Method for predicting sand production pressure differential profile in perforated wells of deep sandstone reservoirs

Abstract

This invention provides a method for predicting the sand production pressure differential profile of perforated wells in deep sandstone reservoirs. The method includes: calculating rock mechanical parameter values ​​using logging data from the target well to obtain a rock mechanical parameter profile along the well trajectory; calculating the geostress field distribution of the target well to obtain a profile of the three principal stress values ​​along the well trajectory; calculating the geostress values ​​under different formation pressure values ​​based on changes in reservoir pressure; establishing a wellbore stress distribution model; calculating the wellbore stress distribution at each point in the well section; substituting the wellbore stress values ​​at each point in the well section into rock failure criteria to calculate the critical sand production pressure differential profile of the target well and obtain the sand-producing well section; calculating the magnitude of geostress values ​​under different reservoir pressures and substituting them into the sand production pressure differential model to calculate the critical sand production pressure differential for each production stage. This invention solves the problem of unreasonable sand production pressure differential profile prediction methods in existing technologies.

Description

Technical Field

[0001] This invention relates to the field of oil and gas development technology, and more specifically, to a method for predicting sand production differential profiles in perforated wells of deep sandstone reservoirs. Background Technology

[0002] Deep, ultra-high pressure, high-yield sandstone oil reservoirs possess enormous reserves and extremely high production capacity, offering broad exploration and development prospects. However, due to their deep burial depth, high reservoir temperature, and high formation pressure, sand production can lead to serious problems affecting safe production, such as wellbore sand accumulation, fluid accumulation, tubing damage, and damage to surface equipment. This also results in high sand control costs and significant economic losses. To ensure the normal and efficient exploitation of high-yield reservoirs, developing a reasonable production plan based on sand production pressure differential prediction is essential. Sand production typically occurs more frequently in loose sandstone oil and gas reservoirs with high porosity, low cementation, and low rock strength. However, recent production practices in similar deep, ultra-high pressure sandstone reservoirs have shown that sand production risks also exist during production. These reservoirs are deeply buried, and the pressure from the overlying strata exerts a significant compaction effect on the reservoir rocks, resulting in relatively dense rocks. Experienced sand production prediction methods often fail to predict sand production, and currently, there is a lack of reasonable sand production pressure differential profile prediction methods tailored to the characteristics of these reservoirs.

[0003] Therefore, the existing technology has the problem of unreasonable prediction methods for sand pressure differential profile. Summary of the Invention

[0004] The main objective of this invention is to provide a method for predicting sand production pressure differential profiles in perforated wells of deep sandstone reservoirs, so as to solve the problem that existing methods for predicting sand production pressure differential profiles are unreasonable.

[0005] To achieve the above objectives, according to one aspect of the present invention, a method for predicting the sand production pressure differential profile of a perforated well in a deep sandstone reservoir is provided, comprising: calculating rock mechanical parameter values ​​using logging data from a target well to obtain a rock mechanical parameter profile along the well trajectory; calculating the geostress field distribution of the target well to obtain a profile of the three principal stress values ​​along the well trajectory; calculating the geostress values ​​under different formation pressure values ​​based on changes in reservoir pressure; establishing a wellbore stress distribution model; calculating the wellbore stress distribution at each point in the well section; substituting the wellbore stress values ​​at each point in the well section into the rock failure criterion to calculate the critical sand production pressure differential profile of the target well and obtain the sand-producing well section; calculating the magnitude of the geostress values ​​under different reservoir pressures and substituting them into the sand production pressure differential model to calculate the critical sand production pressure differential at each production stage.

[0006] Furthermore, when calculating rock mechanical parameters using logging data from the target well, the natural gamma, density, sonic parameters, resistivity, and well diameter parameters obtained from logging the reservoir section of the target well are selected to calculate the rock mechanical parameters of the target formation.

