A complex formation wellbore stability prediction method, system, device and medium

Abstract

The application discloses a complex stratum well wall stability prediction method, system, device and medium, obtains measured stratum data of a drilled well reservoir section; calculates stratum pore pressure and rock mechanics parameters according to the measured stratum data; calculates the ground stress size according to the stratum pore pressure and the rock mechanics parameter profile; takes the additional density of the mud as the initial value, and takes the tectonic strain coefficients in the horizontal minimum principal stress direction and the horizontal maximum principal stress direction as the initial tectonic strain coefficients, obtains the initial pore fluid pressure, the horizontal minimum principal stress and the horizontal maximum principal stress of the stratum based on the measured stratum data, and can obtain the collapse pressure equivalent density and the fracture pressure equivalent density of the drilled well according to the collapse pressure equivalent density calculation formula and the fracture pressure equivalent density calculation formula; when the pressure corresponding to the drilling mud density is greater than the collapse pressure equivalent density and less than the fracture pressure equivalent density, the well wall is stable.

Description

TECHNICAL FIELD

[0001] The application belongs to the field of oil and gas exploration and development, and relates to a complex formation wellbore stability prediction method, system, device and medium. BACKGROUND

[0002] Wellbore stability refers to the ability of the wellbore to maintain its original stress state. Wellbore instability is caused by the destruction of the original balanced stress state during drilling and other processes, resulting in wellbore collapse, expansion, caving and other phenomena. There are many methods for studying wellbore stability. One is drilling fluid chemical composition research, which mainly studies the hydration swelling effect and physicochemical properties caused by the clay mineral content in the mineral composition of the collapsed formation section. The second is rock mechanics research, which does not consider the chemical influence of drilling fluid and purely studies wellbore stability from the perspective of rock mechanics.

[0003] Oil and gas reservoir sections are generally the focus of oil and gas field exploration and development. The downhole information obtained during exploration and development of the reservoir section is relatively complete, while the downhole information obtained for the engineering section has limitations, such as incomplete logging data and lack of measured formation pore fluid pressure data. With the deepening of oil and gas exploration and development, deep oil and gas resources are receiving more and more attention. During drilling in deep formations, the engineering section lacks measured formation pressure data and in-situ stress test data, and often uses data from the reservoir section, which will result in inaccurate calculation of the collapse pressure and fracture pressure of deep complex formations, posing a challenge to rapid and efficient drilling. SUMMARY

[0004] The purpose of the present application is to overcome the shortcomings of the prior art and provide a complex formation wellbore stability prediction method, system, device and medium that can accurately calculate the collapse pressure and fracture pressure of deep complex formations and accurately predict the wellbore stability of complex formations.

[0005] To achieve the above purpose, the following technical solutions are used:

[0006] A complex formation wellbore stability prediction method, comprising the following processes:

[0007] S1, obtaining measured formation data of a drilled well reservoir section;

[0008] S2, calculating the formation pore pressure and rock mechanics parameters according to the measured formation data;

[0009] S3, calculating the tectonic strain coefficient of the horizontal minimum principal stress direction and the tectonic strain coefficient of the horizontal maximum principal stress direction according to the formation pore pressure and rock mechanics parameter profile;

[0010] S4, taking the additional density of the mud as zero as the initial value, and the structural strain coefficients in the direction of the minimum and maximum horizontal principal stress as the initial structural strain coefficients, based on the measured formation data, the initial pore fluid pressure, minimum horizontal principal stress and maximum horizontal principal stress of the formation are obtained. According to the calculation formulas for the collapse pressure equivalent density and the fracture pressure equivalent density, the collapse pressure equivalent density and fracture pressure equivalent density of the drilled well can be obtained.

[0011] S5. Compare the drilling mud density with the collapse pressure equivalent density and the rupture pressure equivalent density. If the pressure corresponding to the drilling mud density is greater than the collapse pressure equivalent density but less than the rupture pressure equivalent density, then the wellbore is stable.

[0012] Preferably, the formation pore pressure is:

[0013]

[0014] In the formula: P p P is the formation pore pressure; P0 is the overlying formation pressure; P w Δt represents the formation water hydrostatic column pressure; Δt is the measured sonic transit time logging value; Δt n is the sonic transit time value on the normal compaction curve; C is the formation compaction index.

[0015] Preferably, the calculation process for the structural strain coefficients along the horizontal minimum principal stress direction and the horizontal maximum principal stress direction is as follows:

[0016] P f =3σ H -σ h -α P +S t

[0017] In the formula: P f σ is the rupture pressure; H σ is the maximum horizontal principal stress; h The minimum principal stress is horizontal; α is the Biot coefficient; P P Formation pore pressure; S t Tensile strength of rock;

[0018]

[0019]

[0020]

[0021] In the formula: ν is the Poisson's ratio of the rock; E is the elastic modulus of the rock; ε H The strain coefficient ε is constructed for the direction of the maximum horizontal principal stress. hσ V σ is the vertical ground stress; H0 is the depth of the logging starting point; ρ0(h) is the density at the depth of h in the unlogged section; and g is the acceleration of gravity.

