Selection method for drilling fluid system, control device and storage medium

Abstract

The embodiment of the invention provides a selection method for a drilling fluid system, a control device and a storage medium, and belongs to the technical field of oil and gas field drilling development. The method comprises the following steps: testing the permeability of a rock matrix, the pore throat diameter of the rock matrix and the crack widths of different cracks through obtained rock cores and rock debris with the same lithology as a target fractured stratum; determining development characteristics of natural fractures of rock around a well and well drilling induced fractures through a preset method; a 3D printing technology is utilized to print a sand disc with the same pore throat diameter and permeability as those of a rock matrix of the target fractured stratum, and cracks with different crack widths and development characteristics are printed on the sand disc to form a crack pore sand disc; and selecting the drilling fluid system with the optimal plugging performance from different drilling fluid systems by taking a crack pore molding sand disc as a medium. According to the embodiment of the invention, the plugging effects of drilling fluids of different systems on the crack-pore type stratum can be accurately determined, the optimal drilling fluid system is selected, and the well wall stability of the fractured stratum is improved.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field drilling and development technology, and specifically to a method for selecting drilling fluid systems, a control device, and a storage medium. Background Technology

[0002] Deep oil and gas reservoirs have unique geological conditions and complex geostress conditions. Under prolonged, multi-stage, and intense tectonic movements and high geostress, deep strata typically develop damage zones of varying degrees, i.e., fracture zones. Under the influence of high temperature, high pressure, high geostress, and high disturbance stress during drilling, wellbore instability in deep formation fracture zones becomes a prominent problem, hindering efficient well construction in deep oil and gas reservoirs.

[0003] Currently, increasing drilling fluid density, strengthening plugging, and appropriate inhibition are insufficient to effectively solve the complex problems of drilling in fractured formations. Further in-depth research should be conducted on fractured formation plugging, optimal formulation of high-efficiency plugging materials, and the plugging mechanism of fractured formations. Various methods for determining wellbore stability have been developed, including scanning electron microscopy, wettability testing, linear expansion testing, triaxial compression testing, CT scanning, mineral composition analysis, and medium-pressure & HPHT filtration loss testing. These methods can determine the inhibition and plugging properties of drilling fluids, the microstructure of rocks, mineral composition, clay content, and mechanical strength. However, most existing experiments use rock samples, and filtration loss tests use filter paper, sand discs, and sand beds that cannot reflect the characteristics of fractured formations. Summary of the Invention

[0004] The purpose of this invention is to provide a method for selecting drilling fluid systems, which can accurately determine the sealing effect of different drilling fluid systems on fracture-pore formations.

[0005] To achieve the above objectives, embodiments of the present invention provide a method for selecting a drilling fluid system used for plugging fractured formations. The method includes: obtaining a core sample of the target fractured formation by coring cuttings returned from a fractured formation section or by core sampling of a target fractured formation section; testing the permeability, pore throat diameter, and fracture width of different fractures in the target fractured formation's rock matrix using the obtained core sample and cuttings; determining the development characteristics of natural fractures and drilling-induced fractures around the well using a preset method; printing a sand disc with the same pore throat diameter and permeability as the target fractured formation's rock matrix using 3D printing technology, and printing the determined fracture widths and development characteristics onto the sand disc to form a fracture-pore-type sand disc; and selecting the drilling fluid system with optimal plugging performance from different drilling fluid systems using the fracture-pore-type sand disc as a medium for plugging the target fractured formation.

[0006] Optionally, the step of testing the permeability, pore throat diameter, and microfracture width of the target fractured stratum using the obtained core and rock fragments includes: testing the permeability of the target fractured stratum's rock matrix using the obtained core; and using a scanning electron microscope to observe the core or rock fragments to test the pore throat diameter and the width of different fractures in the target fractured stratum's rock matrix.

[0007] Optionally, determining the development characteristics of natural fractures and drilling-induced fractures in the surrounding rocks through a preset method includes: analyzing and determining the development characteristics of natural fractures and drilling-induced fractures in the surrounding rocks based on imaging logging data.

[0008] Optionally, determining the development characteristics of natural fractures and drilling-induced fractures in the surrounding rocks using a preset method includes: constructing a drilling-induced fracture prediction model for the surrounding rocks; and determining the development characteristics of natural fractures and drilling-induced fractures in the surrounding rocks based on the drilling-induced fracture prediction model for the surrounding rocks.

[0009] Optionally, the method for constructing a drilling-induced fracture prediction model for the rock surrounding the well includes: transforming the geostress coordinates to a geodetic coordinate system, then to a wellbore coordinate system, and transforming the stress tensor of the geostress in the wellbore coordinate system to a polar coordinate system; obtaining the wellbore stress distribution law based on the principle of linear superposition and Biot's effective stress theory in the polar coordinate system; converting the wellbore stress into principal stresses; and determining the tensile failure type through the principal stresses and calculating the angle between each point around the well and the wellbore axis to construct the drilling-induced fracture prediction model for the rock surrounding the well.

[0010] Optionally, the drilling induced fracture prediction model based on the surrounding rock of the well determines the development characteristics of natural fractures and drilling induced fractures in the surrounding rock, including: determining the development characteristics of drilling induced fractures under different wellbore trajectories based on the drilling induced fracture prediction model based on the surrounding rock of the well; and determining the development characteristics of drilling induced fractures under different in-well fluid column pressures based on the drilling induced fracture prediction model based on the surrounding rock of the well.