[0007] Furthermore, in calculating the stress field distribution of the target well and obtaining the triaxial principal stress profile along the well trajectory, the overlying formation pressure of the target well is obtained by integrating the density logging parameters, and the calculation formula is as follows:

[0008]

[0009] Where, σ v Total vertical stress, unit MPa, D TV Vertical depth, in meters (m), g is the acceleration due to gravity, O is the offset value, and ρ is the vertical depth. b Bulk density, unit: kg / m³ 3 .

[0010] Furthermore, in the process of calculating the stress field distribution of the target well and obtaining the triaxial principal stress profile along the well trajectory, the relationship between the maximum and minimum horizontal principal stresses of the target well is as follows:

[0011]

[0012]

[0013] Where, σ h For the minimum horizontal principal stress, σ H The maximum horizontal principal stress is given by α, the effective stress coefficient (Biot coefficient), μ, and P. p Let E be the pore pressure, E be the static Young's modulus, and ξ be the pore pressure. h ξ is the strain in the direction of minimum principal stress. H Strain is the strain in the direction of maximum principal stress.

[0014] Furthermore, after establishing the wellbore stress distribution model, the rock mechanics parameters and geostress values ​​along the wellbore trajectory of the target well are input into the established wellbore stress distribution model to calculate the wellbore stress distribution at each point in the well section.

[0015] Furthermore, the established wellbore stress distribution models include a perforated wellbore stress distribution model, a perforated wellbore fluid seepage additional stress and production pressure differential stress distribution model, a wellbore fluid drag force stress model during production, and a fluid drag force stress distribution model at the perforation wall.

[0016] Furthermore, the stress distribution model for the perforated wellbore is as follows:

[0017]

[0018] σ xx , σ yy , σ zz —These represent the normal stress components in the coordinate system (x, y, z), with units of MPa and τ.xy , τ yz , τ xz —These represent the shear stress components in the coordinate system (x, y, z), with units of MPa.

[0019] Furthermore, the stress distribution model for the additional stress from fluid seepage in the perforated wellbore and the production pressure differential is as follows:

[0020]

[0021] Furthermore, the stress model for the drag force of the oil well fluid during the production process is as follows:

[0022]

[0023] Furthermore, the stress distribution model at the orifice wall of the fluid drag force perforation is as follows:

[0024]

[0025] Furthermore, by incorporating the wellbore stress values ​​at various points in the well section into the rock failure criterion, calculating the critical sand-producing production pressure differential profile of the target well, and obtaining the sand-producing well section, the stresses in formula (7) are calculated, and the maximum stress σ1 and minimum stress σ3 are substituted into the MC failure criterion to obtain the critical flowing pressure P. w .

[0026] Furthermore, after obtaining the critical flow pressure P w Then, the formation pressure and stress field magnitudes at different production stages of the oil well are calculated, and the critical sand production pressure difference under different formation pressures is obtained through formulas (7) and (8). Formula (8) can be expressed as:

[0027]

[0028] Furthermore, the critical sand-producing pressure differential under different formation pressures can be expressed as formula (9):

[0029] ΔP=P w -P p Formula (9)

[0030] Applying the technical solution of this invention, the method for predicting the sand production pressure differential profile of a perforated well in a deep sandstone reservoir in this application includes: calculating rock mechanical parameter values ​​using logging data from the target well to obtain a rock mechanical parameter profile along the well trajectory; calculating the geostress field distribution of the target well to obtain a profile of the three principal stress values ​​along the well trajectory; calculating the geostress values ​​under different formation pressure values ​​based on changes in reservoir pressure; establishing a wellbore stress distribution model; calculating the wellbore stress distribution at each point in the well section; substituting the wellbore stress values ​​at each point in the well section into the rock failure criterion to calculate the critical sand production pressure differential profile of the target well and obtain the sand-producing well section; calculating the magnitude of the geostress values ​​under different reservoir pressures and substituting them into the sand production pressure differential model to calculate the critical sand production pressure differential at each production stage.

