Knowledge and data coupled driving drilling and completion fluid design expert system

Abstract

This invention provides a knowledge- and data-driven drilling and completion fluid design expert system, belonging to the field of reservoir protection technology in the petroleum industry. The system includes: a total skin factor calculation module for calculating the total skin factor of a target well; and an optimization module for determining that the drilling and completion fluids corresponding to the target well have good performance and require no optimization design when the total skin factor of the target well is less than or equal to 0; and for optimizing the drilling and completion fluids corresponding to the target well when the total skin factor of the target well is greater than 0, by: determining a target drilling fluid formula based on the permeability and / or structural characteristics of the reservoir corresponding to the target well, and pre-setting drilling fluid formulas corresponding to different permeability and / or structural characteristics; and determining a target completion fluid formula based on the type of completion fluid corresponding to the target well and pre-setting completion fluid formulas corresponding to different completion fluid types.

Description

Technical Field

[0001] This invention relates to the field of reservoir protection technology in the petroleum industry, specifically to a method, apparatus, processor, and computer program product for calculating the total skin coefficient of complex wells, as well as a knowledge- and data-coupled driven drilling and completion fluid design expert method and a knowledge- and data-coupled driven drilling and completion fluid design expert system. Background Technology

[0002] As oil and gas exploration and development gradually advances into deeper, ultra-deep, and low-permeability reservoirs, horizontal well technology has become an important means to improve oil and gas recovery and optimize reservoir development. Compared to vertical or directional wells, horizontal wells can 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 insufficient 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 affecting the safety of drilling operations and the efficiency of oil and gas field development.

[0003] In existing technologies, the design of drilling and completion fluids mainly relies on engineers' experience and experimental data. Parameters such as density, viscosity, and fluid loss are adjusted based on formation characteristics, wellbore mechanical analysis, and rheological requirements. However, this experience-based design method has the following limitations: it is highly dependent on experience and difficult to adapt to varying well conditions. Due to the complex and variable nature of formations, a single experience-based method cannot provide the optimal drilling and completion fluid formulation. Especially in special well conditions such as ultra-deep wells, high-temperature and high-pressure (HPHT) wells, and extended reach wells, experience-based adjustments can easily lead to parameter mismatches, affecting drilling safety. Furthermore, traditional drilling and completion fluid optimization methods are usually based on static data calculations, making real-time optimization difficult and unable to dynamically adjust according to changes in the downhole environment, thus increasing well control risks and reservoir damage risks. Summary of the Invention

[0004] The purpose of this invention is to provide a method, apparatus, processor, and computer program product for calculating the total skin factor of complex wells, as well as a knowledge and data coupled-driven drilling and completion fluid design expert method and system, 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 the present invention provides a method for calculating the total skin factor of a complex well, the method comprising:

[0006] By transforming coordinates, the permeability ratio of any section of the target well in the orthogonal plane of the wellbore in an isotropic coordinate system is determined.

[0007] Based on the following parameters corresponding to any well section: wellbore length in an isotropic coordinate system, permeability ratio in the orthogonal plane of the wellbore, distribution of the damage zone radius along the wellbore direction, and the following parameters corresponding to the target well: wellbore radius. The formation permeability before and after damage is used to determine the skin coefficient of the formation near any well section.

[0008] Based on the skin factor of the formation near any well section and the pre-damage formation permeability of the target well, determine the additional pressure drop corresponding to any well section; and

[0009] Based on the following parameters corresponding to any well section: oil and gas reservoir permeability, oil and gas reservoir 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 coefficient of the target well;

[0010] Wherein, any section of the target well is a vertical section, a horizontal section, or an inclined section.

[0011] Preferably, the permeability ratio of any well section of the target well in the orthogonal plane of the wellbore in an isotropic coordinate system includes:

[0012] Based on any section of the target well in the anisotropic coordinate system oxyz Below: Maximum horizontal permeability parallel to the direction of the fracture Minimum horizontal permeability perpendicular to the crack direction Vertical permeability of formations , well inclination angle and in x - y Horizontal projection of a plane and x Angle between axes Determine the permeability ratio of any section of the target well in the orthogonal plane of the wellbore in an isotropic coordinate system. :

[0013] .

[0014] Preferably, the wellbore length corresponding to any well section in an isotropic coordinate system is determined according to the following method:

[0015] Based on any section of the target well in the anisotropic coordinate system oxyz The following parameters are included: maximum horizontal permeability parallel to the fracture direction. Minimum horizontal permeability perpendicular to the crack direction Vertical permeability of formations Determine the first parameter Second parameter and the third parameter :

[0016]

[0017] According to the first parameter The second parameter The third parameter and any section of the target well in the anisotropic coordinate system oxyz The following parameters are listed: length , well inclination angle And in x - y Horizontal projection of a plane and x Angle between axes Determine the wellbore length in an isotropic coordinate system. :

[0018] .

[0019] Preferably, determining the skin factor of the formation near any well section includes:

[0020] Based on the following parameters corresponding to any well section: wellbore length in an isotropic coordinate system. Permeability ratio in the plane orthogonal 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 of the well sections. :

[0021] ;

[0022] in, The direction vector corresponding to the direction of the wellbore toe. It refers to any plane orthogonal to the wellbore corresponding to the formation near any well section.

[0023] Preferably, the formation permeability before damage corresponding to the target well is... It is determined in the following manner:

[0024] According to the target well's... The following parameters correspond to the well section: oil and gas reservoir permeability Oil and gas layer thickness and pressure difference Determine the formation permeability before damage corresponding to the target well. :

[0025] ;

[0026] in, The total number of well sections of the target well.

[0027] Preferably, the formation permeability after damage corresponding to the target well is based on... oxyz The three-dimensional steady-state partial differential equation for seepage of a single-phase incompressible liquid in an oil reservoir is determined in a coordinate system.

[0028] Preferably, determining the additional pressure drop corresponding to any well section includes: based on the skin coefficient of the formation near the well section. ,flow Fluid viscosity Volume index The formation permeability before the damage and the thickness of oil and gas reservoirs Determine the additional pressure drop :

[0029] .

[0030] Preferably, determining the total skin factor of the target well includes:

[0031] Based on the following parameters corresponding to any of the well sections: oil and gas reservoir permeability Oil and gas layer thickness Pressure difference The additional pressure drop and the distribution of the radius of the damage zone 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. :

[0032]

[0033] in, The total number of well sections of the target well.

[0034] Preferably, the distribution of the damage zone radius along the wellbore direction corresponding to any section of the target well is determined based on an oscillation decay function model or an empirical formula model.

[0035] Preferably, the oscillation decay function model includes:

[0036] ;

[0037] in, Indicates the first The radius of the damage zone corresponding to the section of the wellbore extends along the toe of the wellbore. Distribution of directions; The direction vector corresponding to the direction of the wellbore toe; Indicates the first The radius of the maximum damage zone corresponding to the wellbore section. Indicates the first The minimum damage zone radius corresponding to the wellbore of the section.

