wellbore, the closer the ratio of the major axis to the minor axis of the elliptical isobar is to 1, and the closer the shape is to a circle. The distribution of isobars and damage conditions in the orthogonal plane of the wellbore are shown in the figure below. Figure 7 shown.

[0052] Conformal transformation is introduced to solve the Laplace equation of the elliptical inner boundary conditions shown in Equations (18) and (19), and the transformation function is taken as: ; (20) Where, , .

[0053] Will A plane in the coordinate system Convert to New plane in the coordinate system , that is, transforming the elliptical potential line in the original plane into a linear potential line in the new plane, such as Figure 8 As shown, the coordinate transformation relationship is as follows: ;(twenty one) Where, is the hyperbolic cosine function, is the hyperbolic sine function.

[0054] According to the conversion relationship of formula (21), Figure 6 The minor axis and major axis of the corresponding elliptical isobars are: 、 Combining formula (19), the minor axis and major axis of the corresponding elliptical wellbore boundary at the wellbore are: ;(twenty two) ;(twenty three) The average value of the major axis and minor axis of the elliptical isobar is taken as the average radius of the ellipse: ;(twenty four) Combining (22), (23), and (24), we can obtain the average radius of the elliptical wellbore corresponding to the isotropic reservoir: ; (25) In anisotropic coordinate system, to solve the boundary of elliptical damage zone, the major axis of the ellipse is defined as the radius of the damage zone. . Convert it to the isotropic coordinate system, we have: ; (26) This corresponds to Figure 8 middle In the coordinate system for: ; (27) Substituting Equation (27) into Equation (26), the average radius of the boundary of the corresponding elliptical damage zone in the isotropic reservoir is obtained as: ; (28) Substitute the average wellbore radius formula (25) and the average damage zone radius formula (28) into the expression of the true skin coefficient of the formation around the well proposed by Hawkins: ; (29) Where, is the formation permeability, in units of ; is the permeability of the damage zone, in units of ; is the wellbore radius, in units of m ; is the radius of the damage zone, in units of m Obtain a plane perpendicular to the wellbore near the wellbore formation in the down-slant well section of the isotropic reservoir The skin factor of the damaged zone is: ; (30) In the above formula, and It can be obtained from equation (2), and It can be obtained from formula (15) when the well inclination angle and well inclination azimuth of the well section are known. Indicates the radius of the damage zone along the toe of the wellbore The distribution of the direction is determined by integrating the local skin coefficient (30) of the orthogonal surface of the wellbore in the well section, and the skin coefficient model (14) of the formation near the inclined well section can be obtained. Similarly, the skin coefficient model of the special case vertical well section and horizontal section can be obtained by the above method.

[0055] The embodiment of the present invention uses the coordinate transformation method and the conformal transformation method to derive the corresponding local skin coefficient of each well section in the wellbore trajectory of a complex well type, which can more accurately describe the damage evolution characteristics during the well construction process of a complex well type and provide theoretical support for the scientific formulation of reservoir protection strategies.

[0056] Then, the first The following parameters are involved in the well section: wellbore length in the isotropic coordinate system , Distribution of damage zone radius along the wellbore direction The determination process is described in detail.

[0057] For wellbore length , the wellbore length corresponding to any well section in the isotropic coordinate system is determined according to the following method: According to any well section of the target well in the anisotropic coordinate system oxyz The following parameters are given: Maximum horizontal permeability parallel to the fracture direction , minimum horizontal permeability perpendicular to the fracture direction , vertical permeability of the formation , determine the first parameter , the second parameter And the third parameter :

[0058] According to the first parameter , the second parameter , the third parameter And any well section in anisotropic coordinate system oxyz The following parameters are: Length , well inclination angle and in x - y The horizontal projection of the plane x Axis angle , determine the wellbore length in the isotropic coordinate system : . The distribution of the damage zone radius along the wellbore direction , the distribution of the damage zone radius corresponding to any well section of the target well along the wellbore direction It is determined based on the oscillation attenuation function model or the empirical formula model.

[0059] First, the distribution law of the damage zone radius along the wellbore direction is specifically described. During drilling operations, since the toe of the well is in contact with the drilling fluid for a shorter time, the radius of the damage zone there is the smallest and the local skin coefficient is the smallest. In special cases, the minimum damage zone radius is the wellbore radius; while the root end has the longest contact time with the drilling fluid and is most damaged, so the damage zone radius is the largest and the local skin coefficient is the largest. The horizontal well skin coefficient model established by Frick TP and Economides MJ and scholars such as Zhang Zhenhua and Liu Xiaoxu regard the distribution of the damage zone radius in isotropic space along the wellbore direction as a linear distribution, and equate the elliptical cone-shaped damage zone to a truncated cone-shaped damage zone, such as Figure 9 shown.