[0011] Optionally, the drilling induced fracture prediction model based on the surrounding rock of the well determines the development characteristics of drilling induced fractures under different wellbore trajectories, including: when the wellbore axis is parallel to any principal stress, the angle between the induced fracture and the wellbore axis is 0°, resulting in two symmetrically distributed fractures parallel to the wellbore axis; when the change in the angle between the induced fracture and the wellbore axis remains within a first preset angle, feather-shaped fractures are generated; when the change in the angle between the induced fracture and the wellbore axis is greater than the first preset angle, J-shaped fractures are generated; and when the angle between the induced fracture and the wellbore axis is close to 0° at the minimum principal stress around the well, and then the change increases or decreases, a sinusoidal fracture is generated.

[0012] Optionally, the drilling induced fracture prediction model based on the surrounding rock of the well determines the development characteristics of drilling induced fractures under different in-well fluid column pressures, including: the generation of feather-shaped fractures under different bottom hole pressures; and the gradual decrease in the angle between the drilling induced fracture and the wellbore axis as the in-well fluid column pressure increases, while the length of the induced fracture gradually increases.

[0013] Optionally, after forming the fractured pore type sand disc, the method for selecting the drilling fluid system further includes: preparing bentonite slurry of a preset concentration as a base slurry; and adding different types and concentrations of compounded plugging materials to the base slurry and stirring at a preset stirring speed to form the different drilling fluid systems.

[0014] Optionally, the step of selecting the optimal drilling fluid system from different drilling fluid systems using the fractured porous sand disc as a medium includes: using the fractured porous sand disc as a medium, and employing a high-temperature and high-pressure micro-fracture plugging evaluation instrument to select the optimal drilling fluid system from different drilling fluid systems by measuring the filtration loss.

[0015] This invention also provides a control device for selecting drilling fluid systems. The control device includes a memory, a processor, and a computer program stored in the memory and executable on the processor. The processor executes the computer program to implement the above-described method for selecting drilling fluid systems.

[0016] This invention also provides a machine-readable storage medium storing instructions that cause a machine to perform the above-described method for selecting a drilling fluid system.

[0017] Through the above technical solution, the drilling fluid system selection method provided in this embodiment of the invention uses core samples and cuttings of the same lithology as the target fractured formation to test the permeability, pore throat diameter, and fractures of different widths of the target fractured formation's rock matrix. Using a preset method, the development characteristics of natural fractures and drilling-induced fractures in the surrounding rocks are determined. A sand disc with the same pore throat diameter and permeability as the target fractured formation's rock matrix is ​​printed using 3D printing technology, and the determined fractures of different widths and the aforementioned development characteristics are printed on the sand disc to form a fracture-pore type sand disc. Using the fracture-pore type sand disc as a medium, the drilling fluid system with the optimal sealing performance is selected from different drilling fluid systems for sealing the target fractured formation. The development characteristics of natural fractures and drilling-induced fractures in the surrounding rocks can be determined based on imaging logging data analysis or a drilling-induced fracture prediction model of the surrounding rocks. The embodiments of the present invention can conveniently and quickly determine the sealing effect of different drilling fluid systems on fracture-pore formations on a PPA device, so as to select the drilling fluid system with the best sealing performance and improve the wellbore stability of the target fractured formation.

[0018] 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

[0019] 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:

[0020] Figure 1 This is a flowchart illustrating the selection method for drilling fluid systems;

[0021] Figure 2 This is a schematic diagram of a scanning electron microscope image of a fractured stratum rock.

[0022] Figure 3 This is a schematic diagram illustrating the development characteristics of natural cracks and the width of microcracks;

[0023] Figure 4 This is a schematic diagram of an example of vertical drilling induced fracture imaging logging;

[0024] Figure 5 This is a schematic diagram of an example of a goose-shaped drilling induced fracture imaging logging.

[0025] Figure 6 This is a schematic diagram of an example of a fishhook-shaped or "J"-shaped drilling induced fracture imaging logging.

[0026] Figure 7 This is a schematic diagram illustrating the transformation process of geostress between geodetic coordinates and geostress coordinate systems;

[0027] Figure 8 This is a schematic diagram illustrating the conversion between the geodetic coordinate system and the wellbore coordinate system;

[0028] Figure 9 This is a schematic diagram of the wellbore induced fracture initiation mechanism;

[0029] Figure 10 It is a schematic diagram showing the angle between the minimum stress acting on the wellbore wall of an arbitrary trajectory and the wellbore axis;

[0030] Figure 11 Example azimuth angle α b =0° and well inclination angle β b A schematic diagram of the principal stress around the wellbore at 0°, the induced fracture, and its angle with the wellbore axis;

[0031] Figure 12 Example azimuth angle α b =0° and well inclination angle β b A schematic diagram of the principal stress around the wellbore at a angle of 30°, the induced fracture, and its angle with the wellbore axis;

[0032] Figure 13 Example azimuth angle α b =0° and well inclination angle β b A schematic diagram of the principal stress around the wellbore, the induced fracture, and its angle with the wellbore axis at a 60° angle.

[0033] Figure 14 Example azimuth angle α b =0° and well inclination angle β b A schematic diagram of the principal stress around the wellbore at 90°, the induced fracture, and its angle with the wellbore axis;

[0034] Figure 15 Example azimuth angle α b =30° and well inclination angle β b A schematic diagram of the principal stress around the wellbore at 0°, the induced fracture, and its angle with the wellbore axis;

[0035] Figure 16 Example azimuth angle α b =30° and well inclination angle β b A schematic diagram of the principal stress around the wellbore at a angle of 30°, the induced fracture, and its angle with the wellbore axis;

[0036] Figure 17 Example azimuth angle α b =30° and well inclination angle β b A schematic diagram of the principal stress around the wellbore, the induced fracture, and its angle with the wellbore axis at a 60° angle.