[0038] Preferably, the empirical formula model includes:

[0039]

[0040] in; Indicates the radius of the damage zone; Represents the radius of the wellbore; Indicates porosity; , 30 respectively min Static and dynamic filtration loss; , , These are the time for the drilling fluid to soak the target formation and the time for the drilling fluid to circulate through the target formation, respectively. , , These represent 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 outer mud cake, respectively. The diameter of the rock core; Residual oil saturation; This represents the residual saturation of the rock pores after the filtrate has penetrated. The saturation degree of clay after it absorbs water and expands, occupying the original pore volume; Indicates the drilling fluid soaking time; This represents the average mechanical drilling speed; This refers to the drilling fluid soaking time. The corresponding position at that time.

[0041] A second aspect of the present invention provides an apparatus for calculating the total skin factor of a complex well, comprising: a memory configured to store instructions; and a processor configured to retrieve the instructions from the memory and, when executing the instructions, to implement the method for calculating the total skin factor of the complex well.

[0042] A third aspect of the present invention provides a processor for running a program, wherein the program is run to execute: the method for calculating the total skin coefficient of a complex well.

[0043] A fourth aspect of the present invention provides a computer program product, including a computer program that, when executed by a processor, implements the method for calculating the total skin coefficient of a complex well.

[0044] A fifth aspect of this invention provides a knowledge- and data-coupled expert method for drilling and completion fluid design, the method comprising:

[0045] When the total skin coefficient of the target well is less than or equal to 0, the drilling fluid and completion fluid corresponding to the target well are deemed to have good performance and no optimization design is required.

[0046] 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:

[0047] Based on the permeability and / or structural characteristics of the reservoir corresponding to the target well, and pre-set drilling fluid formulations corresponding to different permeability and / or structural characteristics, the target drilling fluid formulation for the target well is determined; and

[0048] The target completion fluid formula for the target well is determined based on the type of completion fluid corresponding to the target well and the preset completion fluid formulas corresponding to different completion fluid types.

[0049] The structural characteristics of the reservoir include: non-fractured reservoirs and fractured reservoirs; the types of completion fluids include: solids-free completion fluids and low-damage surfactant completion fluids; the total skin factor of the target well is determined by the method for calculating the total skin factor of complex wells.

[0050] Preferably, determining the target drilling fluid formulation corresponding to the target well includes:

[0051] The permeability of the reservoir corresponding to the target well is greater than 500 × 10⁻⁶. -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;

[0052] The permeability of the reservoir corresponding to the target well is greater than 500 × 10⁻⁶. -3 μm 2 When the reservoir is fractured, the target drilling fluid formulation is: Formulation 2: Upper drilling fluid + 0.6% xanthan gum XG;

[0053] The permeability of the reservoir corresponding to the target well is between 50 and 500 × 10⁻⁶. -3 μm 2When the reservoir is between and is not fractured, the target drilling fluid formula is: Formula 3: Upper drilling fluid + (2-4)% oil film type reservoir protection new material LCM-8;

[0054] The permeability of the reservoir corresponding to the target well is between 50 and 500 × 10⁻⁶. -3 μm 2 When the reservoir is fractured, the target drilling fluid formulation is: Formulation 4: Upper drilling fluid + 0.6% xanthan gum XG; and

[0055] The permeability of the reservoir corresponding to the target well is less than 5.0 × 10⁻⁶. -3 μm 2 At that time, the target drilling fluid formulation is: Formulation 5: Upper drilling fluid + (2~3)% oil film type reservoir protection new material LCM-8 + (0.2~0.4)% surfactant FCS-08.

[0056] Preferably, the determination of the target completion fluid formulation corresponding to the target well includes:

[0057] When the completion fluid corresponding to the target well is a solids-free completion fluid, the target completion fluid formula is: Formula Six: clean water + 76% anti-collapse plugging agent KR + 3% filtration loss reducer ZT-2 + X% limestone powder; and

[0058] 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 enhancer and filtration reducer + 0.3% zwitterionic polymer FA367 + 3% cationic polymer clay stabilizer YNJ + 3% fine CaCO3 + 0.2% inhibitor SK-2 + 1% water-locking agent JSS + 1% corrosion inhibitor ZH-III + Y% weighting agent;

[0059] The formulas for calculating X and Y in Formulas 6 and 7 are as follows:

[0060]

[0061]

[0062] This indicates the preset completion fluid density value.

[0063] A sixth aspect of this invention provides a knowledge- and data-coupled drilling and completion fluid design expert system, the system comprising:

[0064] Total skin coefficient calculation module: used to calculate the total skin coefficient of the target well;

[0065] Optimization module: used to determine 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;

[0066] 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:

[0067] Based on the permeability and / or structural characteristics of the reservoir corresponding to the target well, and pre-set drilling fluid formulations corresponding to different permeability and / or structural characteristics, the target drilling fluid formulation for the target well is determined; and

[0068] The target completion fluid formula for the target well is determined based on the type of completion fluid corresponding to the target well and the preset completion fluid formulas corresponding to different completion fluid types.

[0069] The structural characteristics of the reservoir include: non-fractured reservoirs and fractured reservoirs; the types of completion fluids include: solids-free completion fluids and low-damage surfactant completion fluids; the total skin factor of the target well is determined by the method for calculating the total skin factor of complex wells.

[0070] The knowledge- and data-driven drilling and completion fluid design expert method provided in this invention calculates the total skin factor of the target well and provides corresponding optimization decisions for the drilling and completion fluids based on the total skin factor. On the one hand, it can solve the problems of difficult, poor adaptability, and reliance on experience in optimizing the design of drilling and completion fluids under complex formation conditions. On the other hand, by using the total skin factor of the target well, it can 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.

[0071] Other features and advantages of the embodiments of the present invention will be described in detail in the following detailed description section. Attached Figure Description

[0072] The accompanying drawings are provided to further illustrate embodiments of the present invention and form part of the specification. They are used together with the following detailed description to explain the embodiments of the present invention, but do not constitute a limitation thereof. In the drawings:

[0073] Figure 1 This is a flowchart illustrating the method for calculating the total skin coefficient of a complex well according to an embodiment of the present invention;

[0074] Figure 2 This is provided by the embodiments of the present invention. oxyz A diagram showing the positional relationship of deviated well sections in anisotropic reservoirs under a coordinate system;

[0075] Figure 3This is provided by the embodiments of the present invention. Locational relationship of inclined well sections in isotropic reservoirs under coordinate system;

[0076] Figure 4 This is provided by the embodiments of the present invention. Locational relationship of inclined well sections in isotropic reservoirs under coordinate system;

[0077] Figure 5 This is provided by the embodiments of the present invention. Locational relationship of inclined well sections in isotropic reservoirs under coordinate system;

[0078] Figure 6 This is a schematic diagram of the damage situation in the orthogonal plane of the wellbore in an anisotropic reservoir provided by an embodiment of the present invention;

[0079] Figure 7 This is a schematic diagram of the damage situation in the orthogonal plane of the wellbore in an isotropic reservoir provided by an embodiment of the present invention;

[0080] Figure 8 This is a schematic diagram of conformal transformation in an orthogonal plane of a wellbore in an isotropic reservoir, provided by an embodiment of the present invention;

[0081] Figure 9 This is a schematic diagram of the linear distribution model of the damage zone radius along the wellbore provided in an embodiment of the present invention;

[0082] Figure 10 This is a schematic diagram of the parabolic distribution model of the damage zone radius along the wellbore provided in an embodiment of the present invention;

[0083] Figure 11 This is a schematic diagram of the distribution of the radius of the damage zone along the wellbore provided in an embodiment of the present invention;

[0084] Figure 12 This is a schematic diagram of the oscillation decay function model provided in an embodiment of the present invention;

[0085] Figure 13 This is a schematic diagram of a horizontal well provided in an embodiment of the present invention. Detailed Implementation

[0086] The specific embodiments of the present invention will be described in detail below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are for illustration and explanation only and are not intended to limit the scope of the present invention.