[0022] Preferably, the calculation process of the collapse pressure equivalent density and the fracture pressure equivalent density is as follows:

[0023]

[0024]

[0025] In the formula, Δρ is the additional density; ρ mc σ is the collapse pressure equivalent density; ρ mf σ is the fracture pressure equivalent density; σ H σ is the horizontal maximum principal stress; σ h σ is the horizontal minimum principal stress; C is the formation compaction index; P P P is the formation pore pressure; S t σ is the rock tensile strength; α is the Biot coefficient; H is the well depth; and D is the depth.

[0026] Preferably, after S4 is completed, the formation pore pressure prediction range, the hole enlargement rate, the actually drilled mud density, and the formation breakdown test data of other drilled wells are obtained, and the above data are used as constraint conditions to adjust and optimize the additional density, the horizontal minimum principal stress direction construction strain coefficient, and the horizontal maximum principal stress direction construction strain coefficient.

[0027] Preferably, the pressure in the range greater than the collapse pressure equivalent density and less than the fracture pressure equivalent density is used as the recommended value of the mud density during drilling.

[0028] Preferably, after S4 is completed, the collapse pressure equivalent density of different formation groups of the wells calculated by multiple wells is used for interpolation to obtain the collapse pressure equivalent density recommended value of the comparative well of the same formation group, and if the actually used mud density of the comparative well is greater than the recommended value and the hole is regular, the prediction result is correct, and if the hole enlargement rate is greater than 15%, the prediction result is incorrect; if the actually used mud density of the comparative well is less than the recommended value and the hole is regular, the prediction result is incorrect, and if the hole enlargement rate is greater than 15%, the prediction result is correct.

[0029] A complex formation wellbore stability prediction system comprises:

[0030] A data acquisition module is configured to acquire actual formation data of a reservoir section of a drilled well.

[0031] A parameter calculation module is configured to calculate the formation pore pressure and rock mechanical parameters according to the actual formation data.

[0032] The tectonic strain coefficient calculation module is configured to calculate a tectonic strain coefficient in the direction of the horizontal minimum principal stress and a tectonic strain coefficient in the direction of the horizontal maximum principal stress according to the formation pore pressure and the rock mechanics parameter profile;

[0033] The density calculation module is configured to take the additional density of the mud as an initial value, and take the tectonic strain coefficient in the direction of the horizontal minimum principal stress and the tectonic strain coefficient in the direction of the horizontal maximum principal stress as initial tectonic strain coefficients, obtain the initial pore fluid pressure, the horizontal minimum principal stress and the horizontal maximum principal stress of the formation based on the measured formation data, and obtain the equivalent density of the collapse pressure and the equivalent density of the fracture pressure of the drilled well according to the equivalent density calculation formula of the collapse pressure and the equivalent density calculation formula of the fracture pressure.

[0034] The prediction module is configured to compare the drilling mud density with the equivalent density of the collapse pressure and the equivalent density of the fracture pressure, and when the pressure corresponding to the drilling mud density is greater than the equivalent density of the collapse pressure and less than the equivalent density of the fracture pressure, the well wall is stable.

[0035] A computer device comprises a memory, a processor, and a computer program stored in the memory and executable on the processor, and the processor implements the steps of the complex formation wellbore stability prediction method when executing the computer program.

[0036] A computer readable storage medium stores a computer program, and the computer program implements the steps of the complex formation wellbore stability prediction method when executed by a processor.

[0037] Compared with the prior art, the present application has the following beneficial effects:

[0038] In the case of lack of downhole data of the engineering section, the present application obtains the pore pressure and the rock mechanics parameters of the formation by using the measured formation data of the reservoir section, and then obtains the data of the earth stress, accurately calculates the equivalent density of the collapse pressure and the equivalent density of the fracture pressure, and accurately predicts the wellbore stability of the complex formation by comparing the drilling mud density with the equivalent density of the collapse pressure and the equivalent density of the fracture pressure, without being affected by the lack of data of the engineering section.

[0039] Further, the calculation process is adjusted and optimized by taking the expansion rate, mud density, formation leakage, and formation fracture test as constraints, thereby improving the prediction accuracy. BRIEF DESCRIPTION OF DRAWINGS

[0040] Figure 1 The complex formation wellbore stability prediction flowchart of the present application;

[0041] Figure 2 The normal compaction trend line graph of a well of the present application;

[0042] Figure 3 Figure for calculating the collapse pressure profile and the fracture pressure profile of the complex formation in well A of the present application;

[0043] Figure 4 Figure for calculating the collapse pressure profile and the fracture pressure profile of the complex formation in well B of the present application;

[0044] Figure 5 Figure for the contrast well location map (wells A and B are drilled wells, and well C is a designed well) of the present application. DETAILED DESCRIPTION

[0045] The technical solutions in the embodiments of the present application will be clearly and completely described below with reference to the drawings in the embodiments of the present application. Obviously, the described embodiments are only part of the embodiments of the present application, rather than all the embodiments of the present application. Based on the embodiments in the present application, all other embodiments obtained by those skilled in the art without creative work fall within the scope of protection of the present application.