[0031] Based on well logging data and considering various influencing factors, this invention can more accurately predict the critical pressure differential profile for sand production in perforated wells of this type of reservoir, providing a theoretical basis for reasonably avoiding sand-producing well sections and recommending reasonable production pressure differentials. Attached Figure Description

[0032] The accompanying drawings, which form part of this application, are used to provide a further understanding of the invention. The illustrative embodiments of the invention and their descriptions are used to explain the invention and do not constitute an undue limitation of the invention. In the drawings:

[0033] Appendix Figure 1 This is a technical roadmap for the method of predicting the critical pressure differential profile of sand production in perforated wells of deep ultra-high pressure sandstone reservoirs provided in this invention.

[0034] Appendix Figure 2 This is a comprehensive diagram of the reservoir rock mechanical parameters of the target well section in the prediction method for the critical pressure difference profile of sand production in perforated wells of deep ultra-high pressure sandstone reservoirs provided in this invention example.

[0035] Appendix Figure 3 This is a comprehensive geostress profile of the target well in the method for predicting the critical pressure difference profile of sand production in perforated wells of deep ultra-high pressure sandstone reservoirs provided in this invention.

[0036] Appendix Figure 4 This is a prediction diagram of the sand production differential pressure of the target well reservoir section without considering fluid drag force in the prediction method for the critical pressure differential pressure profile of perforated wells in deep ultra-high pressure sandstone reservoirs provided by the present invention.

[0037] Appendix Figure 5 This is a prediction diagram of the sand production pressure differential of the target well reservoir section in the prediction method for the critical pressure differential profile of sand production in perforated wells of deep ultra-high pressure sandstone reservoirs provided in this invention.

[0038] Appendix Figure 6This is a critical pressure differential profile prediction method for sand production in perforated wells of deep ultra-high pressure sandstone reservoirs provided by this invention, showing the critical pressure differential profile for sand production of the target well under different formation pressures at different production stages. Detailed Implementation

[0039] It should be noted that, unless otherwise specified, the embodiments and features described in this application can be combined with each other. The present invention will now be described in detail with reference to the accompanying drawings and embodiments.

[0040] It should be noted that, unless otherwise specified, all technical and scientific terms used in this application have the same meaning as commonly understood by one of ordinary skill in the art to which this application pertains.

[0041] In this invention, unless otherwise stated, directional terms such as "upper," "lower," "top," and "bottom" are generally used in relation to the direction shown in the accompanying drawings, or in relation to the vertical, perpendicular, or gravitational direction of the component itself; similarly, for ease of understanding and description, "inner" and "outer" refer to the inner and outer contours of each component itself, but the above directional terms are not intended to limit this invention.

[0042] To address the problem of unreasonable sand production differential pressure profile prediction methods in existing technologies, this application provides a method for predicting sand production differential pressure profiles in perforated wells of deep sandstone reservoirs.

[0043] like Figures 1 to 6 As shown, the method for predicting the sand production pressure differential profile of perforated wells in deep sandstone reservoirs in this application includes: calculating rock mechanical parameter values ​​using logging data from the target well to obtain a rock mechanical parameter profile along the well trajectory; calculating the geostress field distribution of the target well to obtain a profile of the three principal stress values ​​along the well trajectory; calculating the geostress values ​​under different formation pressure values ​​based on changes in reservoir pressure; establishing a wellbore stress distribution model; calculating the wellbore stress distribution at each point in the well section; substituting the wellbore stress values ​​at each point in the well section into the rock failure criterion to calculate the critical sand production pressure differential profile of the target well and obtain the sand-producing well section; calculating the magnitude of the geostress values ​​under different reservoir pressures and substituting them into the sand production pressure differential model to calculate the critical sand production pressure differential at each production stage. This invention, based on logging data and considering various characteristic influencing factors, can more accurately predict the critical sand production pressure differential profile of perforated wells in such reservoirs, providing a theoretical basis for reasonably avoiding sand-producing well sections and recommending reasonable production pressure differentials.