[0060] When Sun Enhui deduced the anisotropic horizontal well productivity considering oil and gas layer damage, he considered the radius of the damage zone in the equivalent isotropic space to be distributed along the wellbore direction as a parabola, such as Figure 10 shown.

[0061] In addition, the physical properties of the oil and gas layer, the performance of the drilling and completion fluid, and the construction parameters will affect the value of the damage zone radius. In actual situations, the distribution of the damage zone radius along the wellbore direction is uneven, such as Figure 11 As shown in Figure 2, this value is also difficult to obtain directly and generally needs to be obtained through indoor experiments.

[0062] Furthermore, the oscillation attenuation function model provided by the embodiment of the present invention is specifically described. In isotropic space, even if there is no formation anisotropy, considering the influence of multiple factors such as drilling and completion fluid properties and construction parameters, the actual damage shape of the oil and gas layer still shows an uneven decreasing distribution from the root end to the toe end of the wellbore. Here, it is assumed that the radius of the damage zone along the toe end of the wellbore is The direction is distributed in the form of an oscillating decay function, such as Figure 12 shown.

[0063] Furthermore, the oscillation attenuation function model includes: ; (31) in, Indicates the The radius of the damage zone corresponding to the well section is along the toe of the wellbore Distribution of directions; Refers to the direction vector corresponding to the toe of the wellbore; Indicates the The maximum damage zone radius corresponding to the wellbore of the section, Indicates the The minimum damage zone radius corresponding to the wellbore of the section.

[0064] It should be noted that 、 They are Figure 7 The maximum and minimum damage zone radii of the wellbore in the corresponding equivalent isotropic reservoir can be determined by the maximum invasion depth model of drilling fluid and completion fluid.

[0065] In some embodiments, the maximum invasion depth model of drilling fluid and completion fluid is as follows: ; (32) In formula (32), is the maximum penetration depth, Drilling fluid soaking time Internal pressure difference Under the action, through 45.8 cm 2 Filtration loss per filtration area, cm 3 ; is the difference between the drilling fluid column pressure and the formation pore pressure. MPa ; represents porosity; K represents reservoir permeability.

[0066] The oscillation attenuation function model provided in an embodiment of the present invention assumes that the radius of the damage zone is distributed along the wellbore direction. In addition to considering the impact of drilling fluid immersion time on formation damage, it also considers the possible impact of drilling and completion fluid properties, construction parameters, etc. on the distribution of the damage zone, thereby optimizing the linear model and the parabolic distribution model to be more in line with actual conditions.

[0067] Next, the empirical formula model provided by the embodiment of the present invention is specifically described. The formula corresponding to the empirical formula model is as follows: ; (33) in, Indicates the penetration depth (i.e., the radius of the damage zone); Represents the radius of the wellbore; 、 30 respectively min Static and dynamic filtration loss; , 、 are the time for the drilling fluid to soak into the target layer and the time for the drilling fluid to circulate through the target layer; 、 、 They are the amount of filtrate absorbed by the rock during soaking, the amount of filtrate absorbed by the rock during mud circulation, and the amount of filtrate in the external mud cake; is the core diameter; is the residual oil saturation; is the residual saturation of rock pores after filtrate invasion; It is the saturation of the original pore volume after the clay absorbs water and expands; Indicates the drilling fluid immersion time; is the average mechanical drilling speed, Indicates the drilling fluid immersion time The corresponding position, Indicates porosity.

[0068] The empirical formula model provided by the embodiment of the present invention can simulate the radius of the damage zone near each point in the wellbore.

[0069] S103, determining an additional pressure drop corresponding to any well section based on a skin coefficient of a formation near the any well section and a reduced permeability of a formation before damage corresponding to the target well; In some embodiments, damage to the oil and gas layer may cause an additional pressure drop in the oil and gas layer around the wellbore. In an isotropic coordinate system, the additional pressure drop is determined according to the following method: : According to the skin coefficient of the formation near any well section ,flow , fluid viscosity , volume coefficient , the reduced permeability of the formation before the damage , and the thickness of the oil and gas layer , determine the additional pressure drop : ; (34) For the skin coefficient of the formation near any well section in formula (34), , can be determined according to formula (14) .