[0046] It should be noted that the words "front", "back", "left", "right", "up" and "down" used in the following description refer to the directions in the drawings, and the words "inner" and "outer" refer to the directions towards or away from the geometric center of a particular component.

[0047] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which the present application belongs. The terminology used in the description of the present application herein only for the purpose of describing the specific embodiments and is not intended to limit the present application. The term "and / or" as used herein includes any and all combinations of one or more of the associated listed items.

[0048] The complex formation wellbore stability prediction method described in the present application comprises the following processes:

[0049] S1, obtaining the measured formation data of the reservoir section of the drilled well.

[0050] S2, calculating the formation pore pressure and rock mechanics parameter profile according to the measured formation data;

[0051] S3, calculating the tectonic strain coefficient of the horizontal minimum principal stress direction and the tectonic strain coefficient of the horizontal maximum principal stress direction according to the formation pore pressure and rock mechanics parameter profile.

[0052] S4, taking the additional density of the mud as an initial value, and taking the horizontal minimum principal stress direction and the horizontal maximum principal stress direction as initial tectonic strain coefficients, obtaining the initial pore fluid pressure profile, the horizontal minimum principal stress profile and the horizontal maximum principal stress profile of the stratum based on the measured stratum data, and obtaining the collapse pressure equivalent density and the fracture pressure equivalent density of the drilled well according to the collapse pressure equivalent density calculation formula and the fracture pressure equivalent density calculation formula.

[0053] S5, when the pressure corresponding to the drilling mud density is greater than the collapse pressure equivalent density and less than the fracture pressure equivalent density, the well wall is stable.

[0054] As Figure 1 shown, the complex stratum well wall stability prediction method comprises the following processes:

[0055] (1) Collecting geological data, logging data, drilling and completion reports of the research work area to determine the reservoir section and the non-reservoir section (engineering section).

[0056] (2) According to the drilled well information, collecting the measured stratum pore fluid pressure data and fracturing operation curve data of the drilled well reservoir section.

[0057] (3) According to the compaction theory, an accurate normal compaction trend line of multiple drilled wells is established by using the logging acoustic wave data, so as to obtain the normal compaction trend equation of the research work area (such as formula (1)). Combined with the measured stratum pore fluid pressure data of the drilled well reservoir section, the compaction index of the multiple well reservoir sections can be obtained based on the Eaton method theory (formula (2)), that is, the average stratum compaction index of the research work area can be obtained. Knowing the compaction index of the stratum, the stratum pore pressure can be calculated by using the Eaton method.

[0058] LN(AC) = -0.000149D + 4.7796 (1)

[0059] In the formula, AC is the acoustic time difference, us / ft; D is the depth, m.

[0060]

[0061] In the formula: P p is the stratum pore pressure, MPa; P0 is the overburden pressure, MPa; P w is the static column pressure of stratum water, MPa;△t is the measured acoustic wave time difference logging value, μs / ft;△t n is the acoustic time difference value on the normal compaction curve, μs / ft; C is the stratum compaction index, dimensionless.

[0062] (4) Based on geological data, core samples are taken from the strata of the engineering section, either from downhole or outcrop. Following the relevant provisions and requirements of SY / T5336—1996 "Routine Core Analysis Methods" and GB / T50266—99 "Standard for Engineering Rock Mass Testing Methods," the core samples are prepared into cylindrical rock specimens with a diameter of 2.5 cm and a height of 5.0 cm, with a sample quantity of 30-50 pieces. Simultaneously, rock physics and rock mechanics tests are performed on the core samples to obtain rock physics parameters such as acoustic velocity and density, as well as rock mechanics parameters such as uniaxial compressive strength, tensile strength, elastic modulus, Poisson's ratio, cohesion, and internal friction angle. Based on this, a rock mechanics parameter prediction model for the engineering section is constructed. Thus, based on the well logging data from the drilled wells, a rock mechanics parameter profile is obtained, including Biot coefficient, Poisson's ratio, and elastic modulus.

[0063] (5) Based on the fracturing operation curve of the reservoir section in the study area, the fracturing pressure value and closure pressure (horizontal minimum principal stress) during the fracturing process are obtained, and the maximum horizontal principal stress at the corresponding depth point is calculated according to equation (3). On this basis, based on the spring combination model (equation (4)), the structural strain coefficients in the direction of the horizontal minimum principal stress and the direction of the horizontal maximum principal stress of the reservoir section can be obtained. Given the structural strain coefficients along the direction of the horizontal minimum principal stress and the direction of the horizontal maximum principal stress, the magnitude of the formation stress can be calculated using the spring combination model.

[0064] P f =3σ H -σ h -αP P +S t (3)

[0065] In the formula: P f The burst pressure (MPa); σ H σ is the maximum horizontal principal stress (MPa); h The minimum principal stress is α (MPa); α is the Biot coefficient, dimensionless; P P Formation pore pressure (MPa); S t The tensile strength of the rock (MPa).