[0044] In one specific embodiment of this application, the method for predicting sand production pressure differential profiles in perforated wells of deep sandstone reservoirs mainly includes:

[0045] (A) Calculate the rock mechanical parameter values ​​using the target well logging data and obtain the rock mechanical parameter profile along the well trajectory;

[0046] (B) Calculate the stress field distribution of the target well and obtain the triaxial principal stress profile along the well trajectory;

[0047] (C) As the reservoir pressure decreases during the reservoir production process, the geostress field changes. Calculate the geostress value under different formation pressure values.

[0048] (D) Input the rock mechanics parameters and geostress values ​​along the well trajectory of the target well into the established wellbore stress distribution model to calculate the wellbore stress distribution at each point in the well section;

[0049] (E) The well perimeter stress values ​​at each point in the well section are incorporated into the rock failure criterion to calculate the critical sand production pressure differential profile of the target well, and at the same time, the well section most prone to sand production is identified.

[0050] (F) Calculate the magnitude of geostress under different reservoir pressures, and input it into the sand production pressure difference model to calculate the critical sand production pressure difference for each production stage.

[0051] This invention, based on rock mechanics parameters and geostress parameters, and comprehensively considering the influence of factors such as fluid drag force, formation pressure depletion, and geostress changes on sand production, predicts the critical sand production pressure differential profile for deep ultra-high pressure sandstone reservoirs. This solves the problem of difficulty in predicting the critical production pressure differential for sand production in such gas reservoirs and provides a reference for sand control measures in oil well production.

[0052] In step A, the natural gamma ray, density, sonic parameters, resistivity, and wellbore diameter obtained from well logging of the target well are used to calculate the rock mechanics parameters of the target formation. Sometimes shear wave data is missing from the well logging data; in such cases, shear wave velocity can be obtained by converting data such as formation P-wave velocity.

[0053]

[0054] The formula for calculating Young's modulus E is shown in (11):

[0055]

[0056] In equation (11), ρ b The value is the density logging value, in kg / m³.

[0057] The formula for calculating the dynamic Poisson's ratio is shown in (12):

[0058]

[0059] The formula for calculating compressive strength is shown in (13):

[0060] S c =E[0.008V sh +0.0045(1-V sh)] Formula (13)

[0061] In equation (13), V sh The mud content can be calculated from the natural gamma curve.

[0062] The formula for the shear modulus of reservoir rock is:

[0063] G = ρV s 2 Formula (14)

[0064] In equation (14), G is the shear modulus, GPa; ρ is the formation density (which can be obtained from the density curve), g / cm3.

[0065] The formula for calculating the internal friction coefficient of reservoir rock is:

[0066]

[0067] In step B, in a preferred embodiment of the present invention, the vertical principal stress, i.e., the overlying formation pressure, can generally be determined by integrating the density logging parameters. The calculation formula is shown in (1):

[0068]

[0069] Where, σ v Total vertical stress, unit MPa, D TV Vertical depth, in meters (m), g is the acceleration due to gravity, O is the offset value, and ρ is the vertical depth. b Bulk density, unit: kg / m³ 3 .

[0070] In step B, in a preferred embodiment of the present invention, the preferred combination of the maximum and minimum horizontal principal stresses in the porous elasticity calculation formulas (2) and (3) is as follows:

[0071]

[0072]

[0073] Where, σ h For the minimum horizontal principal stress, σ H The maximum horizontal principal stress is given by α, the effective stress coefficient (Biot coefficient), μ, and P. p Let E be the pore pressure, E be the static Young's modulus, and ξ be the pore pressure. h ξ is the strain in the direction of minimum principal stress. H Strain is the strain in the direction of maximum principal stress.