[0070] For the reduced permeability of the formation before damage in formula (34), , the reduced permeability of the formation before the damage It is determined in the following way: According to the target well The following parameters correspond to the well section: oil and gas layer permeability , oil and gas layer thickness and pressure difference , determine the reduced permeability of the formation before damage : ; (35) in, is the total number of well sections of the target well.

[0071] Specifically, the derivation process of (35) is explained in detail.

[0072] First, considering the flow mode of different well sections as plane radial flow, Darcy's law is applied to calculate the single-phase fluid production in steady-state radial flow. , that is, formula (36): ; (36) In formula (36), is the fluid production (flow), usually in cubic meters per day; K is the reservoir permeability; is the effective thickness of the reservoir, in meters (m), indicating the thickness of the reservoir where fluid can flow; Δ P is the production pressure difference; μ is the fluid viscosity; Reservoir radius, in meters (m), represents the boundary radius of the well control area; is the wellbore radius.

[0073] Assume that the pressures at different positions from the point where the complex well enters the oil and gas layer to the well toe are P1, P2, P3, ..., P i ,…,P n The permeabilities of oil and gas layers in different well sections are K1, K2, K3, ..., K i ,…,K n The total production of the well is Equal to the production of each well section sum: ; (37) In formula (37), is the pressure difference of the i-th section of the complex well, in MPa; Indicates the The thickness of the well section; Indicates the permeability of the oil and gas strata in the well section; μ is the fluid viscosity; is the reservoir radius; is the wellbore radius, is the total number of well sections.

[0074] Simplifying formula (37) yields formula (35).

[0075] In some embodiments, according to the target well The following parameters correspond to the well section: oil and gas layer permeability , oil and gas layer thickness , pressure difference and additional pressure drop , determine the reduced permeability of the damaged formation : ; (38) in, is the total number of well sections of the target well.

[0076] S104, determining a total skin factor of the target well based on the following parameters corresponding to any well section: oil and gas layer permeability, oil and gas layer thickness, pressure difference, the additional pressure drop, and distribution of the damage zone radius along the wellbore direction, and the following parameters corresponding to the target well: total wellbore length and wellbore radius; In some embodiments, determining the total skin factor of the target well includes: determining the total skin factor of the target well according to the following parameters corresponding to any well section: oil and gas layer permeability , oil and gas layer thickness , pressure difference , the additional pressure drop and the distribution of the damage zone radius along the wellbore direction , and the following parameters corresponding to the target well: total wellbore length and wellbore radius , determine the total skin factor of the target well : ; (39) in, is the total number of well sections of the target well.

[0077] It should be noted that for formula (39), the average damage zone radius of the entire well can be obtained by dividing the sum of the damage zone radii of each well section by the total length of the wellbore: To convert: ; (40) Combining equations (29), (35), (38), and (40), we can obtain the total skin coefficient of a complex well with different wellbore trajectories in an anisotropic reservoir: , that is, formula (39).

[0078] The present invention also provides a method for calculating the pseudo-skin coefficient (one of the skin coefficients), and a method for calculating the productivity of a complex well using the pseudo-skin coefficient. method.

[0079] First, for the inclined well section in a complex well type, the pseudo-skin coefficient is generated due to the well deviation. , oil and gas layer damage produces true skin coefficient , then the productivity equation of the inclined well section under the condition of single-phase steady-state seepage infinite plate-like reservoir considering oil and gas layer damage is: ; (41) in, is the reservoir permeability; is the effective thickness of the reservoir; Δ P is the production pressure difference; μ is the fluid viscosity; Indicates the oil volume coefficient; is the reservoir radius, in meters (m), indicating the boundary radius of the well control area; is the wellbore radius; true skin coefficient The pseudo-skin coefficient can be determined by formula (39): It is determined in the following way: First, according to any well section of the target well in the anisotropic coordinate system oxyz The following parameters are given: Maximum horizontal permeability parallel to the fracture direction , minimum horizontal permeability perpendicular to the fracture direction , vertical permeability of the formation , determine the first parameter , the second parameter And the third parameter :

[0080] Then, according to the first parameter , the second parameter , the third parameter , well inclination angle , wellbore radius , wellbore length and in x - y The horizontal projection of the plane x Axis angle , determine the pseudo-skin coefficient of the wellbore with high deviation in anisotropic reservoir : (42) In some embodiments, using Figure 13The horizontal well shown in FIG. 1 is a specific illustration of the method for calculating the total skin factor of a complex well provided by an embodiment of the present invention. Figure 13 As shown in Figure 1, the well section within the oil and gas layer includes a vertical well section, an inclined well section, and a horizontal section, all of which have been opened. r w =0.2m, thickness of oil and gas layer h =50m, the oil and gas layer section permeability K=1000mD, the average formation permeability of the damaged zone is 500mD, the oil and gas layer section porosity is 20%, the formation anisotropy coefficient =3, crude oil viscosity =30mPa•s, crude oil volume coefficient B o =1.058, formation pressure is 13.5MPa, bottom hole pressure is 10MPa. According to experimental tests and the high temperature and high pressure filtration loss test of drilling fluid, the filtration loss of drilling fluid within 30min is 15ml at 3.5MPa.