[0066]

[0067]

[0068]

[0069] In the formula: ν is the Poisson's ratio of the rock, dimensionless; E is the elastic modulus of the rock (MPa); ε H The strain coefficient ε is constructed for the direction of the maximum horizontal principal stress and is dimensionless. hStrain coefficient for the direction of the horizontal minimum principal stress, dimensionless; σ V Vertical ground stress (MPa); H0 is the depth of the starting point of the well logging (m); ρ0(h) is the density at the depth of h in the unlogged section (g / cm 3 ); g is the acceleration of gravity (m / s 3 ).

[0070] (6) Considering that there are many missing data in the engineering section, and simply using the reservoir compaction index may cause large errors, therefore, on the basis of the Eaton formula, the influence of mud additional pressure is considered, and a nonlinear equation (formula (5)) for calculating the formation pore pressure by Eaton method is constructed. The additional density of mud is taken as the initial value, and the strain coefficients in the directions of the horizontal minimum and maximum principal stresses are taken as the initial strain coefficients. Based on the logging data of the drilled well, the initial pore fluid pressure profile, the horizontal minimum principal stress profile and the horizontal maximum principal stress profile of the formation are obtained. According to the collapse pressure equivalent density calculation formula (6) and the fracture pressure equivalent density calculation formula (8), the equivalent density of the collapse pressure and the equivalent density of the fracture pressure of the drilled well can be obtained.

[0071]

[0072]

[0073]

[0074]

[0075] In the formula, K Z is an intermediate variable; is the internal friction angle; Δρ is the additional density (g / cm 3 ); ρ mc is the collapse pressure equivalent density (g / cm 3 ); ρ mf is the fracture pressure equivalent density (g / cm 3 ); H is the well depth (m); D is the depth, m.

[0076] (7) The formation collapse pressure and fracture pressure obtained according to step (6) do not match the actual situation of the formation, and need to be adjusted. On the basis of step (6), according to the formation pore pressure prediction range, hole enlargement rate, actual drilling mud density, and formation breakdown test data obtained from the logging data, well logging data, and drilling and completion reports of the drilled wells, these data are taken as constraint conditions to continuously adjust and optimize the additional density, the horizontal minimum principal stress direction structural strain coefficient, and the horizontal maximum principal stress direction structural strain coefficient, so that the equivalent density of the calculated formation collapse pressure and fracture pressure can meet the actual engineering conditions of the drilled wells (the hole enlargement rate is greater than 15%, which is considered as wellbore collapse, and the actual drilling mud density is less than the calculated collapse pressure equivalent density; the hole enlargement rate is less than 15%, which is considered as wellbore stability, and the actual drilling mud density is greater than the calculated collapse pressure equivalent density; the formation is not broken in the formation breakdown test, and the calculated fracture pressure equivalent density is greater than the pressure equivalent density in the formation breakdown test; the formation is broken in the formation breakdown test, and the calculated fracture pressure equivalent density is less than the pressure equivalent density in the formation breakdown test), so as to obtain the equivalent density of the formation collapse pressure and fracture pressure of the engineering section in the study area, and thus the reasonable mud density window of the engineering section is finally obtained. The flow chart is shown in FIG. 1. Figure 1

[0077] (8) After obtaining the collapse pressure equivalent density and fracture pressure equivalent density of the drilled wells according to step (7), the method is applied for prediction. In the process of drilling design, the mud density of the adjacent well is often used for interpolation to determine the mud density recommended value of different formation groups of the new well. According to this idea, the collapse pressure equivalent density of different formation groups of the well section of the calculated drilled wells is used for interpolation to obtain the collapse pressure equivalent density recommended value of the comparative well of the same formation group. If the actual mud density of the comparative well is greater than the recommended value, and the hole is regular, the prediction result is correct, and if the hole enlargement rate is greater than 15%, the prediction result is incorrect. If the actual mud density of the comparative well is less than the recommended value, and the hole is regular, the prediction result is incorrect, and if the hole enlargement rate is greater than 15%, the prediction result is correct.

[0078] (9) The drilling mud density is compared with the collapse pressure equivalent density and the fracture pressure equivalent density. When the pressure corresponding to the drilling mud density is greater than the collapse pressure equivalent density and less than the fracture pressure equivalent density, the wellbore is stable.

[0079] The pressure in the range greater than the collapse pressure equivalent density and less than the fracture pressure equivalent density is taken as the reasonable mud density window corresponding to the drilling.

[0080] The above process is introduced below by taking an actual well as an example.

[0081] (1) Collect the geological data, well logging data, logging data, and drilling and completion reports of the study area to determine the reservoir section and non-reservoir section (engineering section).​

[0082] (2) Based on the information of the drilled wells, collect data such as measured formation pore fluid pressure data and fracturing operation curves of the drilled reservoir sections;

[0083] (3) Based on compaction theory, accurate normal compaction trend lines for multiple drilled wells are established using well logging sonic data, such as... Figure 2 As shown, the normal compaction trend equation of the study area is obtained (as shown in Equation (1)). Combining the measured formation pore fluid pressure data of the drilled reservoir sections, and based on the Eaton method theory (Equation (2)), the compaction index of the reservoir sections of multiple wells can be obtained, and the average formation compaction index of the study area can be obtained, such as 1.42. Given the formation compaction index, the formation pore fluid pressure can be calculated using the Eaton method.