[0037] Figure 18 Example azimuth angle α b=30° and well inclination angle β b A schematic diagram of the principal stress around the wellbore at 90°, the induced fracture, and its angle with the wellbore axis;

[0038] Figure 19 Example azimuth angle α b =60° and well inclination angle β b A schematic diagram of the principal stress around the wellbore at 0°, the induced fracture, and its angle with the wellbore axis;

[0039] Figure 20 Example azimuth angle α b =60° and well inclination angle β b A schematic diagram of the principal stress around the wellbore at a angle of 30°, the induced fracture, and its angle with the wellbore axis;

[0040] Figure 21 Example azimuth angle α b =60° and well inclination angle β b A schematic diagram of the principal stress around the wellbore, the induced fracture, and its angle with the wellbore axis at a 60° angle.

[0041] Figure 22 Example azimuth angle α b =60° and well inclination angle β b A schematic diagram of the principal stress around the wellbore at 90°, the induced fracture, and its angle with the wellbore axis;

[0042] Figure 23 Example azimuth angle α b =90° and well inclination angle β b A schematic diagram of the principal stress around the wellbore at 0°, the induced fracture, and its angle with the wellbore axis;

[0043] Figure 24 Example azimuth angle α b =90° and well inclination angle β b A schematic diagram of the principal stress around the wellbore at a angle of 30°, the induced fracture, and its angle with the wellbore axis;

[0044] Figure 25 Example azimuth angle α b =90° and well inclination angle β b A schematic diagram of the principal stress around the wellbore, the induced fracture, and its angle with the wellbore axis at a 60° angle.

[0045] Figure 26 Example azimuth angle α b =90° and well inclination angle β b A schematic diagram of the principal stress around the wellbore at 90°, the induced fracture, and its angle with the wellbore axis;

[0046] Figure 27 Example azimuth angle α b =0° and well inclination angle βb A schematic diagram of the drilling induced fracture orientation of a 30° wellbore under different bottom hole pressures;

[0047] Figure 28 Example azimuth angle α b =30° and well inclination angle β b A schematic diagram of the drilling induced fracture orientation of a 30° wellbore under different bottom hole pressures;

[0048] Figure 29 This is a schematic diagram of a sand table containing multi-scale cracks;

[0049] Figure 30 This is an example of a high-temperature, high-pressure microcrack sealing evaluation instrument; and

[0050] Figure 31 These are examples of filtration loss test results for different drilling fluid systems. Detailed Implementation

[0051] 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.

[0052] Figure 1 This is a flowchart illustrating the selection method for drilling fluid systems. Please refer to it. Figure 1 The method for selecting the drilling fluid system may include:

[0053] Step S110: Obtain the core of the target fractured formation by returning rock cuttings from the fractured formation section or by coring the target fractured formation section.

[0054] Preferably, after step S110, the method for selecting the drilling fluid system may further include: preparing a corresponding standard rock sample using the core.

[0055] For example, core samples are taken from the target fractured formation section to obtain fresh and intact cores with the same lithology as the target fractured formation, and standard rock samples are drilled. The diameter of the standard rock sample is, for example, 25.4 mm, and the length is, for example, 50.8 mm.

[0056] Step S120: Using the obtained core and rock fragments, test the permeability of the rock matrix of the target fractured stratum, the diameter of the rock matrix pore throat, and the width of different fractures.

[0057] Preferably, step S120 may include: testing the permeability of the rock matrix of the target fractured stratum using the obtained core sample; and using a scanning electron microscope to observe the core sample or the rock fragments to test the pore throat diameter and fracture width of different fractures in the rock matrix of the target fractured stratum.

[0058] Continuing with the above example, for a standard rock sample, the permeability of the target fractured stratum's matrix is ​​measured using, for example, an overburden porosity and permeability meter, for example, 0.01 mD. Using a scanning electron microscope, the standard rock sample or rock fragments are observed to test the pore throat diameter and fracture widths of different fractures in the target fractured stratum's matrix. For example... Figure 2 As shown, the distribution range of the pore throat diameter of the rock matrix in the tested fractured strata is, for example, 20–50 μm, with an average of 35 μm; the distribution range of the microcrack width is, for example, 114–140 μm, with an average of 120 μm.

[0059] Step S130: Determine the development characteristics of natural fractures and drilling-induced fractures in the surrounding rock using a preset method.

[0060] Among them, the development characteristics of natural fractures and drilling-induced fractures in the surrounding rocks include features such as fracture dip angle, fracture dip direction, and fracture width.

[0061] This invention provides two preset methods for determining the development characteristics of natural fractures and drilling-induced fractures in the surrounding rock of a well. Example development characteristics of natural fractures and drilling-induced fractures in the surrounding rock of a well are as follows: Figure 3-6 As shown in the image. The open slit area in the image is for illustrative purposes only and does not represent actual development.

[0062] Method 1: Preferably, step S130 may include: analyzing and determining the development characteristics of natural fractures and drilling-induced fractures in the surrounding rocks based on imaging logging data.

[0063] For example, based on imaging logging data (e.g., imaging logging charts), the development characteristics of natural fractures and drilling-induced fractures in the surrounding rock are analyzed and determined. Figure 5 For example, it was determined that there were goose-shaped drilling-induced fractures in the surrounding rocks of the target formation well. Using logging software such as Ciflog, JewelSuite, or Techlog, the fracture dip angle was identified as 60°, the length as 15mm, and the width as 120μm.