[0081] It should be noted that Figure 13 Any section of the horizontal well shown in the anisotropic coordinate system oxyz The maximum horizontal permeability parallel to the fracture direction under Minimum horizontal permeability perpendicular to the fracture direction Same, that is = .

[0082] First, according to formula (6), the wellbore lengths corresponding to the well sections included in the horizontal well are converted into wellbore lengths in the isotropic coordinate system, which are: 20.80 m, 23.81 m, and 219.15 m, respectively.

[0083] Then, according to formula (13), the permeability ratio of each section of the horizontal well in the wellbore orthogonal plane in the isotropic coordinate system is obtained: , respectively: .

[0084] Substituting the relevant parameters into formula (32), the maximum invasion depth of drilling fluid in the near-wellbore zone is obtained as r dmax =0.52m.

[0085] According to the oscillation attenuation function model (31), the damage zone ranges of each section of the horizontal well are 6.73m 2 , 7.72m 2 , 65.06m 2 .

[0086] Furthermore, according to formula (40), the average converted damage zone radius of the entire well section corresponding to this horizontal well is 0.30 m.

[0087] According to formula (35), the pre-damage formation permeability corresponding to the target well is 236.25 mD; According to formula (14), the skin coefficients of the formations around the three well sections are 3.19, 3.68, and 4.77, respectively. Then, the additional pressure drops are obtained from formula (34): 2.34 MPa, 2.70 MPa, and 3.50 MPa.

[0088] According to formula (38), the permeability of the damaged formation corresponding to the target well is 17.60 mD; Finally, substituting the above parameters into formula (39), the total skin coefficient corresponding to the horizontal well can be obtained as: 14.37.

[0089] An embodiment of the present invention provides a device for calculating the total skin coefficient of a complex well, comprising: a memory configured to store instructions; and a processor configured to call the instructions from the memory and implement the method for calculating the total skin coefficient of a complex well when executing the instructions.

[0090] An embodiment of the present invention provides a processor for running a program, wherein the program is used to execute the method for calculating the total skin factor of a complex well when the program is run. An embodiment of the present invention provides a computer program product, including a computer program, which implements the method for calculating the total skin factor of a complex well when executed by a processor.

[0091] The method for calculating the total skin coefficient of a complex well provided in an embodiment of the present invention is based on the permeability change and the damage zone radius distribution to determine the total skin coefficient corresponding to the complex well. It can more accurately calculate the skin coefficient of complex well types and provide a scientific basis for the rational formulation of reservoir protection measures.

[0092] Example 2 As oil and gas exploration and development gradually advance towards deep, ultra-deep, and low-permeability reservoirs, horizontal well technology has become a crucial tool for improving oil and gas recovery and optimizing reservoir development methods. Compared to vertical or directional wells, horizontal wells significantly increase the contact area with the reservoir, thereby increasing single-well productivity. However, due to the longer horizontal well sections and the increased number of factors controlling wellbore stability, traditional drilling and completion fluid designs are unable to meet the demands of modern, complex well conditions. This leads to frequent problems such as wellbore instability, lost circulation, well collapse, and reservoir damage, seriously impacting drilling safety and the profitability of oil and gas field development.

[0093] In the prior art, the design of drilling and completion fluids mainly relies on the experience and experimental data of engineers, and the density, viscosity, filtration loss and other parameters of the drilling and completion fluids are adjusted according to the formation characteristics, well wall mechanics analysis and rheological requirements. However, this experience-based design method has the following limitations: it is highly dependent on experience and is difficult to adapt to changing well conditions - due to the complex and changeable formation characteristics, a single empirical method is difficult to provide the optimal drilling and completion fluid formula, especially in special well conditions such as ultra-deep wells, high-temperature and high-pressure (HPHT) wells, and large-reach wells. The empirical adjustment method is prone to parameter mismatch, affecting drilling safety. Moreover, traditional drilling and completion fluid optimization methods are usually based on static data calculations, which makes it difficult to achieve real-time optimization and cannot be dynamically adjusted according to changes in the downhole environment, thereby increasing well control risks and reservoir damage risks. Based on this, Example 2 of the present invention provides a drilling and completion fluid design expert method driven by knowledge and data coupling based on Example 1. The method includes: S201. Determine the total skin coefficient of a target well according to the method for calculating the total skin coefficient of a complex well described in Example 1; S202: When the total skin coefficient of the target well is less than or equal to 0, it is determined that the drilling fluid and completion fluid corresponding to the target well have good performance and no optimization design is required; S203: When the total skin coefficient of the target well is greater than 0, the drilling fluid corresponding to the target well is optimized and designed according to S301, and the completion fluid corresponding to the target well is optimized and designed according to S302: S301. Determine a target drilling fluid formulation corresponding to the target well according to the permeability and / or structural characteristics of the reservoir corresponding to the target well and preset drilling fluid formulations corresponding to different permeabilities and / or structural characteristics.