[0084] LN(AC)=-0.000149D+4.7796 (1)

[0085] In the formula, AC is the acoustic time difference, us / ft; D is the depth, m.

[0086]

[0087] Where: Pp is the formation pressure gradient, MPa; P0 is the overlying formation pressure, MPa; P w Δt represents the formation water hydrostatic pressure, MPa; Δt represents the measured sonic transit time log value, μs / ft; Δt n is the sonic transit time value on the normal compaction curve, in μs / ft; C is the formation compaction index, dimensionless.

[0088] (4) Based on geological data, core samples were taken from the strata of the engineering section, either from downhole or outcrop. Following the relevant provisions and requirements of SY / T5336—1996 "Routine Core Analysis Methods" and GB / T50266—99 "Standard for Engineering Rock Mass Testing Methods," the core samples were prepared into cylindrical rock specimens with a diameter of 2.5 cm and a height of 5.0 cm, with a sample quantity of 30-50 pieces. Simultaneously, rock physics and rock mechanics tests were performed on the core samples to obtain rock physics parameters such as acoustic velocity and density, as well as rock mechanics parameters such as uniaxial compressive strength, elastic modulus, Poisson's ratio, cohesion, and internal friction angle. Based on this, a rock mechanics parameter prediction model for the engineering section was constructed, as shown in Table 1. Thus, a rock mechanics parameter profile was obtained based on the well logging data from the drilled wells.

[0089] Table 1 Prediction Model of Formation Rock Mechanical Parameters

[0090] Parameter name Prediction model Elastic modulus E s = -164.69AC + 21605 Poisson's ratio μ s = 0.5855 exp(-0.012AC) Uniaxial compressive strength c = 22.173(304.8 / AC) - 21.645 ​ Cohesion C = 142.23e -0.023AC ]]> Tensile strength t = 5 x 10 -5 E d + 1.21]]> ​

[0091] (5) According to the fracturing operation curve of the reservoir section in the research area, the breakdown pressure value and the closure pressure (the horizontal minimum principal stress) in the fracturing process are obtained, and the maximum horizontal principal stress at the corresponding depth point is calculated according to formula (3). On this basis, based on the spring combination model (formula (4)), the horizontal minimum principal stress direction tectonic strain coefficient and the horizontal maximum principal stress direction tectonic strain coefficient of the reservoir section can be obtained, such as 0.0008705 and 0.003954. Knowing the tectonic strain coefficient along the horizontal minimum principal stress direction and the tectonic strain coefficient along the horizontal maximum principal stress direction, the formation stress size can be calculated by using the spring combination model.

[0092] P f = 3σ H - σ h - αP P + S t (3)

[0093] In the formula: P f is the breakdown pressure (MPa); σ H is the horizontal maximum principal stress (MPa); σ h is the horizontal minimum principal stress (MPa); α is the Biot coefficient, dimensionless; P P is the formation pore pressure (MPa); S t is the rock tensile strength (MPa).

[0094]

[0095]

[0096]

[0097] In the formula: v is the rock Poisson's ratio, dimensionless; E is the rock elastic modulus (MPa); ε H is the horizontal maximum principal stress direction tectonic strain coefficient, dimensionless; ε h is the horizontal minimum principal stress direction tectonic strain coefficient, dimensionless; σ V is the vertical ground stress (MPa); H0 is the logging starting point depth (m); ρ0(h) is the density at the depth h of the unlogged section (g / cm 3 ); g is the acceleration of gravity (m / s 3 ).

[0098] (6) Considering that there are many missing data in the engineering section, and simply using the reservoir section formation compaction index can easily cause large errors, therefore, on the basis of the Eaton formula, the influence of additional pressure is considered to construct the nonlinear equation of Eaton formula for calculating the formation pore fluid pressure (equation (5)). Taking the additional density zero as the initial value, and taking the horizontal minimum principal stress direction tectonic strain coefficient and the horizontal maximum principal stress direction tectonic strain coefficient as the initial tectonic strain coefficients, based on the logging data of the drilled well, the initial pore fluid pressure profile, the horizontal minimum principal stress profile and the horizontal maximum principal stress profile of the formation are obtained, and the equivalent density calculation formula (6) of the collapse pressure and the equivalent density calculation formula (8) of the fracture pressure can be used to obtain the collapse pressure profile and the fracture pressure profile of the drilled well.

[0099]

[0100]

[0101]

[0102]

[0103] In the formula, Δρ is the additional density (g / cm 3 ); ρ mc is the equivalent density of the collapse pressure (g / cm 3 ); ρ mf is the equivalent density of the fracture pressure (g / cm 3 ); H is the well depth (m); and D is the depth (m).