[0064] Again Figure 4 For example, in a vertical well, the drilling induced fractures are vertical, appearing in pairs along the direction of maximum horizontal stress, spaced 180° apart. Figure 5 and Figure 6 For example, in deviated wells, drilling induced fractures appear as groups of "eight"-shaped dark lines along the well wall, also known as goose-like or feather-like induced fractures; or they appear as fishhook-shaped or "J"-shaped fractures. Their direction is generally parallel to the maximum principal stress and they do not have any filling effect. In the dual lateral logging curves, the shallow lateral resistivity is higher than the deep lateral resistivity.

[0065] Method 2: Preferably, step S130 may include: constructing a drilling-induced fracture prediction model for the surrounding rock; and determining the development characteristics of natural fractures and drilling-induced fractures in the surrounding rock based on the drilling-induced fracture prediction model.

[0066] Further preferably, the construction of the drilling-induced fracture prediction model for the surrounding rock can include the following steps S131-S134: Step S131, after converting the geostress coordinates to the geodetic coordinate system, it is then converted to the wellbore coordinate system, and the stress tensor of the geostress in the wellbore coordinate system is converted to the polar coordinate system; Step S132, in the polar coordinate system, based on the principle of linear superposition and Biot's effective stress theory, the distribution law of the wellbore stress is obtained to obtain the wellbore stress; Step S133, the wellbore stress is converted into principal stress; Step S134, through the principal stress, the tensile failure type is determined, and the angle between each point around the well and the wellbore axis is calculated to construct the drilling-induced fracture prediction model for the surrounding rock.

[0067] For step S131, to obtain the wellbore stress distribution characteristics, the in-situ stress is first transformed to a geodetic coordinate system. For example... Figure 7 As shown, X G -Y G -Z G Represents the geodetic coordinate system, X G Indicates due north, Y G Indicates due east, Z G Indicates vertical; X S -Y S -Z S This represents the geodetic coordinate system, where the maximum horizontal geodetic stress, minimum horizontal geodetic stress, and vertical stress are represented respectively. Transforming the geodetic stress to the geodetic coordinate system involves three coordinate transformations, including: 1) around the Z-axis... G 1) Rotate the global coordinate system around the Y' axis by an angle α1 to obtain the X'-Y'-Z' coordinate system; 2) Rotate the X'-Y'-Z' coordinate system around the Y' axis by an angle β1 to obtain the X”-Y”-Z” coordinate system; 3) Rotate the X”-Y”-Z” coordinate system around the X” axis by an angle γ1, that is, the X”-Y”-Z” coordinate system can be rotated. G -Y G -Z G Coordinate system transformation to X G -Y G -Z G In a coordinate system.

[0068] Based on the above, the transformation matrix R1 can be established as shown in the following equation:

[0069]

[0070] Using stress tensor σG σ represents the geostress components in the geodetic coordinate system. S If we represent the geostress components in the geostress coordinate system, then the transformation relationship between the two is shown in the following equation:

[0071]

[0072] Where, σ S =[σ H ,0,0;0,σ h ,0;0,0,σ v ], σ H σ represents the maximum horizontal ground stress (MPa). h σ represents the minimum horizontal ground stress (MPa). v This represents the vertical ground stress (MPa).

[0073] After converting the geostress to the geodetic coordinate system, it should then be converted to the borehole coordinate system for analysis; the conversion relationship between the geodetic coordinate system (GCS) and the borehole coordinate system (BCS) is as follows: Figure 8 As shown in the figure, X B -Y B -Z B Let α2 represent the wellbore coordinate system, where α2 represents the angle between the wellbore dip direction and true north, also known as the wellbore azimuth; β2 represents the angle between the wellbore axis and the vertical direction, also known as the wellbore inclination angle. σ is used. B σ represents the stress tensor in the wellbore coordinate system. B With σ G The transformation relationship is shown in the following formula:

[0074]

[0075] The transformation matrix R2 is shown in the following equation:

[0076]

[0077] The wellbore stress tensor expressed in polar coordinates is simpler to use. Therefore, after transforming the geostress to the wellbore coordinate system, this stress tensor σ is... B That is, [σ x , σ y , σ y , τ xy , τ xz , τ yz ], transform to polar coordinates, where the parameters in the above formula are the stress components of the geostress in the wellbore coordinate system, or stress tensors.

[0078] For step S132, since the formation is drilled through, the original geostress state is disrupted, and stress is redistributed around the wellbore, resulting in stress concentration. Based on the principle of linear superposition and Biot's effective stress theory, the effective stress equation around the wellbore for any well deviation is as follows:

[0079]

[0080] Where, r w Let P be the wellbore radius (m), r be the distance (m) from any point around the well to the wellbore axis, and P be the radius of the wellbore. w P is the bottom hole fluid column pressure (MPa). p The formation pore pressure is θ (MPa), and θ is the wellbore angle, which is the angle at which a point around the well is rotated clockwise to the X-axis. b The included angle (°), α is the Biot effective stress coefficient, which can take values ​​between 0 and 1, dimensionless, and v is Poisson's ratio.

[0081] For step S133, after obtaining the wellbore stress distribution law, the wellbore stress is substituted into the rock strength criterion to determine the stability of the surrounding rock. The rock strength criterion is expressed in the form of principal stresses. Therefore, the wellbore stress is converted into the form of principal stresses. The equation for converting the wellbore stress in polar coordinates into principal stresses is as follows:

[0082]

[0083] The relative magnitudes of the three principal stresses at any point around the well vary with the change in the bottom hole fluid column pressure. To accurately distinguish the three principal stresses around the well, the σ obtained from equation (6) is used. i ,σ j ,σ k Substitute into the following formula.