[0094] It should be noted that the structural characteristics of the reservoir include: non-fractured reservoir and fractured reservoir.

[0095] First, the reservoir is divided into three categories according to the reservoir permeability: low permeability reservoir, medium permeability reservoir and high permeability reservoir. The classification standards are as follows: High permeability reservoir: greater than 500×10 -3 μm 2 ; Medium permeability reservoir: 50~500×10 -3 μm 2 ; Low permeability and ultra-low permeability reservoir: less than 5.0×10 -3 μm 2 .

[0096] Then, when the permeability of the reservoir corresponding to the target well is greater than 500×10 -3 μm 2(High permeability reservoir) and non-fractured reservoir, the target drilling fluid formula is: Formula 1: upper drilling fluid + (1-2)% oil film type reservoir protection new material LCM-8 + (2-3)% ideal filler; The permeability of the reservoir corresponding to the target well is greater than 500×10 -3 μm 2 (High permeability reservoir) and when it is a fractured reservoir, the target drilling fluid formula is: Formula 2: upper drilling fluid + 0.6% XG xanthan gum; The permeability of the reservoir corresponding to the target well is between 50 and 500×10 -3 μm 2 When the reservoir is between (medium permeability reservoir) and non-fractured reservoir, the target drilling fluid formula is: Formula 3: upper drilling fluid + (2-4)% oil film type reservoir protection new material LCM-8; The permeability of the reservoir corresponding to the target well is between 50 and 500×10 -3 μm 2 When the reservoir is between (medium permeability reservoir) and fractured, the target drilling fluid formula is: Formula 4: upper drilling fluid + 0.6% xanthan gum XG; and The permeability of the reservoir corresponding to the target well is less than 5.0×10 -3 μm 2 (low-permeability and extra-low-permeability reservoir), the target drilling fluid formula is: Formula 5: upper drilling fluid + (2-3)% oil film type reservoir protection new material LCM-8 + (0.2-0.4)% surfactant FCS-08.

[0097] S302: Determine a target completion fluid formula corresponding to the target well based on the type of completion fluid corresponding to the target well and preset completion fluid formulas corresponding to different completion fluid types; Specifically, the types of completion fluid include: solid-free completion fluid and low-damage surfactant completion fluid.

[0098] In some embodiments, when the completion fluid corresponding to the target well is a solid-free completion fluid, the target completion fluid formula is: Formula 6: clean water + 76% anti-collapse plugging agent KR + 3% fluid loss reducer ZT-2 + X% limestone powder; and When the completion fluid corresponding to the target well is a low-damage surfactant completion fluid, the target completion fluid formula is: Formula 7: clean water + 0.2% viscosity-increasing fluid loss reducer + 0.3% zwitterionic polymer FA367 + 3% cationic polymer clay stabilizer YNJ + 3% fine-mesh CaCO3 + 0.2% inhibitor SK-2 + 1% water-locking agent JSS + 1% corrosion inhibitor ZH-III + Y% weighting agent; The calculation formulas for X and Y in formulas 6 and 7 are as follows:

[0099]

[0100] Indicates the preset completion fluid density value.

[0101] An embodiment of the present invention further provides a drilling and completion fluid design expert system driven by knowledge and data coupling, the system comprising: Total skin coefficient calculation module: used to calculate the total skin coefficient of the target well; Optimization module: used for determining that the drilling fluid and completion fluid corresponding to the target well have good performance and no optimization design is required when the total skin coefficient of the target well is less than or equal to 0; When the total skin factor of the target well is greater than 0, the drilling fluid and completion fluid corresponding to the target well are optimized according to the following method: Determining a target drilling fluid formulation corresponding to the target well based on the permeability and / or structural characteristics of the reservoir corresponding to the target well and preset drilling fluid formulations corresponding to different permeabilities and / or structural characteristics; and Determining a target completion fluid formula corresponding to the target well based on the type of completion fluid corresponding to the target well and preset completion fluid formulas corresponding to different completion fluid types; Among them, the structural characteristics of the reservoir include: non-fractured reservoir and fractured reservoir; the types of completion fluid include: solid-free completion fluid and low-damage surfactant completion fluid; the total skin coefficient of the target well is determined by the method for calculating the total skin coefficient of a complex well described in Example 1.