[0104] (7) The collapse pressure and the fracture pressure of the formation obtained according to step (6) do not conform to the actual situation of the formation, and need to be adjusted. On the basis of step (6), according to the drilling information, the logging data and the drilling and completion report of the drilled well, the formation pore pressure prediction range, the hole enlargement rate, the actual drilling mud density and the formation breaking test data of the formation are obtained, and these data are used as constraint conditions to continuously adjust and optimize the additional density, the horizontal minimum principal stress direction tectonic strain coefficient and the horizontal maximum principal stress direction tectonic strain coefficient, so that the calculated collapse pressure and fracture pressure profiles of the formation can meet the actual engineering conditions of the drilled well (the hole enlargement rate greater than 15% can be considered as well collapse, the actual drilling mud density less than the calculated equivalent density of the collapse pressure, and the hole enlargement rate less than 15% can be considered as well stability, the actual drilling mud density greater than the calculated equivalent density of the collapse pressure; the formation is not broken in the formation breaking test, and the calculated equivalent density of the fracture pressure is greater than the equivalent density of the pressure in the formation breaking test, and the formation is broken in the formation breaking test, and the calculated equivalent density of the fracture pressure is less than the equivalent density of the pressure in the formation breaking test), and the collapse pressure and fracture pressure profiles of the formation in the engineering section of the research area are obtained, so that the reasonable mud density window of the engineering section is finally obtained, and the flow chart is as follows:Figure 3 The collapse pressure profile and the fracture pressure obtained based on the method are shown in Figs. 4 and 5, respectively. Figures 3-4 As shown in the figures, the calculation results meet the engineering requirements and can ensure safe drilling of the well.

[0105] (8) After obtaining the collapse pressure profile and the fracture pressure profile of the drilled well according to step (7), the method is applied for prediction. In the process of well drilling design, the mud density of the adjacent well is often used for interpolation to determine the recommended value of the mud density of different formation groups of the new well. According to this idea, the equivalent density of the collapse pressure of the different formation groups of the well section of the calculated drilled well is used for interpolation to obtain the recommended value of the equivalent density of the collapse pressure of the comparative well of the same formation group. If the actual mud density of the comparative well is greater than the recommended value and the wellbore is regular, the prediction result is correct, and if the wellbore expansion rate is greater than 15%, the prediction result is incorrect. If the actual mud density of the comparative well is less than the recommended value and the wellbore is regular, the prediction result is incorrect, and if the wellbore expansion rate is greater than 15%, the prediction result is correct. The well location map of the comparative well is shown in Fig. 6. The evaluation table of the collapse pressure prediction effect of different wells in a certain block is shown in Table 2. As shown in the table, the prediction coincidence rate reaches 88%, which indicates the reliability of the prediction result. This also indicates the feasibility of the method. Figure 5

[0106] Table 2 Evaluation of collapse pressure prediction effect of a certain block

[0107]

[0108]

[0109] The following is an embodiment of the device of the present application, which can be used to execute the method embodiment of the present application. For details not mentioned in the device embodiment, please refer to the method embodiment of the present application.

[0110] In another embodiment of the present application, a complex formation wellbore stability prediction system is provided, which can be used to implement the complex formation wellbore stability prediction method. Specifically, the complex formation wellbore stability prediction system comprises a data acquisition module, a parameter calculation module, a construction strain coefficient calculation module, a density calculation module and a prediction module.

[0111] The data acquisition module is configured to acquire measured formation data of a drilled well reservoir section.

[0112] The parameter calculation module is configured to calculate formation pore pressure and rock mechanical parameters according to the measured formation data.

[0113] ​The tectonic strain coefficient calculation module is configured to calculate the tectonic strain coefficient in the direction of the horizontal minimum principal stress and the tectonic strain coefficient in the direction of the horizontal maximum principal stress according to the formation pore pressure and the rock mechanics parameter profile.

[0114] The density calculation module is configured to take the additional density of the mud as an initial value, and take the tectonic strain coefficient in the direction of the horizontal minimum principal stress and the tectonic strain coefficient in the direction of the horizontal maximum principal stress as initial tectonic strain coefficients, obtain the initial pore fluid pressure, the horizontal minimum principal stress and the horizontal maximum principal stress of the formation based on the measured formation data, and obtain the equivalent density of the collapse pressure and the equivalent density of the fracture pressure of the drilled well according to the equivalent density calculation formula of the collapse pressure and the equivalent density calculation formula of the fracture pressure.

[0115] The prediction module is configured to compare the drilling mud density with the equivalent density of the collapse pressure and the equivalent density of the fracture pressure, and when the pressure corresponding to the drilling mud density is greater than the equivalent density of the collapse pressure and less than the equivalent density of the fracture pressure, the well wall is stable.