[0074] In step C, as the oil and gas reservoir is exploited, the reservoir pressure decreases. The pressure of the overlying strata is borne jointly by the rock skeleton and rock fluids. Assuming the overlying strata pressure remains constant, the decreasing pore pressure of the formation leads to increasing pressure on the rock skeleton. At a specific burial depth, the rock's bearing capacity is fixed. When the effective stress it bears exceeds the bearing capacity of the reservoir rock, rock failure occurs. Therefore, during oil reservoir production, the formation undergoes a series of complex geomechanical processes, including elastic compaction, plastic deformation, the formation of new microfractures, and the closure or opening of existing fractures. The change in vertical principal stress is negligible, but the maximum and minimum horizontal principal stresses also change simultaneously, which can be expressed as:

[0075]

[0076] in:

[0077]

[0078] In the formula:

[0079] P i ρ is the original pressure, MPa; ρ is the load factor, P. c The current formation pressure is in MPa.

[0080] In step D, the stress distribution calculation model for the perforated wellbore can be represented as (4):

[0081]

[0082] σ xx , σ yy , σ zz —These represent the normal stress components in the coordinate system (x, y, z), with units of MPa and τ. xy , τ yz , τ xz —These represent the shear stress components in the coordinate system (x, y, z), with units of MPa.

[0083] Furthermore, the stress distribution model for the additional stress from fluid seepage in the perforated wellbore and the production pressure differential is as follows:

[0084]

[0085] Furthermore, the stress model for the drag force of the oil well fluid during the production process is as follows:

[0086]

[0087] Furthermore, the stress distribution model at the orifice wall of the fluid drag force perforation is as follows:

[0088]

[0089] By incorporating the wellbore stress values ​​at various points in the well section into the rock failure criterion, calculating the critical sand-producing production pressure differential profile of the target well, and obtaining the sand-producing well section, the stresses in formula (7) are calculated. The maximum stress σ1 and the minimum stress σ3 are then incorporated into the MC failure criterion to obtain the critical flowing pressure P. w .

[0090] After obtaining the critical flow pressure P w Then, the formation pressure and stress field magnitudes at different production stages of the oil well are calculated, and the critical sand production pressure difference under different formation pressures is obtained through formulas (7) and (8). Formula (8) can be expressed as:

[0091]

[0092] Furthermore, the critical sand-producing pressure differential under different formation pressures can be expressed as formula (9):

[0093] ΔP=P w -P p Formula (9)

[0094] In one specific embodiment of this application:

[0095] (1) Establish the rock mechanical parameter profile of the target well;

[0096] Natural gamma ray, density, sonic logging, and resistivity data from the X reservoir section of the target well (5200–5700 m) were selected. Dynamic rock mechanical parameters (compressive strength, Young's modulus, dynamic Poisson's ratio, internal friction coefficient, etc.) of the target formation were calculated using parameter calculation formulas consistent with reservoir characteristics. Finally, a comprehensive rock mechanical parameter profile of the target well was obtained, as shown in the attached figure. Figure 2 As shown in the comprehensive diagram of reservoir rock mechanical parameters, the average uniaxial compressive strength is 73 MPa, the average Young's modulus is 33 GPa, the average Poisson's ratio is 0.24, the average internal friction coefficient is 0.74, and the average porosity is 0.1.

[0097] (2) Establish the geostress parameter profile of the target well;

[0098] The vertical principal stress is determined by integrating the density logging curve, and the calculation formula is shown in (2). The optimal combination of the horizontal maximum and minimum principal stresses is calculated using porous elastic formulas (3) and (4). The geostress profile is obtained based on field construction data, logging curves, and core experiments, as shown in (2). Figure 3As shown, the average horizontal formation pressure gradient is 0.024 MPa / m, with a horizontal formation pressure of approximately 133 MPa; the average vertical stress gradient is 0.26 MPa / m, with a vertical stress of approximately 146 MPa; the average minimum horizontal principal stress gradient is 0.025 MPa / m, with a minimum horizontal principal stress of approximately 139 MPa; and the average maximum horizontal principal stress gradient is 0.028 MPa / m, with a maximum horizontal principal stress of approximately 150 MPa.