[0102] The knowledge and data coupling-driven drilling and completion fluid design expert method provided by the embodiment of the present invention calculates the total skin coefficient of the target well and provides corresponding optimization decisions for the drilling fluid and completion fluid corresponding to the target well based on the total skin coefficient of the target well. On the one hand, it can solve the problems of difficulty, poor adaptability, and reliance on experience in the optimization design of drilling fluid and completion fluid under complex formation conditions. On the other hand, the total skin coefficient of the target well can be used to obtain real-time changes in the downhole environment, thereby making dynamic adjustments based on changes in the downhole environment and reducing well control risks and reservoir damage risks.

[0103] Those skilled in the art will appreciate that the embodiments of the present application may be provided as methods, systems, or computer program products. Therefore, the present application may take the form of an entirely hardware embodiment, an entirely software embodiment, or an embodiment combining software and hardware. Furthermore, the present application 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.

[0104] The present application is described with reference to the flowcharts and / or block diagrams of the methods, devices (systems), and computer program products according to the embodiments of the present application. It should be understood that each process and / or block in the flowchart and / or block diagram, as well as the combination of processes and / or blocks in the flowchart and / or block diagram, 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 flowchart and / or block diagram. 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.

[0105] 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.

[0106] 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.

[0107] In a typical configuration, a computing device includes one or more processors (CPUs), input / output interfaces, network interfaces, and memory.

[0108] The memory may include non-permanent memory 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. The memory is an example of a computer-readable medium.

[0109] Computer-readable media includes both permanent and non-permanent, removable and non-removable media that can be implemented using any method or technology for information storage. 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 RAM (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 technologies, 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, such as modulated data signals and carrier waves.

[0110] It should also be noted that the terms "comprises," "includes," or any other variations thereof are intended to encompass non-exclusive inclusion, such that a process, method, commodity, or apparatus that includes a series of elements includes not only those elements but also other elements not explicitly listed, or includes elements inherent to such process, method, commodity, or apparatus. In the absence of further limitations, an element defined by the phrase "comprises a ..." does not exclude the presence of other identical elements in the process, method, commodity, or apparatus that includes the element.

[0111] The above are merely embodiments of the present application and are not intended to limit the present application. For those skilled in the art, the present application may have various changes and variations. Any modifications, equivalent replacements, improvements, etc. made within the spirit and principles of the present application should all be included within the scope of the claims of the present application.

Claims

1. A method for calculating the total skin factor of a complex well, characterized in that: The method comprises: By coordinate transformation, the permeability ratio of any well section of the target well in the wellbore orthogonal plane in the isotropic coordinate system is determined; According to the following parameters corresponding to any well section: the ratio of the wellbore length and the permeability in the wellbore orthogonal plane in the isotropic coordinate system, the distribution of the damage zone radius along the wellbore direction, and the following parameters corresponding to the target well: the wellbore radius The permeability of the formation before damage and the permeability of the formation after damage are used to determine the skin factor of the formation near any well section; determining an additional pressure drop corresponding to any well section based on a skin coefficient of a formation near the any well section and a reduced permeability of a formation before damage corresponding to the target well; and Determining a total skin factor of the target well based on the following parameters corresponding to any well section: oil and gas layer permeability, oil and gas layer thickness, pressure difference, the additional pressure drop, and the distribution of the damage zone radius along the wellbore direction, and the following parameters corresponding to the target well: total wellbore length and wellbore radius; Wherein, any well section of the target well is a vertical well section, a horizontal well section or a inclined well section.