[0087] It should be noted that the acquisition, transmission, storage, use, and processing of data in the technical solution of this application all comply with relevant laws and regulations. In the embodiments of this application, certain existing industry solutions such as software, components, and models may be mentioned. These should be considered exemplary, intended only to illustrate the feasibility of implementing the technical solution of this application, and do not imply that the applicant has already used or necessarily used such solutions.

[0088] Example 1

[0089] The skin factor is a dimensionless parameter used to describe changes in flow resistance in the formation surrounding the wellbore due to drilling, completion, and other operations. The skin factor quantifies the degree of damage to the reservoir caused during drilling and completion. A larger positive skin factor indicates more severe reservoir damage and a stronger obstruction to oil and gas flow. By monitoring changes in the skin factor, the effectiveness of reservoir protection measures can be assessed, and drilling and completion plans can be adjusted in a timely manner to reduce reservoir damage.

[0090] Existing technologies calculate the skin coefficient of complex wells based on well production models. These models typically assume homogeneous and isotropic formations with consistent formation conditions around the wellbore. However, complex wells, such as horizontal wells and multi-branched wells, often exhibit heterogeneity, anisotropy, and permeability variations along the wellbore direction, leading to inaccurate skin coefficient calculations. Therefore, this invention provides a method for calculating the total skin coefficient of complex wells, enabling more accurate calculations and providing a scientific basis for rationally formulating reservoir protection measures. Before detailing the implementation process for calculating the total skin coefficient of complex wells provided in this invention, we will first introduce horizontal wells. A horizontal well refers to a section where the wellbore trajectory remains horizontal or nearly horizontal (with an inclination angle typically greater than 85°) within the target formation. A horizontal well typically includes a vertical section (also called a straight section), a build-up section (also called an inclined section), and a horizontal section (also called a horizontal section). Each section of a horizontal well has different functions and characteristics. Specifically, the vertical section extends from the wellhead to the build-up point, with a wellbore trajectory that is basically vertical. The drilling process is similar to that of a vertical well, and it is used to quickly penetrate surface and shallow formations. The build-up section extends from the build-up point to the landing point, with the well inclination angle gradually increasing from vertical to horizontal. Drilling is more difficult and requires the use of directional drilling tools. The horizontal section extends from the landing point to the end of the horizontal well, with the wellbore trajectory remaining horizontal or nearly horizontal. Its extension length can reach hundreds to thousands of meters. The horizontal section is entirely located within the target reservoir, with a large contact area with the reservoir, and is a key part for improving recovery rate.

[0091] Furthermore, taking the calculation of the total skin factor corresponding to a horizontal well as an example, the method for calculating the total skin factor of a complex well provided in this embodiment of the invention will be specifically explained.

[0092] Figure 1This is a flowchart illustrating the method for calculating the total skin factor of complex wells provided in an embodiment of the present invention, as shown below. Figure 1 As shown, the method for calculating the total skin factor of a complex well may include:

[0093] S101. Through coordinate transformation, determine the permeability ratio of any section of the target well in the orthogonal plane of the wellbore in the isotropic coordinate system.

[0094] It should be noted that any section of the target well can be a vertical section, a horizontal section, or an inclined section.

[0095] In some embodiments, determining the permeability ratio of any well section of the target well in the orthogonal plane of the wellbore in an isotropic coordinate system includes:

[0096] Based on any section of the target well in the anisotropic coordinate system oxyz Below: Maximum horizontal permeability parallel to the direction of the fracture Minimum horizontal permeability perpendicular to the crack direction Vertical permeability of formations , well inclination angle and in x - y Horizontal projection of a plane and x Angle between axes Determine the permeability ratio of any section of the target well in the orthogonal plane of the wellbore in an isotropic coordinate system. :

[0097] (1)

[0098] Furthermore, taking the calculation of the permeability of the inclined well section in the orthogonal plane of the wellbore under the isotropic coordinate system as an example, the derivation process of formula (1) will be explained in detail.

[0099] Due to the uneven distribution of geostress, anisotropy is prevalent in oil reservoirs, and the direction of maximum permeability generally coincides with the direction of maximum horizontal principal stress. Assume the thickness of the oil and gas layer is... h In an anisotropic homogeneous oil reservoir, there is a reservoir with a length of... The inclined shaft section has a shaft radius of... , defined as Figure 2 The conventional coordinate system shown oxyz ,in oz Perpendicular to the plane of the strata, x - y The plane is horizontal. Assume the permeability along the three coordinate axes of the coordinate system represents the maximum horizontal permeability parallel to the crack direction. Minimum horizontal permeability perpendicular to the crack direction and vertical permeability of the formation ( > > The well inclination angle is... ,exist x - y The horizontal projection of the well in the plane and x The included angle of the axis, i.e., the azimuth angle, is ,in , .

[0100] In this coordinate system, the three-dimensional steady-state partial differential equation for seepage of a single-phase incompressible liquid in an oil reservoir is:

[0101] (2)

[0102] make Substituting into equation (2), we get:

[0103] (3)

[0104] Equation (3) is expressed as follows: The three-dimensional steady-state seepage partial differential equation in the coordinate system is transformed using the above relationships. oxyz Coordinate system transformation Coordinate system, i.e.:

[0105] (4)

[0106] in, .

[0107] After coordinate transformation, in The permeability tensor in the coordinate system is transformed into:

[0108] (5)

[0109] It can be seen that, after coordinate transformation, the original anisotropic permeability space is converted into an equivalent isotropic permeability space. For example... Figure 3 As shown, in isotropic coordinate space, the new well inclination angle, azimuth angle, well length, well radius, and permeability are respectively expressed as: , , , , The corresponding conversion formula is shown in formula (6).

[0110]

[0111]

[0112]

[0113]

[0114] (6)

[0115] In formula (6), For the anisotropy coefficient of the formation: , For the horizontal permeability of the formation: .

[0116] In isotropic reservoirs, since the isobars around the wellbore always lie in a plane perpendicular to the wellbore, and wellbore damage is directly related to pressure, rotating the coordinate system so that one of the coordinate axes is parallel to the axial direction of the deviated section allows the pressure distribution of the formation around the wellbore to be represented by two quantities in a coordinate plane.

[0117] for Figure 3 In order to make the coordinates in the data... The coordinate axes are parallel to the wellbore direction, first with The axial direction is the axis, and noodle( (Face) Rotate clockwise Angle, converted to Coordinate system, such as Figure 4 As shown.