[0084]

[0085] For step S134, the relationship between the major principal stresses around the well is quantitatively analyzed to distinguish the types of tensile failure of the wellbore, and the relationship between the minimum principal stress around the well and the tensile strength of the rock is compared, as shown in the following formula:

[0086] σ3≤-σ t (4)

[0087] When σ r When σ is 3 and equation (8) holds, the wellbore undergoes the following... Figure 9 (b) type of destruction; when σ r When σ is not 3 and Equation 8 holds, the well wall undergoes the following... Figure 9 (a) The type of damage shown; when such damage occurs Figure 9(b) In the case of tensile failure of the type shown, no induced fractures are generated around the well, and the spalling of the surrounding rock causes the well diameter to expand uniformly along the well circumference; while when a failure occurs as shown in the diagram, no induced fractures are generated around the well, and the spalling of the surrounding rock causes the well diameter to expand uniformly along the well circumference; Figure 9 When the type of failure shown in (a) occurs, a drilling induced fracture will be generated around the well, and the fluid column pressure will be higher than the formation pressure, which may cause drilling fluid loss. The relationship between the angle between the induced fracture and the wellbore axis and the well axis stress is shown in the following formula.

[0088]

[0089] Where ω is the angle (°) between the drilling induction fracture and the wellbore axis, such as Figure 10 As shown, this is the angle between the direction of the maximum principal stress around the well and the wellbore axis.

[0090] After determining the in-situ stress, wellbore trajectory, and well fluid column pressure, the principal stresses at each point around the well are calculated to determine the tensile failure type. The angles between each point around the well and the wellbore axis are also calculated, thus obtaining the development morphology of the drilling induced fracture under this working condition.

[0091] Preferably, the step of determining the development characteristics of natural fractures and drilling-induced fractures in the surrounding rock based on the drilling-induced fracture prediction model can include steps S135-S136: Step S135, determining the development characteristics of drilling-induced fractures under different wellbore trajectories based on the drilling-induced fracture prediction model based on the surrounding rock; Step S136, determining the development characteristics of drilling-induced fractures under different in-well fluid column pressures based on the drilling-induced fracture prediction model based on the surrounding rock.

[0092] Preferably, step S135 may include: when the wellbore axis is parallel to any principal stress, the angle between the induced fracture and the wellbore axis is 0°, generating two symmetrically distributed fractures parallel to the wellbore axis; when the change in the angle between the induced fracture and the wellbore axis is kept within a first preset angle, a feather-shaped fracture is generated; when the change in the angle between the induced fracture and the wellbore axis is greater than the first preset angle, a J-shaped fracture is generated; and when the angle between the induced fracture and the wellbore axis is close to 0° at the minimum principal stress around the well, and then the change increases or decreases, a sinusoidal fracture is generated.

[0093] As an example, by inputting the parameters shown in Table 1 into the wellbore surrounding rock drilling induced fracture prediction model, the variation patterns of the principal stress of the wellbore wall and the angle between the induced fracture and the wellbore axis along the wellbore perimeter can be obtained for different trajectories. Figures 11-26 As shown in the figure, the left vertical axis represents the principal stress, and the purple "+" and the right vertical axis represent the angle between the drilling induced fracture and the wellbore axis. According to the rock tensile strength criterion, when the minimum principal stress of the wellbore becomes tensile stress, it will lead to the generation of drilling induced fracture.

[0094] Table 1 Model Input Parameters

[0095]

[0096] like Figure 11 As shown in (a), the first and second principal stresses around the wellbore do not change with the wellbore angle. The third principal stress reaches its maximum value in the direction of minimum horizontal stress and its minimum value in the direction of maximum horizontal stress. The angle ω between the induced fracture and the wellbore axis is always 0. Therefore, a vertical fracture is generated in the direction of maximum horizontal stress, as shown in (a). Figure 11 As shown in (b).

[0097] Keep the wellbore drilling azimuth constant (e.g., azimuth angle α). b =0°), change the well inclination angle β b Well inclination angle β b For example, the principal stress around the well, the angle between the induced fracture and the wellbore axis, and the orientation of the induced fracture for wells with angles of 30°, 60°, and 90° are respectively as follows: Figure 12-14 As shown. When the well inclination angle β b When the angle is 30°, the minimum principal stress around the well reaches its minimum at 90° and 270°. Furthermore, when the minimum principal stress is tensile stress, the angle between the induced fracture and the wellbore axis changes very little. Converting this angle into an induced fracture, as shown... Figure 12 As shown in (b), the induced fractures exhibit feather-like or goose-like characteristics; when the well inclination angle β b When the angle is 60°, the minimum principal stress around the well becomes negative along the wellbore angle, and the angle between the induced fracture and the wellbore axis varies greatly at different locations. Therefore, the attitude of the induced fracture becomes extremely complex, such as... Figure 13 As shown in (b); for horizontal wells, the minimum principal stress around the wellbore reaches its minimum at 0° and 180°, and the angle between the induced fracture and the wellbore axis is 0° for each full rotation around the wellbore, which is converted into the induced fracture orientation as shown in Figure (b). Figure 14 As shown in (b), two vertical fractures are generated at the wellbore angles of 0° and 180°.