2. The method according to claim 1, characterized in that The determination of the permeability ratio of any well section of the target well in a wellbore orthogonal plane in an isotropic coordinate system includes: According to any well section of the target well in the anisotropic coordinate system oxyz Bottom: Maximum horizontal permeability parallel to the fracture direction , minimum horizontal permeability perpendicular to the fracture direction , vertical permeability of the formation , well inclination angle , and in x - y The horizontal projection of the plane x Axis angle , determine the permeability ratio of any well section of the target well in the wellbore orthogonal plane in the isotropic coordinate system : 。 3. The method according to claim 1, characterized in that The wellbore length corresponding to any well section in the isotropic coordinate system is determined according to the following method: According to any well section of the target well in the anisotropic coordinate system oxyz The following parameters are given: Maximum horizontal permeability parallel to the fracture direction , minimum horizontal permeability perpendicular to the fracture direction , vertical permeability of the formation , determine the first parameter , the second parameter And the third parameter : According to the first parameter The second parameter , the third parameter And any well section of the target well in the anisotropic coordinate system oxyz The following parameters are: Length , well inclination angle and in x - y The horizontal projection of the plane x Axis angle , determine the wellbore length in the isotropic coordinate system : 。 4. The method according to claim 1, wherein Determining the skin factor of the formation near any well section includes: According to the following parameters corresponding to any well section: wellbore length in isotropic coordinate system Permeability ratio in the plane perpendicular to the wellbore , and the distribution of the damage zone radius along the wellbore direction , and the following parameters corresponding to the target well: wellbore radius Formation permeability before damage and the permeability of the damaged formation , determine the skin coefficient of the formation near any well section : ； in, Refers to the direction vector corresponding to the wellbore toe direction, Refers to any plane perpendicular to the wellbore corresponding to the stratum near any well section.

5. The method according to claim 1, wherein The permeability of the formation before damage corresponding to the target well It is determined in the following way: According to the target well The following parameters correspond to the well section: oil and gas layer permeability , oil and gas layer thickness and pressure difference , determine the pre-damage reduced permeability of the formation corresponding to the target well : ； in, is the total number of well sections of the target well.

6. The method according to claim 1, characterized in that The permeability of the damaged formation corresponding to the target well is based on oxyz The three-dimensional steady-state partial differential equation of the single-phase incompressible liquid flow in the reservoir is determined in the coordinate system.

7. The method according to claim 1, characterized in that The determining of the additional pressure drop corresponding to any well section includes: determining the additional pressure drop corresponding to any well section according to the skin coefficient of the formation near the well section; ,flow , fluid viscosity , volume coefficient , the reduced permeability of the formation before the damage , and the thickness of the oil and gas layer , determine the additional pressure drop : 。 8. The method according to claim 1, characterized in that Determining the total skin factor of the target well includes: According to the following parameters corresponding to any well section: oil and gas layer permeability , oil and gas layer thickness , pressure difference , the additional pressure drop and the distribution of the damage zone radius along the wellbore direction , and the following parameters corresponding to the target well: total wellbore length and wellbore radius , determine the total skin factor of the target well : ； in, is the total number of well sections of the target well.

9. The method according to claim 1, characterized in that The distribution of the damage zone radius corresponding to any well section of the target well along the wellbore direction is determined according to an oscillation attenuation function model or an empirical formula model.

10. The method according to claim 9, characterized in that The oscillation attenuation function model includes: ； in, Indicates the The radius of the damage zone corresponding to the well section is along the toe of the wellbore Distribution of directions; Refers to the direction vector corresponding to the wellbore toe direction; Indicates the The maximum damage zone radius corresponding to the wellbore of the section, Indicates the The minimum damage zone radius corresponding to the wellbore of the section.

11. The method according to claim 9, characterized in that The empirical formula model includes: in; Indicates the radius of the damage zone; Represents the radius of the wellbore; represents porosity; 、 30 respectively min Static and dynamic filtration loss; , 、 are the time for the drilling fluid to soak into the target layer and the time for the drilling fluid to circulate through the target layer; 、 、 They are the amount of filtrate absorbed by the rock during soaking, the amount of filtrate absorbed by the rock during mud circulation, and the amount of filtrate in the external mud cake; is the core diameter; is the residual oil saturation; is the residual saturation of rock pores after filtrate invasion; It is the saturation of the original pore volume after the clay absorbs water and expands; Indicates the drilling fluid immersion time; is the average mechanical drilling speed; Refers to the drilling fluid immersion time The corresponding position.

12. A device for calculating the total skin factor of a complex well, characterized in that: include: a memory configured to store instructions; and a processor configured to call the instructions from the memory and implement the method for calculating the total skin factor of a complex well according to any one of claims 1 to 11 when executing the instructions.

13. A processor, characterized in that: Used for running a program, wherein the program is used to execute: the method for calculating the total skin factor of a complex well according to any one of claims 1 to 11 when being run.

14. A computer program product, characterized in that The invention comprises a computer program, which, when executed by a processor, implements the method for calculating the total skin factor of a complex well according to any one of claims 1 to 11.