[0118] The coordinate transformation relationship is as follows:

[0119] ; (7)

[0120] Again The axial direction is the axis, and noodle( (Face) Rotate counterclockwise Angle, converted to Coordinate system, such as Figure 5 As shown.

[0121] The coordinate transformation relationship is as follows:

[0122] ; (8)

[0123] Then ultimately by oxyz coordinate system to The coordinate system transformation relationship is as follows:

[0124] ; (9)

[0125] use Represents the transformed coordinate axes The oil reservoir is located in In the coordinate system, it is isotropic, where The axis is always parallel to the deviated well section under study, and The surface is perpendicular to the wellbore of the inclined section under study, and can be in a certain... The plane represents the distribution of formation pressure field or damage near the deviated well section. Correspondingly... ouvw coordinate system oxyz A coordinate system obtained by rotating a coordinate system. w The axis is always parallel to the deviated well section under study, and UV The plane is perpendicular to the wellbore of the deviated section under study, and the reservoir below it represents an anisotropic reservoir with unconverted permeability. UV The plane can also represent the formation seepage characteristics or wellbore damage distribution near the inclined well section. The transformation relationship between the two coordinate systems and the permeability transformation relationship are shown in equations (10) to (13), respectively.

[0126] ; (10)

[0127] ; (11)

[0128] ;(12)

[0129] ; (13)

[0130] S102. Based on the following parameters corresponding to any well section: wellbore length in an isotropic coordinate system, permeability ratio in the orthogonal plane of the wellbore, distribution of the damage zone radius along the wellbore direction, and the following parameters corresponding to the target well: wellbore radius. The formation permeability before and after damage is used to determine the skin coefficient of the formation near any well section.

[0131] In some embodiments, determining the skin factor of the formation near any well section includes: based on the following parameters corresponding to any well section: wellbore length in an isotropic coordinate system. Permeability ratio in the plane orthogonal 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 of the well sections. :

[0132] (14)

[0133] in, The direction vector corresponding to the direction of the wellbore toe. It refers to any plane orthogonal to the wellbore corresponding to the formation near any well section.

[0134] First, the derivation process of formula (14) is explained in detail based on the distribution characteristics of oil and gas damage zones in the deviated well section of complex well type.

[0135] In anisotropic oil reservoirs ouvw coordinate system UV In the plane, w If is a constant, then the steady-state seepage equation can be expressed as:

[0136] (15)

[0137] The above equation is a common second-order linear elliptic partial differential equation, and the internal boundary conditions of the equation are:

[0138] ;

[0139] (16)

[0140] In the formula, For formation pressure, MPa ; For the bottom hole pressure, MPa ; Let be the wellbore radius. Through equation (18) and boundary condition (19), it can be found that 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. A schematic diagram of the distribution and damage of wellbore isobars in anisotropic reservoirs is shown below. Figure 6 As shown.

[0141] After coordinate transformation, anisotropic reservoirs are converted to For an equivalent isotropic reservoir in the new coordinate system, the transformation relationship between the two coordinate systems in the orthogonal plane of the wellbore is as follows:

[0142] (17)

[0143] In isotropic reservoirs, u'-v' The steady-state seepage equation in the plane becomes:

[0144] (18)

[0145] This equation is the Laplace equation. The corresponding inner boundary conditions are then transformed into:

[0146] (19)

[0147] Equation (18) and boundary condition (19) show that in an equivalent isotropic reservoir, the isobars around the wellbore are a series of confocal concentric ellipses. The inner boundary condition expression after coordinate transformation indicates that the wellbore shape is transformed into the focus at... An ellipse on the axis (as known from equation (15)) The further away from the wellbore, the closer the ratio of the major axis to the minor axis of the elliptical isobars is to 1, and the closer their shape is to a circle. A schematic diagram of the isobar distribution and damage situation within the orthogonal plane of the wellbore is shown below. Figure 7 As shown.

[0148] To solve the Laplace equation for the elliptic inner boundary conditions shown in equations (18) and (19), we introduce conformal transformation and take the transformation function:

[0149] (20)

[0150] In the formula, , .

[0151] Will A plane in a coordinate system Convert to New plane in coordinate system That is, to transform 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:

[0152] ;(twenty one)

[0153] In the formula, It is a hyperbolic cosine function. It is a hyperbolic sine function.

[0154] Based on the transformation relationship of equation (21), Figure 6 The minor and major axes of the corresponding elliptic isobars are as follows:

[0155] , Combined equation (19), the minor axis and major axis of the corresponding elliptical wellbore boundary at the wellbore are respectively:

[0156] ;(twenty two)

[0157] ;(twenty three)

[0158] The average of the major and minor axes of the elliptical isobars is taken as the average radius of the ellipse.

[0159] ;(twenty four)

[0160] Combining (22), (23), and (24), we obtain the average radius of the elliptical wellbore corresponding to the isotropic reservoir as follows:

[0161] (25)

[0162] In an anisotropic coordinate system, to solve for the boundary of an elliptical damage zone, the major axis of the ellipse is defined as the radius of the damage zone. Transforming it to an isotropic coordinate system, we have:

[0163] (26)

[0164] Then corresponding to Figure 8 middle coordinate system for:

[0165] (27)

[0166] Substituting equation (27) into equation (26), we obtain the average radius of the boundary of the corresponding elliptical damage zone in isotropic reservoirs as follows:

[0167] (28)

[0168] Substituting the average wellbore radius equation (25) and the average damage zone radius equation (28) into the expression for the true skin coefficient of the formation around the well proposed by Hawkins:

[0169] (29)

[0170] In the formula, Formation permeability, in units of ; Permeability of the damaged zone, in units of ; The radius of the wellbore is given in units of 1. m ; The radius of the damage zone, in units of m A plane orthogonal to the wellbore is obtained in the near-wellbore formation of the lower inclined section of an isotropic reservoir. The epidermal coefficient of the damaged zone is:

[0171] (30)

[0172] In the above formula, and It can be obtained from equation (2). and Given the well inclination angle and well inclination azimuth of the well section, it can be obtained from equation (15). Indicates the radius of the damage zone along the toe of the wellbore. The distribution of the direction is such that the local skin coefficient (30) of the orthogonal plane of the wellbore is integrated over the well section to obtain the skin coefficient model (14) of the formation near the inclined well section. Similarly, the skin coefficient models of the vertical and horizontal well sections in special cases can be obtained by the above method.

[0173] The embodiments of this invention utilize coordinate transformation and conformal transformation methods to derive the corresponding local skin coefficients of each well segment in the wellbore trajectory of complex well types. This can more accurately describe the damage evolution characteristics during the well construction process of complex well types, providing theoretical support for the scientific formulation of reservoir protection strategies.

[0174] Then, respectively, the first part of formula (14) The following parameters are involved in the well section: wellbore length in an isotropic coordinate system. Distribution of damage zone radius along the wellbore direction The process of determining [the value] will be explained in detail.