[0099] (3) Establish the critical production pressure differential profile of perforated wells in deep ultra-high pressure sandstone reservoirs and identify sand-prone well sections;

[0100] By inputting rock mechanics and geostress parameters into a stress distribution model at the perforation wall considering fluid drag and using the Mohr-Coulomb criterion, the critical flowing pressure and corresponding critical sand production pressure differential profile were obtained. The target well has an azimuth of approximately 90°, high formation pressure, and high production. The fluid drag at the perforation is extremely strong. At this point, the perforation density is 16 perforations / m, the perforated oil layer thickness is 1m, the perforation radius is 5mm, the length of the cement sheath outside the perforation is 0.95m, the permeability around the perforation is 65mD, the skin factor is 1.5, and the oil layer thickness is 11m. The critical sand production pressure differential profile without considering drag is as follows: Figure 4 As shown. Sand production always occurs where the rock first fails; that is, the minimum critical pressure difference along the well depth profile is the critical sand production pressure difference for that well. The minimum critical sand production pressure difference for the 5200–5700m horizontal well section is 43.9 MPa. Using the critical sand production pressure difference model for perforation considering wellbore drag force established in this invention, the critical sand production pressure difference profile for perforation along the maximum horizontal principal stress of the target well is calculated as follows. Figure 5 As shown, when using perforated completion, the minimum critical sand production pressure differential of the well is approximately 39.6 MPa, which is about 4.3 MPa lower than the critical sand production pressure differential without considering drag force. Furthermore, the critical sand production pressure differential is relatively low near well sections such as 5210m and 5420m. To ensure the stability of the perforation channel in the perforated well, perforation can be avoided at these lower critical sand production pressure differentials.

[0101] (4) Prediction of sand production pressure difference of target wells under different formation pressures;

[0102] As reservoir pressure decreases during oil production, the geostress field changes. This study calculates the geostress values ​​under different formation pressures. The original formation pressure of the target reservoir is 133 MPa. Assuming the same rock mechanics parameters at the same location within the reservoir, and with formation pressure depletion and overlying stress remaining constant, the study uses the aforementioned single-point analysis of rock mechanics parameters. Taking the perforation direction along the direction of maximum principal stress as an example, the study analyzes the variation of geostress and the corresponding change in the critical pressure differential for sand production at the perforation hole. Figure 6As shown, with the depletion of formation pressure, both the maximum and minimum horizontal principal stresses decrease. Furthermore, calculations using the horizontal well perforation sand production critical pressure differential model show that, as the maximum and minimum horizontal principal stresses decrease, the critical perforation sand production critical pressure differential at this location also decreases from 39.6 MPa to 4.3 MPa.

[0103] As can be seen from the above description, the above embodiments of the present invention achieve the following technical effects. The present invention is based on rock mechanics parameters and geostress parameters, and comprehensively considers the influence of factors such as fluid drag force, formation pressure depletion and geostress changes on sand production. It predicts the critical sand production pressure differential profile of deep ultra-high pressure sandstone reservoirs, solves the problem of difficulty in predicting the critical production pressure differential of such gas reservoirs, and provides a reference for sand control measures in oil well production.

[0104] Obviously, the embodiments described above are merely some, not all, embodiments of the present invention. All other embodiments obtained by those skilled in the art based on the embodiments of the present invention without inventive effort should fall within the scope of protection of the present invention.

[0105] It should be noted that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the exemplary embodiments according to this application. As used herein, the singular form is intended to include the plural form as well, unless the context clearly indicates otherwise. Furthermore, it should be understood that when the terms "comprising" and / or "including" are used in this specification, they indicate the presence of features, steps, operations, devices, components, and / or combinations thereof.

[0106] It should be noted that the terms "first," "second," etc., used in the specification, claims, and accompanying drawings of this application are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that such data can be interchanged where appropriate so that the embodiments of this application described herein can be implemented in sequences other than those illustrated or described herein.