15. A knowledge and data coupled driven drilling and completion fluid design expert method, characterized in that: The method comprises: When the total skin coefficient of the target well is less than or equal to 0, it is determined that the drilling fluid and completion fluid corresponding to the target well have good performance and no optimization design is required; When the total skin factor of the target well is greater than 0, the drilling fluid and completion fluid corresponding to the target well are optimized according to the following method: Determining a target drilling fluid formulation corresponding to the target well based on the permeability and / or structural characteristics of the reservoir corresponding to the target well and preset drilling fluid formulations corresponding to different permeabilities and / or structural characteristics; and Determining a target completion fluid formula corresponding to the target well based on the type of completion fluid corresponding to the target well and preset completion fluid formulas corresponding to different completion fluid types; Wherein, the structural characteristics of the reservoir include: non-fractured reservoir and fractured reservoir; the types of the completion fluid include: solid-free completion fluid and low-damage surfactant completion fluid; the total skin coefficient of the target well is determined by the method for calculating the total skin coefficient of a complex well as described in any one of claims 1 to 11.

16. The method according to claim 15, characterized in that Determining the target drilling fluid formula corresponding to the target well includes: The permeability of the reservoir corresponding to the target well is greater than 500×10 -3 μm 2 When the reservoir is non-fractured, the target drilling fluid formula is: Formula 1: upper drilling fluid + (1-2)% oil film type reservoir protection new material LCM-8 + (2-3)% ideal filler; The permeability of the reservoir corresponding to the target well is greater than 500×10 -3 μm 2 When the reservoir is fractured, the target drilling fluid formula is: Formula 2: upper drilling fluid + 0.6% xanthan gum XG; The permeability of the reservoir corresponding to the target well is between 50 and 500×10 -3 μm 2 When the reservoir is between 100 and 150 nm and is non-fractured, the target drilling fluid formula is: Formula 3: upper drilling fluid + (2-4)% oil film type reservoir protection new material LCM-8; The permeability of the reservoir corresponding to the target well is between 50 and 500×10 -3 μm 2 When the reservoir is fractured, the target drilling fluid formula is: Formula 4: upper drilling fluid + 0.6% xanthan gum XG; and The permeability of the reservoir corresponding to the target well is less than 5.0×10 -3 μm 2 When the target drilling fluid formula is: Formula 5: upper drilling fluid + (2-3)% oil film type reservoir protection new material LCM-8 + (0.2-0.4)% surfactant FCS-08.

17. The method according to claim 15, characterized in that Determining the target completion fluid formula corresponding to the target well includes: When the completion fluid corresponding to the target well is a solid-free completion fluid, the target completion fluid formula is: Formula 6: clean water + 76% anti-collapse plugging agent KR + 3% fluid loss reducer ZT-2 + X% limestone powder; and When the completion fluid corresponding to the target well is a low-damage surfactant completion fluid, the target completion fluid formula is: Formula 7: clean water + 0.2% viscosity-increasing fluid loss reducer + 0.3% zwitterionic polymer FA367 + 3% cationic polymer clay stabilizer YNJ + 3% fine-mesh CaCO3 + 0.2% inhibitor SK-2 + 1% water-locking agent JSS + 1% corrosion inhibitor ZH-III + Y% weighting agent; The calculation formulas for X and Y in formulas 6 and 7 are as follows: Indicates the preset completion fluid density value.

18. A knowledge and data coupled driven drilling and completion fluid design expert system, characterized in that: The system comprises: Total skin coefficient calculation module: used to calculate the total skin coefficient of the target well; Optimization module: used for determining that the drilling fluid and completion fluid corresponding to the target well have good performance and no optimization design is required when the total skin coefficient of the target well is less than or equal to 0; When the total skin factor of the target well is greater than 0, the drilling fluid and completion fluid corresponding to the target well are optimized according to the following method: Determining a target drilling fluid formulation corresponding to the target well based on the permeability and / or structural characteristics of the reservoir corresponding to the target well and preset drilling fluid formulations corresponding to different permeabilities and / or structural characteristics; and Determining a target completion fluid formula corresponding to the target well based on the type of completion fluid corresponding to the target well and preset completion fluid formulas corresponding to different completion fluid types; Wherein, the structural characteristics of the reservoir include: non-fractured reservoir and fractured reservoir; the types of the completion fluid include: solid-free completion fluid and low-damage surfactant completion fluid; the total skin coefficient of the target well is determined by the method for calculating the total skin coefficient of a complex well as described in any one of claims 1 to 11.

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