[0175] For wellbore length The wellbore length corresponding to any well section in the isotropic coordinate system is determined as follows:

[0176] Based on any section of the target well in the anisotropic coordinate system oxyz The following parameters are included: maximum horizontal permeability parallel to the fracture direction. Minimum horizontal permeability perpendicular to the crack direction Vertical permeability of formations Determine the first parameter Second parameter and the third parameter :

[0177] According to the first parameter Second parameter Third parameter and any well section in an anisotropic coordinate system oxyz The following parameters are listed: length , well inclination angle And in x - y Horizontal projection of a plane and x Angle between axes Determine the wellbore length in an isotropic coordinate system. :

[0178] .

[0179] The distribution of the damage zone radius along the wellbore direction The distribution of the damage zone radius along the wellbore direction for any section of the target well. It is determined based on the oscillation decay function model or empirical formula model.

[0180] First, the distribution law of the damage zone radius along the wellbore direction is explained in detail. During drilling operations, the contact time between the well toe and the drilling fluid is shorter, resulting in the smallest damage zone radius and the smallest local skin coefficient at that point. In special cases, the minimum damage zone radius is equal to the wellbore radius. Conversely, the root end has the longest contact time with the drilling fluid, resulting in the most severe damage and the largest damage zone radius and the largest local skin coefficient. The horizontal well skin coefficient model established by Frick TP and Economides MJ, along with scholars such as Zhang Zhenhua and Liu Xiaoxu, treats the distribution of the damage zone radius along the wellbore direction in isotropic space as a linear distribution and equates the elliptical frustum-shaped damage zone to a frustum-shaped damage zone, such as... Figure 9 As shown.

[0181] When deriving the productivity of anisotropic horizontal wells considering reservoir damage, Sun Enhui treated the distribution of the damage zone radius along the wellbore direction in the equivalent isotropic space as parabolic, such as... Figure 10 As shown.

[0182] Furthermore, reservoir properties, drilling and completion fluid properties, and construction parameters all affect the value of the damaged zone radius. In reality, the distribution of the damaged zone radius along the wellbore direction is uneven, such as... Figure 11 As shown, this value is also difficult to obtain directly and generally needs to be obtained through indoor experiments.

[0183] Furthermore, the oscillation decay function model provided in this embodiment of the invention will be specifically explained. In isotropic space, even without the influence of formation anisotropy, considering the influence of multiple factors such as drilling and completion fluid properties and construction parameters, the shape of oil and gas reservoir damage actually exhibits a non-uniform decreasing distribution from the wellbore root to the wellbore toe. Here, it is assumed that the radius of the damage zone extends along the wellbore toe. The direction is distributed in the form of an oscillating decay function, such as... Figure 12 As shown.

[0184] Furthermore, the oscillation decay function model includes:

[0185] (31)

[0186] in, Indicates the first The radius of the damage zone corresponding to the section of the wellbore extends along the toe of the wellbore. Distribution of directions; The direction vector corresponding to the direction of the wellbore toe; Indicates the first The radius of the maximum damage zone corresponding to the wellbore section. Indicates the first The minimum damage zone radius corresponding to the wellbore of the section.

[0187] It should be noted that, , They are respectively Figure 7 The maximum and minimum damage zone radii of the wellbore in the corresponding equivalent isotropic reservoir can be determined using the maximum invasion depth model of drilling fluid and completion fluid.

[0188] In some embodiments, the maximum penetration depth model for drilling fluid and completion fluid is as follows:

[0189] (32)

[0190] In formula (32), For maximum penetration depth, For drilling fluid soaking time Internal pressure difference Under its influence, through 45.8 cm 2 Filtration loss due to filtration area cm 3 ; This is the difference between the drilling fluid column pressure and the formation pore pressure. MPa ; represents porosity; K represents reservoir permeability.

[0191] The oscillation decay function model provided in this embodiment of the invention assumes that the radius of the damage zone is distributed along the wellbore direction. In addition to considering the influence of drilling fluid soaking time on formation damage, it also considers the possible influence of drilling and completion fluid performance, construction parameters, etc. on the distribution of the damage zone. It optimizes the linear model and the parabolic distribution model, making it more in line with the actual situation.

[0192] Next, the empirical formula model provided in the embodiments of the present invention will be specifically described. The formula corresponding to the empirical formula model is as follows:

[0193] (33)

[0194] in, Indicates the depth of invasion (i.e., the radius of the damage zone); Represents the radius of the wellbore; , 30 respectively min Static and dynamic filtration loss; , , These are the time for the drilling fluid to soak the target formation and the time for the drilling fluid to circulate through the target formation, respectively. , , These represent 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 outer mud cake, respectively. The diameter of the rock core; Residual oil saturation; This represents the residual saturation of the rock pores after the filtrate has penetrated. The saturation degree of clay after it absorbs water and expands, occupying the original pore volume; Indicates the drilling fluid soaking time; The average mechanical drilling speed, This indicates the drilling fluid soaking time. The corresponding position at that time Indicates porosity.

[0195] The empirical formula model provided in this embodiment of the invention can simulate the radius of the damage zone near each point in the wellbore.

[0196] S103. Determine the additional pressure drop corresponding to any well section based on the skin coefficient of the formation near any well section and the pre-damage permeability of the formation corresponding to the target well.

[0197] In some embodiments, reservoir damage can cause an additional pressure drop in the reservoir surrounding the wellbore. This additional pressure drop is determined in an isotropic coordinate system as follows: :

[0198] Based on the skin coefficient of the formation near any of the well sections ,flow Fluid viscosity Volume index The formation permeability before the damage and the thickness of oil and gas reservoirs Determine the additional pressure drop :

[0199] (34)

[0200] For the skin coefficient of the formation near any well section in formula (34) The value can be determined according to formula (14). .

[0201] For the formation permeability before damage in formula (34) The formation permeability before the damage It is determined in the following manner:

[0202] According to the target well's... The following parameters correspond to the well section: oil and gas reservoir permeability Oil and gas layer thickness and pressure difference Determine the reduced permeability of the formation before damage. :

[0203] (35)

[0204] in, The total number of well sections of the target well.

[0205] Specifically, the derivation process of (35) will be explained in detail.

[0206] First, considering that the flow pattern in different well sections is planar radial flow, Darcy's law is applied to calculate the single-phase fluid production in steady-state radial flow. That is, formula (36):

[0207] (36)

[0208] In formula (36), Fluid output (flow rate), usually expressed in cubic meters per day; K Reservoir permeability; Δ represents the effective reservoir thickness, expressed in meters (m), indicating the thickness of the reservoir where fluids can flow. P For production pressure differential; μ For fluid viscosity; Reservoir radius, in meters (m), represents the boundary radius of the well-controlled area; Where is the radius of the wellbore.

[0209] Assume the pressures at different locations from the point where the complex well enters the oil and gas formation to the well toe are P1, P2, P3, ..., P... i ... P n The permeability of the oil and gas reservoirs in different well sections are K1, K2, K3, ..., K. i ... K n The total production of the well Equal to the production of each well section sum:

[0210] (37)

[0211] In formula (37), The pressure difference in the i-th segment of the complex well is expressed in MPa. Indicates the first The thickness of the well section; Indicates the first The permeability of the oil and gas reservoir in the well section; μ For fluid viscosity; Where is the reservoir radius; Where is the wellbore radius. This represents the total number of well sections.