[0098] Maintain wellbore azimuth angle α b The inclination angle β is changed to 30°. b For angles of 0°, 30°, 60°, and 90°, the principal stress around the well, the induced fracture, and their angles with the wellbore axis are obtained as follows: Figure 15-18 As shown. When the well inclination angle β b When the inclination angle β = 0°, the minimum principal stress around the well reaches its minimum value at the wellbore angles of 60° and 240°, and the angle between the induced fracture and the wellbore axis is always 0°. Therefore, two vertical fractures are generated at the wellbore angles of 60° and 240°. b When the angle is 30°, the minimum principal stress around the well becomes tensile stress between 0° and 108° and between 181° and 289°. Furthermore, the angle between the induced fracture and the wellbore axis varies significantly at this point, resulting in an induced fracture orientation as shown in the image. Figure 16 As shown in (b), it has a "J" or "fishhook" shaped feature; when the well inclination angle βb When the angle is 60°, the minimum principal stress around the well becomes tensile stress within the ranges of 0° to 82°, 163° to 262°, and 323° to 360° around the well, and the angle between the induced fracture and the wellbore axis varies greatly, transforming into an induced fracture attitude as shown in the figure. Figure 17 As shown in (b), the induced fractures produce inflection points at 60° and 240°, forming more obvious "J"-shaped fractures; when the well inclination angle is 90°, the angle between the induced fracture and the wellbore axis varies within 10°, and the induced fracture occurrence characteristics are in the transitional stage between feather-like and "fishhook-like".

[0099] Maintain wellbore azimuth angle α b The inclination angle β remains constant at 60°. b The variations of wellbore principal stress and induced fracture orientation with wellbore angle at 0°, 30°, 60°, and 90° are as follows: Figure 19-22 As shown. When the well inclination angle is 0°, the wellbore axis is parallel to the vertical geostress direction, thus generating induced fractures parallel to the wellbore axis. When the well inclination angle is 30° and 60°, the minimum principal stress around the well is tensile stress, and the angle between the induced fracture and the wellbore axis varies greatly, thus generating "J"-shaped fractures. When the well inclination angle is 90° and the minimum principal stress around the well is negative, the angle between the induced fracture and the wellbore axis varies within 10°, thus generating induced fractures whose orientation is between feather-shaped fractures and "J"-shaped fractures.

[0100] Wellbore azimuth α b The inclination angle is 90°, β. b The principal stresses around the well and the orientation of induced fractures at 0°, 30°, 60° and 90° are respectively as follows: Figure 23-26 As shown. When the well inclination angle is 0° and 90°, the wellbore axis is parallel to the directions of vertical and horizontal maximum geostress, respectively, and the angle between the induced fracture and the wellbore axis is 0°. Therefore, two fractures parallel to the wellbore axis are generated, and the two fractures are symmetrically distributed with a 180° interval. When the well inclination angle is 30° and 60°, the minimum principal stress around the well reaches its minimum value at the wellbore angles of 0° and 180°. However, when the minimum principal stress is tensile stress, the angle between the induced fracture and the wellbore axis is close to 0° at the 0° and 180° positions, with a very small variation range. Afterward, the variation range increases with the increase of the wellbore angle. The predicted occurrence of the induced fracture is as follows. Figure 24 (b) and Figure 25 As shown in (b), the induced fractures exhibit a sinusoidal orientation, making them highly susceptible to confusion with natural fractures. Furthermore, induced fractures typically appear in pairs, spaced 180° apart, in a symmetrical pattern.

[0101] As mentioned above, comparing the induced fractures generated by wells with different trajectories, when the wellbore axis is parallel to any principal stress, since there is no shear stress around the well, the angle between the induced fracture and the wellbore axis is always 0°. Therefore, two symmetrically distributed fractures parallel to the wellbore axis are usually generated. When the angle between the induced fracture and the wellbore axis varies within a first preset angle (e.g., 10°), feather-shaped fractures are generated. When the angle between the induced fracture and the wellbore axis varies more than 10°, "J"-shaped fractures are generated. When the angle between the induced fracture and the wellbore axis is close to 0° at the minimum principal stress around the well, and then the change increases or decreases sharply, approximately sinusoidal fractures are generated. In addition, induced fractures usually appear in pairs symmetrically at 180° intervals.

[0102] Preferably, step S136 may include: generating feather-shaped fractures under different bottom hole pressures; and as the pressure of the fluid column in the well increases, the angle between the drilling induced fracture and the wellbore axis gradually decreases, while the length of the induced fracture gradually increases.

[0103] As illustrated by the example, the fluid column pressure inside the well is one of the most direct, effective, and controllable measures for maintaining wellbore stability. It directly determines complex situations such as wellbore erosion or shear collapse, and working fluid leakage. Based on the drilling-induced fracture prediction model of the surrounding rock, the influence of the fluid column pressure inside the well on the induced fracture is determined. Continuing with the above example, for the azimuth angle α... b =0° and well inclination angle β b =30° wellbore under different bottom hole pressures, the occurrence of drilling induced fractures is as follows Figure 27 As shown. Analysis reveals that feather-shaped fractures were generated under different bottom hole pressures; as the hydraulic pressure inside the well increases, the angle between the drilling induced fracture and the wellbore axis gradually decreases, while the length of the induced fracture gradually increases; the induced fractures are symmetrically distributed within the wellbore, spaced at 180° intervals. For the azimuth angle α... b =30° and well inclination angle β b The variation of drilling induced fracture orientation in a 30° wellbore under different bottom hole pressures is as follows: Figure 28 As shown in the figure. Analysis shows that when the bottom hole pressure is low, feather-shaped induced fractures are generated in the wellbore. As the bottom hole pressure increases, the angle between the induced fracture and the wellbore axis gradually decreases, the length increases, and it gradually transforms into a "J"-shaped fracture.