[0116] In still another embodiment of the present application, a terminal device is provided, which comprises a processor and a memory, the memory being configured to store a computer program, the computer program comprising program instructions, and the processor being configured to execute the program instructions stored in the computer storage medium. The processor can be a central processing unit (CPU), and can also be other general-purpose processors, digital signal processors (DSP), application specific integrated circuits (ASIC), field-programmable gate arrays (FPGA) or other programmable logic devices, discrete gates or transistor logic, discrete hardware components, etc., which are the computing core and control core of the terminal, and are suitable for implementing one or more instructions, and are particularly suitable for loading and executing one or more instructions to implement a corresponding method flow or a corresponding function; the processor in the embodiments of the present application can be used for the operation of the complex formation wellbore stability prediction method, comprising: S1, obtaining the measured formation data of the drilled well reservoir section; S2, calculating the formation pore pressure and rock mechanics parameters according to the measured formation data; S3, calculating the tectonic strain coefficient of the horizontal minimum principal stress direction and the tectonic strain coefficient of the horizontal maximum principal stress direction according to the formation pore pressure and rock mechanics parameter profile; S4, taking the additional density of the mud as the initial value, and taking the tectonic strain coefficient of the horizontal minimum principal stress direction and the tectonic strain coefficient of the horizontal maximum principal stress direction as the initial tectonic strain coefficient, obtaining the initial pore fluid pressure, the horizontal minimum principal stress and the horizontal maximum principal stress of the formation based on the measured formation data, and obtaining the collapse pressure equivalent density and the fracture pressure equivalent density of the drilled well according to the collapse pressure equivalent density calculation formula and the fracture pressure equivalent density calculation formula; S5, comparing the drilling mud density with the collapse pressure equivalent density and the fracture pressure equivalent density, when the pressure corresponding to the drilling mud density is greater than the collapse pressure equivalent density and less than the fracture pressure equivalent density, the wellbore is stable.

[0117] In another embodiment, the present application also provides a computer readable storage medium (Memory), which is a memory device in the terminal equipment, for storing programs and data. It can be understood that the computer readable storage medium herein can include the built-in storage medium in the terminal equipment, and of course can also include the expansion storage medium supported by the terminal equipment. The computer readable storage medium provides a storage space, which stores the operating system of the terminal. Moreover, one or more instructions suitable for being loaded and executed by the processor are also stored in the storage space, and the instructions can be one or more computer programs (including program codes). It should be noted that the computer readable storage medium herein can be a high-speed RAM memory, or a non-volatile memory such as at least one disk memory.

[0118] The one or more instructions stored in the computer readable storage medium can be loaded and executed by the processor to implement the corresponding steps of the complex formation borehole stability prediction method in the above embodiments; the one or more instructions stored in the computer readable storage medium are loaded and executed by the processor to perform the following steps: S1, obtaining the measured formation data of the drilled well reservoir section; S2, calculating the formation pore pressure and rock mechanical parameters according to the measured formation data; S3, calculating the tectonic strain coefficient of the horizontal minimum principal stress direction and the tectonic strain coefficient of the horizontal maximum principal stress direction according to the formation pore pressure and rock mechanical parameter profile; S4, taking the additional density of the mud as the initial value, and taking the tectonic strain coefficient of the horizontal minimum principal stress direction and the tectonic strain coefficient of the horizontal maximum principal stress direction as the initial tectonic strain coefficient, obtaining the initial pore fluid pressure, the horizontal minimum principal stress and the horizontal maximum principal stress of the formation based on the measured formation data, and obtaining the collapse pressure equivalent density and the fracture pressure equivalent density of the drilled well according to the collapse pressure equivalent density calculation formula and the fracture pressure equivalent density calculation formula; S5, comparing the drilling mud density with the collapse pressure equivalent density and the fracture pressure equivalent density, and when the pressure corresponding to the drilling mud density is greater than the collapse pressure equivalent density and less than the fracture pressure equivalent density, the borehole wall is stable.

[0119] Those skilled in the art should understand that the embodiments of the present application can be provided as a method, a system, or a computer program product. Therefore, the present application can adopt a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Moreover, the present application can adopt the form of a computer program product implemented on one or more computer usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer usable program codes.

[0120] The computer program instructions can also be loaded onto a computer or other programmable data processing apparatus to cause a series of operational steps to be performed on the computer or other programmable apparatus to produce a computer-implemented process such that the instructions which execute on the computer or other programmable apparatus provide steps for implementing the functions specified in the flowchart block or blocks. Figure 1 one or more flow or blocks Figure 1 one or more flow or blocks

[0121] These computer program instructions can also be stored in a computer readable memory that can direct a computer or other programmable data processing apparatus to function in a particular manner, such that the instructions stored in the computer readable memory produce an article of manufacture including instructions which implement the function specified in the flowchart block or blocks. Figure 1 one or more flow or blocks Figure 1 one or more flow or blocks

[0122] The computer program instructions can also be loaded onto a computer or other programmable data processing apparatus to cause a series of operational steps to be performed on the computer or other programmable apparatus to produce a computer-implemented process such that the instructions which execute on the computer or other programmable apparatus provide steps for implementing the functions specified in the flowchart block or blocks. Figure 1 one or more flow or blocks Figure 1 one or more flow or blocks

[0123] It should be noted that, in the present document, the terms such as first and second, etc., are used only to distinguish one entity or operation from another, and do not necessarily require or imply these entities or operations to be in any such actual relationship or order. Moreover, the terms "comprising", "including" or any other variant thereof are intended to cover a non-exclusive inclusion, such that a process, method, article or apparatus that comprises a list of elements does not include only those elements but can also include other elements not expressly listed or inherent to such process, method, article or apparatus.