[0212] Simplifying formula (37) yields formula (35).

[0213] In some embodiments, based on the target well's first The following parameters correspond to the well section: oil and gas reservoir permeability Oil and gas layer thickness Pressure difference and additional pressure drop Determine the reduced permeability of the damaged formation. :

[0214] (38)

[0215] in, The total number of well sections of the target well.

[0216] S104. Based on the following parameters corresponding to any well section: oil and gas reservoir permeability, oil and gas reservoir 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 coefficient of the target well.

[0217] In some embodiments, determining the total skin factor of the target well includes: based on the following parameters corresponding to any well section: oil and gas reservoir permeability. Oil and gas layer thickness Pressure difference The additional pressure drop and the distribution of the radius of the damage zone 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. :

[0218] (39)

[0219] in, The total number of well sections of the target well.

[0220] It should be noted that, for formula (39), the average damage zone radius of the entire well can be calculated by summing the damage zone radii of each well section and dividing by the total wellbore length. Conversion:

[0221] (40)

[0222] Combining equations (29), (35), (38), and (40), the total skin coefficient of a complex well type with different wellbore trajectories in an anisotropic reservoir can be obtained. That is, formula (39).

[0223] This invention also provides a method for calculating the pseudo-skin factor (one of the skin factors), and for calculating the productivity of complex wells using the pseudo-skin factor. The method.

[0224] First, for the deviated section in a complex well configuration, the deviation generates a pseudo-skin coefficient. Damage to the oil and gas reservoir resulted in a true skin coefficient. Then, considering the damage to the oil and gas reservoir, the productivity equation for the deviated well section under the condition of infinitely large steady-state seepage in a single-phase plate-shaped reservoir is:

[0225] (41)

[0226] in, Reservoir permeability; Δ is the effective thickness of the reservoir. P For production pressure differential; μ For fluid viscosity; Indicates the oil volume coefficient; The reservoir radius is expressed in meters (m), representing the boundary radius of the well-controlled area. Where: wellbore radius; true skin coefficient The pseudo-epidermal coefficient can be determined by formula (39). It was determined in the following way:

[0227] First, based on any section of the target well in the anisotropic coordinate system... oxyz The following parameters are included: maximum horizontal permeability parallel to the fracture direction. Minimum horizontal permeability perpendicular to the crack direction Vertical permeability of formations Determine the first parameter Second parameter and the third parameter :

[0228]

[0229] Then, based on the first parameter Second parameter Third parameter , well inclination angle , wellbore radius Wellbore length And in x - y Horizontal projection of a plane and x Angle between axes Determine the pseudo-skin coefficient of well inclination in highly deviated wells in anisotropic reservoirs. :

[0230] (42)

[0232] In some embodiments, utilizing Figure 13 The method for calculating the total skin factor of complex wells provided in this embodiment of the invention, as shown in the horizontal well illustration, is explained in detail below. Figure 13 As shown, the well sections within the oil and gas reservoir include vertical, inclined, and horizontal sections, all of which have been opened. The wellbore radius is... r w =0.2m, oil and gas layer thickness h =50m, oil and gas layer formation permeability K=1000mD, average formation permeability of the damaged zone is 500mD, oil and gas layer porosity is 20%, formation anisotropy coefficient =3, crude oil viscosity =30 mPa•s, crude oil volume coefficient B o =1.058, formation pressure 13.5MPa, bottom hole flowing pressure 10MPa. According to the experimental test, the drilling fluid filtration loss was 15ml within 30min under 3.5MPa.

[0233] It should be noted that, Figure 13 The horizontal well section shown is in an anisotropic coordinate system oxyz Maximum horizontal permeability parallel to the direction of the fracture Minimum horizontal permeability perpendicular to the crack direction Same, that is = .

[0234] First, according to formula (6), the lengths of the wellbore corresponding to each well section included in the horizontal well are converted into the lengths of the wellbore in the isotropic coordinate system, which are 20.80m, 23.81m, and 219.15m respectively.

[0235] Then, according to formula (13), the permeability ratio of each section of the horizontal well in the orthogonal plane of the wellbore in the isotropic coordinate system is obtained. They are respectively: .

[0236] Substituting the relevant parameters into formula (32), the maximum penetration depth of the drilling fluid in the near-wellbore zone is obtained as follows: r dmax =0.52m.

[0237] According to the oscillation decay function model (31), the damage zone range of each section of the horizontal well is 6.73m. 2 7.72m 2 65.06m 2 .

[0238] Therefore, according to formula (40), the average equivalent damage zone radius of the entire well section corresponding to this horizontal well is 0.30m.

[0239] According to formula (35), the formation permeability before damage corresponding to the target well is 236.25 mD;

[0240] 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.

[0241] According to formula (38), the calculated permeability of the formation after damage to the target well is 17.60 mD;

[0242] Finally, by substituting the above parameters into formula (39), the total skin coefficient corresponding to the horizontal well can be obtained as 14.37.

[0243] This invention provides an apparatus for calculating the total skin factor of a complex well, comprising: a memory configured to store instructions; and a processor configured to retrieve the instructions from the memory and, when executing the instructions, to implement the method for calculating the total skin factor of the complex well.

[0244] This invention provides a processor for running a program, which, when run, performs the method for calculating the total skin coefficient of a complex well.

[0245] This invention provides a computer program product, including a computer program that, when executed by a processor, implements the method for calculating the total skin coefficient of a complex well.

[0246] The method for calculating the total skin coefficient of complex wells provided in this invention is based on permeability variation and the distribution of damaged zone radius to determine the total skin coefficient corresponding to the complex well. This method can more accurately calculate the skin coefficient of complex well types and provide a scientific basis for rationally formulating reservoir protection measures.

[0247] Example 2

[0248] As oil and gas exploration and development gradually advances into deeper, ultra-deep, and low-permeability reservoirs, horizontal well technology has become an important means to improve oil and gas recovery and optimize reservoir development. Compared to vertical or directional wells, horizontal wells can 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 insufficient 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 affecting the safety of drilling operations and the efficiency of oil and gas field development.

[0249] In existing technologies, drilling and completion fluid design primarily relies on engineers' experience and experimental data. Based on formation characteristics, wellbore mechanical analysis, and rheological requirements, parameters such as density, viscosity, and fluid loss of the drilling and completion fluid are adjusted. However, this experience-based design method has the following limitations: strong reliance on experience, making it difficult to adapt to varying well conditions—due to the complex and variable formation characteristics, a single experience-based method cannot provide the optimal drilling and completion fluid formulation, especially in special well conditions such as ultra-deep wells, high-temperature and high-pressure (HPHT) wells, and extended reach wells. Experience-based adjustments can easily lead to parameter mismatches, affecting drilling safety. Furthermore, traditional drilling and completion fluid optimization methods are usually based on static data calculations, making real-time optimization difficult and unable to dynamically adjust according to changes in the downhole environment, thereby increasing well control risks and reservoir damage risks. Based on this, Embodiment Two of the present invention, based on Embodiment One, provides a knowledge- and data-coupled driven expert method for drilling and completion fluid design, the method comprising:

[0250] S201. Determine the total skin coefficient of the target well according to the method for calculating the total skin coefficient of a complex well as described in Example 1.