[0104] Step S140: Using 3D printing technology, a sand disc with the same pore throat diameter and permeability as the target fractured stratum is printed, and the determined fracture width and development characteristics are printed on the sand disc to form a fracture pore type sand disc.

[0105] As an example, using 3D printing technology, a sand disc with the same pore throat diameter and permeability as the target fractured stratum is printed. The diameter and thickness of the sand disc can be determined based on the dimensions of the test specimens used in different PPA devices. In this example, the diameter of the sand disc is, for example, 63.5 mm, and the thickness is, for example, 6.35 mm. Next, the pore throat diameter and fracture width of the printed sand disc are based on... Figure 5 The target formation shown has en echelon-shaped drilling-induced fractures in the surrounding rock. A 3D-printed sand disc containing multi-scale fractures is also shown. Figure 29 As shown; then print the matrix permeability of the sand disc (which is the same as the permeability of the rock matrix of the target fractured stratum).

[0106] Step S150: Using the fractured pore-type sand disc as a medium, select the optimal drilling fluid system from different drilling fluid systems to seal the target fractured formation.

[0107] The drilling fluid system is used to seal broken formations.

[0108] Preferably, before step S150, the method for selecting the drilling fluid system may further include: using prepared bentonite slurry as a base slurry; and adding different types and concentrations of compounded plugging materials to the base slurry and stirring at a preset stirring speed to form the different drilling fluid systems.

[0109] For example, a bentonite slurry of a preset concentration (e.g., 4%) is prepared as the base slurry. Different types and concentrations of plugging materials, such as rigid particles, elastic particles, sheet-like materials, and fibrous materials, are added. The mixture is then stirred at a preset stirring speed (e.g., 12000 rpm / min) for 20 minutes to form different drilling fluid systems. For instance, a 4% bentonite slurry is prepared as the base slurry. Three 275 mL portions of the base slurry are taken and labeled as base slurry A, base slurry B, and base slurry C, respectively. No materials are added to base slurry A. 1% polymer plugging agent (calculated by weight of the base slurry) is added to base slurry B. 1% polymer plugging agent and 1% 100-mesh sepiolite powder are added to base slurry C. Drilling fluid systems A, B, and C are all stirred at 12000 rpm / min for 20 minutes to ensure the parallelism of the tests.

[0110] Preferably, before testing with a fractured porous sand disc as the medium, the formation water is saturated, which includes: immersing the fractured porous sand disc in a formation water solution; testing the weight of the sand disc after immersion for different times until the weight no longer increases, indicating that the formation water is saturated. More preferably, the pressure differential, temperature, etc., are kept constant for each test to ensure the repeatability of the printed fractured porous sand disc.

[0111] Preferably, step S150 may include: using the fractured pore-type sand disc as a medium, and employing a high-temperature and high-pressure micro-fracture plugging evaluation instrument to select the optimal drilling fluid system from different drilling fluid systems by measuring the filtration loss.

[0112] Among them, using a fractured porous sand disc as the medium, the filtration loss of different drilling fluid systems was tested. The lower the filtration loss, the better the sealing performance of the drilling fluid system for fractured porous formations.

[0113] Following the example above, using, for example Figure 30 The high-temperature, high-pressure microfracture plugging evaluation instrument shown uses a fracture porosity sand disc as the medium and filtration loss as the indicator to test the plugging effect of drilling fluid systems A, B, and C on the target fractured formation. For example, with a temperature of 120℉, a positive pressure of 700psi, and a back pressure of 200psi, the filtration losses for drilling fluid systems A, B, and C are measured to be 14mL, 13mL, and 1mL, respectively. For example, with a temperature of 212℉, a positive pressure of 700psi, and a back pressure of 200psi, the filtration losses for drilling fluid systems A, B, and C are measured again to be 35mL, 16mL, and 5mL, respectively. The test results are as follows... Figure 31 As shown, drilling fluid system C is selected as the optimal drilling fluid system. It can also be found that adding 1% polymer and 1% fiber material to the drilling fluid can achieve strong sealing of fractured and porous formations.

[0114] Accordingly, the drilling fluid system selection method provided in this embodiment of the invention uses core samples and cuttings of the same lithology as the target fractured formation to test the permeability, pore throat diameter, and microfracture width of the target fractured formation's rock matrix. Using a preset method, the development characteristics of natural fractures and drill-induced fractures in the surrounding rocks are determined. A 3D printing disc with the same pore throat diameter and permeability as the target fractured formation's rock matrix is ​​printed, and the determined fracture width and development characteristics are printed on the disc to form a fracture-pore type disc. Using the fracture-pore type disc as a medium, the optimal drilling fluid system is selected from different drilling fluid systems for sealing the target fractured formation. The development characteristics of natural fractures and drill-induced fractures in the surrounding rocks can be determined based on imaging logging data analysis or a drill-induced fracture prediction model of the surrounding rocks. This embodiment of the invention can conveniently and quickly determine the sealing effect of different drilling fluid systems on fracture-pore type formations on a PPA device, thereby selecting the optimal drilling fluid system and improving the wellbore stability of the target fractured formation.

[0115] This invention also provides a control device for selecting drilling fluid systems. The control device includes a memory, a processor, and a computer program stored in the memory and executable on the processor. The processor executes the computer program to implement the above-described method for selecting drilling fluid systems.

[0116] This invention also provides a machine-readable storage medium storing instructions that cause a machine to perform the above-described method for selecting a drilling fluid system.

[0117] 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.

[0118] 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.

[0119] 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.

[0120] 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.

[0121] In a typical configuration, a computing device includes one or more processors (CPU), input / output interfaces, network interfaces, and memory.

[0122] 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.

[0123] 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 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.