[0107] The above description is merely a preferred embodiment of the present invention and is not intended to limit the invention. Various modifications and variations can be made to the present invention by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A method for predicting sand production pressure differential profiles in perforated wells of deep sandstone reservoirs, characterized in that, include: Rock mechanical parameter values ​​are calculated using target well logging data to obtain a rock mechanical parameter profile along the well trajectory; Calculate the stress field distribution of the target well and obtain the triaxial principal stress profile along the well trajectory; Calculate the geostress values ​​under different formation pressure values ​​based on changes in reservoir pressure; Establish a wellbore stress distribution model; Calculate the wellbore stress distribution at various points in the well section; By incorporating the well perimeter stress values ​​at various points in the well section into the rock failure criterion, the critical sand production pressure differential profile of the target well is calculated to obtain the sand-producing well section. Calculate the magnitude of geostress under different reservoir pressures, and then input the sand production pressure difference model to calculate the critical sand production pressure difference at each production stage; After establishing the wellbore stress distribution model, the rock mechanics parameters and geostress values ​​along the wellbore trajectory of the target well are input into the established wellbore stress distribution model to calculate the wellbore stress distribution at each point in the well section. The established wellbore stress distribution models include the perforated wellbore stress distribution model, the stress distribution model of the additional stress from fluid seepage in the perforated wellbore and the production pressure differential, the stress model of the oil well fluid drag force during production, and the stress distribution model of the fluid drag force at the perforation wall. The stress distribution model at the wall of the fluid drag force perforation is as follows: By incorporating the wellbore stress values ​​at various points in the well section into the rock failure criterion, calculating the critical sand-producing production pressure differential profile of the target well, and obtaining the sand-producing well section, the stresses in formula (7) are calculated, and the maximum stress σ1 and minimum stress σ3 are substituted into the MC failure criterion to obtain the critical flowing pressure P. w ; After obtaining the critical flow pressure P w Then, the formation pressure and stress field magnitudes at different production stages of the oil well are calculated, and the critical sand production pressure difference under different formation pressures is obtained through formulas (7) and (8). Formula (8) can be expressed as: Furthermore, the critical sand-producing pressure differential under different formation pressures can be expressed as formula (9): ΔP=P w -P p Formula (9) The calculation of geostress values ​​under different formation pressure values ​​based on changes in reservoir pressure includes calculating the magnitude of geostress values ​​under different formation pressure values ​​as the reservoir pressure decreases during the reservoir production process and the geostress field changes. The formula for calculating Young's modulus E is shown in (11): In equation (11), ρ b Density logging value, kg / m3; Where, σ h For the minimum horizontal principal stress, σ H The maximum horizontal principal stress is given by α, the effective stress coefficient (Biot coefficient), μ, and P. p Let E be the pore pressure, E be the static Young's modulus, and ξ be the pore pressure. h ξ is the strain in the direction of minimum principal stress. H The strain is in the direction of the maximum principal stress; the maximum and minimum horizontal principal stresses are expressed as: in: In the formula: P i ρ is the original pressure, MPa; ρ is the load factor, P. c The current formation pressure is in MPa.

2. The method for predicting sand production pressure differential profiles in perforated wells of deep sandstone reservoirs according to claim 1, characterized in that, When calculating rock mechanical parameters using logging data from the target well, the natural gamma, density, sonic parameters, resistivity, and well diameter parameters obtained from logging the reservoir section of the target well are selected to calculate the rock mechanical parameters of the target formation.

3. The method for predicting sand production pressure differential profiles in perforated wells of deep sandstone reservoirs according to claim 1, characterized in that, The stress distribution model for the perforated wellbore is as follows: σ xx , σ yy , σ zz —These represent the normal stress components in the coordinate system (x, y, z), with units of MPa and τ. xy , τ yz , τ xz —These represent the shear stress components in the coordinate system (x, y, z), with units of MPa.

4. The method for predicting sand production pressure differential profiles in perforated wells of deep sandstone reservoirs according to claim 3, characterized in that, The stress distribution model for the additional stress from fluid seepage in the perforated wellbore and the production pressure differential is as follows: 。 5. The method for predicting sand production pressure differential profiles in perforated wells of deep sandstone reservoirs according to claim 4, characterized in that, The stress model for the drag force of oil well fluid during the production process is as follows: 。

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