[0251] 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.

[0252] S203. When the total skin coefficient of the target well is greater than 0, optimize the drilling fluid design corresponding to the target well according to S301, and optimize the completion fluid design corresponding to the target well according to S302:

[0253] S301. Determine the target drilling fluid formula corresponding to the target well based on the permeability and / or structural characteristics of the reservoir corresponding to the target well, and the pre-set drilling fluid formulas corresponding to different permeability and / or structural characteristics.

[0254] It should be noted that the structural characteristics of the reservoir include: non-fractured reservoirs and fractured reservoirs.

[0255] First, reservoirs are classified into three categories based on their permeability: low-permeability reservoirs, medium-permeability reservoirs, and high-permeability reservoirs. The classification criteria are as follows: High-permeability reservoirs: greater than 500 × 10⁻⁶-3 μm 2 Medium-permeability reservoirs: 50~500×10 -3 μm 2 Low-permeability and ultra-low-permeability reservoirs: less than 5.0 × 10⁻⁶ -3 μm 2 .

[0256] Then, the permeability of the reservoir corresponding to the target well is greater than 500 × 10⁻⁶. -3 μm 2 When the reservoir is a high-permeability reservoir and is not a 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;

[0257] The permeability of the reservoir corresponding to the target well is greater than 500 × 10⁻⁶. -3 μm 2 When the reservoir is a high-permeability reservoir and is a fractured reservoir, the target drilling fluid formula is: Formula 2: Upper drilling fluid + 0.6% XG xanthan gum;

[0258] The permeability of the reservoir corresponding to the target well is between 50 and 500 × 10⁻⁶. -3 μm 2 When the reservoir is between medium-permeability reservoirs and is a 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;

[0259] The permeability of the reservoir corresponding to the target well is between 50 and 500 × 10⁻⁶. -3 μm 2 When the reservoir is between medium permeability and fractured, the target drilling fluid formulation is: Formulation 4: Upper drilling fluid + 0.6% xanthan gum XG; and

[0260] The permeability of the reservoir corresponding to the target well is less than 5.0 × 10⁻⁶. -3 μm 2 When the target drilling fluid formula is for (low-permeability and ultra-low-permeability reservoirs), the 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.

[0261] S302. Determine the target completion fluid formula corresponding to the target well based on the type of completion fluid corresponding to the target well and the preset completion fluid formulas corresponding to different completion fluid types;

[0262] Specifically, the types of completion fluids include: solids-free completion fluids and low-damage surfactant completion fluids.

[0263] In some embodiments, when the completion fluid corresponding to the target well is a solids-free completion fluid, the target completion fluid formulation is: Formulation Six: clean water + 76% anti-collapse plugging agent KR + 3% filtration loss reducer ZT-2 + X% limestone powder; and

[0264] 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 enhancer and filtration reducer + 0.3% zwitterionic polymer FA367 + 3% cationic polymer clay stabilizer YNJ + 3% fine CaCO3 + 0.2% inhibitor SK-2 + 1% water-locking agent JSS + 1% corrosion inhibitor ZH-III + Y% weighting agent;

[0265] The formulas for calculating X and Y in Formulas 6 and 7 are as follows:

[0266]

[0267]

[0268] This indicates the preset completion fluid density value.

[0269] This invention also provides a knowledge- and data-coupled drilling and completion fluid design expert system, the system comprising:

[0270] Total skin coefficient calculation module: used to calculate the total skin coefficient of the target well;

[0271] Optimization module: used to determine 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;

[0272] 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:

[0273] Based on the permeability and / or structural characteristics of the reservoir corresponding to the target well, and pre-set drilling fluid formulations corresponding to different permeability and / or structural characteristics, the target drilling fluid formulation for the target well is determined; and

[0274] The target completion fluid formula for the target well is determined based on the type of completion fluid corresponding to the target well and the preset completion fluid formulas corresponding to different completion fluid types.

[0275] The structural characteristics of the reservoir include: non-fractured reservoirs and fractured reservoirs; the types of completion fluids include: solids-free completion fluids and low-damage surfactant completion fluids; the total skin factor of the target well is determined by the method for calculating the total skin factor of complex wells described in Example 1.

[0276] The knowledge- and data-driven drilling and completion fluid design expert method provided in this invention calculates the total skin factor of the target well and provides corresponding optimization decisions for the drilling and completion fluids based on the total skin factor. On the one hand, it can solve the problems of difficult, poor adaptability, and reliance on experience in optimizing the design of drilling and completion fluids under complex formation conditions. On the other hand, by using the total skin factor of the target well, it can 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.

[0277] Those skilled in the art will understand that embodiments of this application can be provided as methods, systems, or computer program products. Therefore, this application can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, this application can take the form of a computer program product embodied on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0278] This application is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of this application. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations 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, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart... Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0279] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0280] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1The steps of the function specified in one or more boxes.

[0281] In a typical configuration, a computing device includes one or more processors (CPU), input / output interfaces, network interfaces, and memory.

[0282] Memory may include non-persistent memory in computer-readable media, such as random access memory (RAM) and / or non-volatile memory, such as read-only memory (ROM) or flash RAM. Memory is an example of computer-readable media.

[0283] Computer-readable media includes both permanent and non-permanent, removable and non-removable media that can store information using any method or technology. Information can be computer-readable instructions, data structures, modules of programs, 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 technologies, CD-ROM, digital versatile optical disc (DVD) or other optical storage, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other non-transferable medium that can be used to store information accessible by a computing device. As defined herein, computer-readable media does not include transient computer-readable media, such as modulated data signals and carrier waves.

[0284] It should also be noted that the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such process, method, article, or apparatus. Unless otherwise specified, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes that element.

[0285] The above are merely embodiments of this application and are not intended to limit the scope of this application. Various modifications and variations can be made to this application by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of this application should be included within the scope of the claims of this application.

Claims

1. A method for calculating the total skin factor of a complex well, characterized in that, The method includes: By transforming coordinates, the permeability ratio of any section of the target well in the orthogonal plane of the wellbore in an isotropic coordinate system is determined. Based on the following parameters corresponding to any well section: well length in an isotropic coordinate system and permeability ratio in the orthogonal plane of the well, distribution of the radius of the damaged zone along the well direction, and the following parameters corresponding to the target well: well radius, formation permeability before damage and formation permeability after damage, the skin coefficient of the formation near any well section is determined. Based on the skin factor of the formation near any well section and the pre-damage formation permeability of the target well, determine the additional pressure drop corresponding to any well section; and Based on the following parameters corresponding to any well section: oil and gas reservoir permeability, oil and gas reservoir 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 coefficient of the target well; Wherein, any section of the target well is a vertical section, a horizontal section, or an inclined section; The formation permeability before damage corresponding to the target well It was determined in the following manner: According to the target well's... The following parameters correspond to the well section: oil and gas reservoir permeability Oil and gas layer thickness and pressure difference Determine the formation permeability before damage corresponding to the target well. : ； in, The total number of well sections of the target well.