[0124] 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.

[0125] 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 selection method for a drilling fluid system for use in breaking a seal of a formation, characterized in that, The method for selecting a drilling fluid system comprises: obtaining a core of the target fractured formation by breaking a formation section to return cuttings or coring a well section of the target fractured formation; testing the permeability of a rock matrix, the rock matrix pore throat diameter and the fracture width of different fractures of the target fractured formation by the obtained core and cuttings; determining the development characteristics of natural fractures and drilling-induced fractures of the surrounding rock of the well by a preset method; printing a sand disc with the same rock matrix pore throat diameter and permeability of the target fractured formation by using a 3D printing technology, and printing the determined fractures with different fracture widths and the development characteristics on the sand disc to form a fractured-porous sand disc; and selecting a drilling fluid system with the optimal sealing performance from different drilling fluid systems as a medium to seal the target fractured formation.

2. The method for selecting a drilling fluid system according to claim 1, wherein, The testing the permeability of a rock matrix, the rock matrix pore throat diameter and the fracture width of different fractures of the target fractured formation by the obtained core and cuttings comprises: testing the permeability of a rock matrix of the target fractured formation by the obtained core; and observing the core or the cuttings by using a scanning electron microscope to test the rock matrix pore throat diameter and the fracture width of different fractures of the target fractured formation.

3. The method for selecting a drilling fluid system according to claim 1, wherein, The determining the development characteristics of natural fractures and drilling-induced fractures of the surrounding rock of the well by a preset method comprises: determining the development characteristics of natural fractures and drilling-induced fractures of the surrounding rock of the well based on imaging logging data.

4. The method for selecting a drilling fluid system according to claim 1, wherein, The determining the development characteristics of natural fractures and drilling-induced fractures of the surrounding rock of the well by a preset method comprises: constructing a drilling-induced fracture prediction model of the surrounding rock of the well; and determining the development characteristics of natural fractures and drilling-induced fractures of the surrounding rock of the well based on the drilling-induced fracture prediction model of the surrounding rock of the well.

5. The method for selecting a drilling fluid system according to claim 4, wherein, The constructing a drilling-induced fracture prediction model of the surrounding rock of the well comprises: converting the ground stress coordinates to a geodetic coordinate system, then to a wellbore coordinate system, and converting the stress tensor of the ground stress in the wellbore coordinate system to a polar coordinate system; obtaining the stress distribution law around the well in the polar coordinate system based on the linear superposition principle and the Biot effective stress theory to obtain the stress around the well; converting the stress around the well to the principal stress; and determining the tensile failure type by the principal stress, and calculating the angle between each point around the well and the wellbore axis to construct the drilling-induced fracture prediction model of the surrounding rock of the well.

6. The method for selecting a drilling fluid system according to claim 4, wherein, The determining the development characteristics of natural fractures and drilling-induced fractures of the surrounding rock of the well based on the drilling-induced fracture prediction model of the surrounding rock of the well comprises: determining the development characteristics of drilling-induced fractures under different wellbore trajectory conditions based on the drilling-induced fracture prediction model of the surrounding rock of the well; and determining the development characteristics of drilling-induced fractures under different wellbore fluid column pressure conditions based on the drilling-induced fracture prediction model of the surrounding rock of the well.

7. The method for selecting a drilling fluid system according to claim 6, wherein, The determining the development characteristics of drilling-induced fractures under different wellbore trajectory conditions based on the drilling-induced fracture prediction model of the surrounding rock of the well comprises: when the wellbore axis is parallel to any principal ground stress, the angle between the induced fracture and the wellbore axis is 0°, and two symmetrically distributed fractures parallel to the wellbore axis are generated; When the angle between the induced fracture and the wellbore axis changes within a first preset angle, a feathered fracture is generated; When the angle between the induced fracture and the wellbore axis changes beyond the first preset angle, a J-shaped fracture is generated; and When the angle between the induced fracture and the wellbore axis is close to 0° at the minimum value of the minimum principal stress around the well, and then increases or decreases, a sine-shaped fracture is generated.

8. The method for selecting a drilling fluid system of claim 1, wherein, The drilling-induced fracture prediction model based on the surrounding rock of the well determines the drilling-induced fracture development characteristics under different well fluid column pressures, comprising: Under different bottom hole pressures, a feathered fracture is generated; and With the increase of the fluid column pressure in the well, the angle between the drilling-induced fracture and the wellbore axis gradually decreases, and the length of the induced fracture gradually increases.

9. The method for selecting a drilling fluid system of claim 1, wherein, After the formation of the fracture pore type sand disc, the method for selecting the drilling fluid system further comprises: A predetermined concentration of bentonite slurry is configured as a base slurry; and Different types and concentrations of plugging materials are added to the base slurry, and stirred at a predetermined stirring speed to form different drilling fluid systems.

10. The method for selecting a drilling fluid system of claim 1, wherein, The optimal drilling fluid system is selected from different drilling fluid systems using the fracture pore type sand disc as a medium, comprising: The optimal drilling fluid system is selected from different drilling fluid systems using the fracture pore type sand disc as a medium, by using a high temperature and high pressure micro-fracture plugging evaluation instrument to measure the filtration loss.

11. A control device for drilling fluid system selection, characterized by, The control device comprises a memory, a processor and a computer program stored on the memory and executable on the processor, and the processor executes the computer program to implement the method for selecting the drilling fluid system according to any one of claims 1-10.

12. A machine-readable storage medium, characterized in that, The machine readable storage medium stores instructions that cause the machine to execute the method for selecting the drilling fluid system according to any one of claims 1-10.

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