2. The method according to claim 1, characterized in that, The permeability ratio of any section of the target well in the orthogonal plane of the wellbore in an isotropic coordinate system includes: Based on any section of the target well in the anisotropic coordinate system oxyz Below: Maximum horizontal permeability parallel to the direction of the fracture Minimum horizontal permeability perpendicular to the crack direction Vertical permeability of formations , well inclination angle and in x - y Horizontal projection of a plane and x Angle between axes Determine the permeability ratio of any section of the target well in the orthogonal plane of the wellbore in an 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 as follows: Based on any section of the target well in the anisotropic coordinate system oxyz The following parameters are included: maximum horizontal permeability parallel to the fracture direction. Minimum horizontal permeability perpendicular to the crack direction Vertical permeability of formations Determine the first parameter Second parameter and the third parameter : According to the first parameter The second parameter The third parameter and any section of the target well in the anisotropic coordinate system oxyz The following parameters are listed: length , well inclination angle And in x - y Horizontal projection of a plane and x Angle between axes Determine the wellbore length in an isotropic coordinate system. : 。 4. The method according to claim 1, characterized in that, Determining the skin factor of the formation near any of the well sections includes: Based on the following parameters corresponding to any well section: wellbore length in an isotropic coordinate system. Permeability ratio in the plane orthogonal 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 of the well sections. : ； in, The direction vector corresponding to the direction of the wellbore toe. It refers to any plane orthogonal to the wellbore corresponding to the formation near any well section.

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

6. The method according to claim 1, characterized in that, Determining the additional pressure drop corresponding to any well section includes: based on the skin coefficient of the formation near any well section. ,flow Fluid viscosity Volume index The formation permeability before the damage and the thickness of oil and gas reservoirs Determine the additional pressure drop : 。 7. The method according to claim 1, characterized in that, The total skin factor for determining the target well includes: Based on the following parameters corresponding to any of the well sections: oil and gas reservoir permeability Oil and gas layer thickness Pressure difference The additional pressure drop and the distribution of the radius of the damage zone 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, The total number of well sections of the target well.

8. The method according to claim 1, characterized in that, The distribution of the damage zone radius along the wellbore direction for any segment of the target well is determined based on an oscillation decay function model or an empirical formula model.

9. The method according to claim 8, characterized in that, The oscillation decay function model includes: ； in, Indicates the first The radius of the damage zone corresponding to the section of the wellbore extends along the toe of the wellbore. Distribution of directions; The direction vector corresponding to the direction of the wellbore toe; Indicates the first The radius of the maximum damage zone corresponding to the wellbore section. Indicates the first The minimum damage zone radius corresponding to the wellbore of the section.

10. The method according to claim 8, characterized in that, The empirical formula model includes: in; Indicates the radius of the damage zone; Represents the radius of the wellbore; Indicates porosity; , 30 respectively min Static and dynamic filtration loss; , , These are the time for the drilling fluid to soak the target formation and the time for the drilling fluid to circulate through the target formation, respectively. , , These represent 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 outer mud cake, respectively. The diameter of the rock core; Residual oil saturation; This represents the residual saturation of the rock pores after the filtrate has penetrated. The saturation degree of clay after it absorbs water and expands, occupying the original pore volume; Indicates the drilling fluid soaking time; This represents the average mechanical drilling speed; This refers to the drilling fluid soaking time. The corresponding position at that time.

11. An apparatus for calculating the total skin factor of a complex well, characterized in that, include: The memory is configured to store instructions; The processor is configured to retrieve the instructions from the memory and, when executing the instructions, to implement the method for calculating the total skin coefficient of a complex well according to any one of claims 1 to 10.

12. A computer program product, characterized in that, Includes a computer program that, when executed by a processor, implements the method for calculating the total skin factor of a complex well as described in any one of claims 1 to 10.

13. A knowledge- and data-coupled expert method for drilling and completion fluid design, characterized in that, The method includes: When the total skin coefficient of the target well is less than or equal to 0, the drilling fluid and completion fluid corresponding to the target well are deemed to 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: Based on the permeability and / or structural characteristics of the reservoir corresponding to the target well, and pre-set drilling fluid formulations corresponding to different permeability and / or structural characteristics, the target drilling fluid formulation for the target well is determined; and The target completion fluid formula for the target well is determined based on the type of completion fluid corresponding to the target well and the preset completion fluid formulas corresponding to different completion fluid types. The structural characteristics of the reservoir include: non-fractured reservoirs and fractured reservoirs; the types of completion fluids include: solid-free completion fluids and low-damage surfactant completion fluids; the total skin factor of the target well is determined by the method for calculating the total skin factor of complex wells as described in any one of claims 1 to 10.

14. The method according to claim 13, characterized in that, Determining the target drilling fluid formulation corresponding to the target well includes: The permeability of the reservoir corresponding to the target well is greater than 500 × 10⁻⁶. -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 × 10⁻⁶. -3 μm 2 When the reservoir is fractured, the target drilling fluid formulation is: Formulation 2: Upper drilling fluid + 0.6% xanthan gum XG; The permeability of the reservoir corresponding to the target well is between 50 and 500 × 10⁻⁶. -3 μm 2 When the reservoir is between and is not 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 × 10⁻⁶. -3 μm 2 When the reservoir is fractured, the target drilling fluid formulation is: Formulation 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 × 10⁻⁶. -3 μm 2 At that time, the target drilling fluid formulation is: Formulation 5: Upper drilling fluid + (2~3)% oil film type reservoir protection new material LCM-8 + (0.2~0.4)% surfactant FCS-08.

15. The method according to claim 13, characterized in that, The target completion fluid formulation corresponding to the target well includes: When the completion fluid corresponding to the target well is a solids-free completion fluid, the target completion fluid formula is: Formula Six: clean water + 76% anti-collapse plugging agent KR + 3% filtration 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 enhancer and filtration reducer + 0.3% zwitterionic polymer FA367 + 3% cationic polymer clay stabilizer YNJ + 3% fine CaCO3 + 0.2% inhibitor SK-2 + 1% water-locking agent JSS + 1% corrosion inhibitor ZH-III + Y% weighting agent; The formulas for calculating X and Y in Formulas 6 and 7 are as follows: This indicates the preset completion fluid density value.

16. A knowledge- and data-coupled driven expert system for drilling and completion fluid design, characterized in that, The system includes: Total skin coefficient calculation module: used to calculate the total skin coefficient of the target well; Optimization module: used to determine 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: Based on the permeability and / or structural characteristics of the reservoir corresponding to the target well, and pre-set drilling fluid formulations corresponding to different permeability and / or structural characteristics, the target drilling fluid formulation for the target well is determined; and The target completion fluid formula for the target well is determined based on the type of completion fluid corresponding to the target well and the preset completion fluid formulas corresponding to different completion fluid types. The structural characteristics of the reservoir include: non-fractured reservoirs and fractured reservoirs; the types of completion fluids include: solid-free completion fluids and low-damage surfactant completion fluids; the total skin factor of the target well is determined by the method for calculating the total skin factor of complex wells as described in any one of claims 1 to 10.

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