[0124] It is to be understood that the above description is intended to be illustrative, and not restrictive. Many embodiments and applications other than the examples provided would be apparent to those of skill in the art upon reading the above description. The scope of the technology should be determined, not with reference to the above description, but should instead be determined with reference to the appended claims, along with the full scope of equivalents to which such claims are entitled. The disclosures of all articles and references, including patent applications and publications, are incorporated by reference for all purposes. The omission in the foregoing description of any aspect of the subject matter disclosed herein is not a disclaimer of such subject matter, nor should it be regarded that the applicant has disclaimed any such subject matter, nor should any such omission be regarded as affecting the scope of the claimed teaching.

Claims

1. A method of predicting borehole stability in complex formations, comprising: The method comprises the following steps: S1, obtaining measured formation data of a reservoir section of a drilled well; S2, calculating formation pore pressure and rock mechanics parameters according to the measured formation data; S3, calculating the tectonic strain coefficient of the horizontal minimum principal stress direction and the tectonic strain coefficient of the horizontal maximum principal stress direction according to the formation pore pressure and rock mechanics parameter profile; The calculation process of the tectonic strain coefficient of the horizontal minimum principal stress direction and the tectonic strain coefficient of the horizontal maximum principal stress direction is as follows: wherein: P f is the fracture pressure; σ H is the horizontal maximum principal stress; σ h is the horizontal minimum principal stress; α is the Biot's coefficient; P P is the formation pore pressure; S t is the rock tensile strength; wherein: ν is the rock Poisson's ratio; E is the rock elastic modulus; ε H is the tectonic strain coefficient in the direction of the horizontal maximum principal stress; ε h is the tectonic strain coefficient in the direction of the horizontal minimum principal stress; σ V is the vertical in-situ stress; H 0 is the depth of the start of the well; ρ 0( h ) is the depth of the unlogged section h is the density of the point; g is the acceleration of gravity; S4, taking the additional density of the mud as the initial value, and taking the tectonic strain coefficient of the horizontal minimum principal stress direction and the tectonic strain coefficient of the horizontal maximum principal stress direction as the initial tectonic strain coefficients, obtaining the initial pore fluid pressure, the horizontal minimum principal stress and the horizontal maximum principal stress of the formation based on the measured formation data, and obtaining the collapse pressure equivalent density and the fracture pressure equivalent density of the drilled well according to the collapse pressure equivalent density calculation formula and the fracture pressure equivalent density calculation formula; S5, comparing the drilling mud density with the collapse pressure equivalent density and the fracture pressure equivalent density, and when the pressure corresponding to the drilling mud density is greater than the collapse pressure equivalent density and less than the fracture pressure equivalent density, the well wall is stable.

2. The complex formation borehole stability prediction method of claim 1, wherein, The formation pore pressure is as follows: where: P p Pp is the pore pressure of the formation; P P0 is the overburden pressure; P w Pw is the static fluid column pressure of the formation water; t Δt is the measured acoustic travel time log value; t n Δt0 is the acoustic travel time value on the normal compaction curve; C C is the compaction exponent of the formation.

3. The method for predicting the stability of a well wall in a complex formation according to claim 1, characterized by, The calculation process of the collapse pressure equivalent density and the fracture pressure equivalent density is as follows: where: Δ ρ is the additional density; ρ mc is the collapse pressure equivalent density; ρ mf is the fracture pressure equivalent density; σ H is the horizontal maximum principal stress; σ h is the horizontal minimum principal stress; C is the formation compaction exponent; P P is the formation pore pressure; S t is the rock tensile strength; α is the Biot's coefficient; H is the well depth; D is the depth.

4. The method for predicting the stability of a well wall in a complex formation according to claim 1, characterized by, After S4 is completed, the formation pore pressure prediction range, the hole enlargement rate, the actually drilled mud density and the breakdown test data of other drilled wells are obtained, and the above data are taken as constraint conditions to adjust and optimize the additional density, the tectonic strain coefficient of the horizontal minimum principal stress direction and the tectonic strain coefficient of the horizontal maximum principal stress direction.

5. The method for predicting the stability of a well wall in a complex formation according to claim 1, characterized by, The pressure range greater than the collapse pressure equivalent density and less than the fracture pressure equivalent density is taken as the recommended value of the corresponding mud density during drilling.

6. The method for predicting the stability of a well wall in a complex formation according to claim 1, characterized by, After S4 is completed, the collapse pressure equivalent density of the same formation group of the comparative well is obtained by interpolation using the collapse pressure equivalent densities of different formation groups of the well sections of a plurality of calculated drilled wells, if the actually used mud density of the comparative well is greater than the recommended value and the hole is regular, the prediction result is correct, if the hole enlargement rate is greater than 15%, the prediction result is incorrect, if the actually used mud density of the comparative well is less than the recommended value and the hole is regular, the prediction result is incorrect, if the hole enlargement rate is greater than 15%, the prediction result is correct.

7. A complex formation wellbore stability prediction system characterized by, The method comprises the following steps: The data acquisition module is configured to obtain measured formation data of a reservoir section of a drilled well; The parameter calculation module is configured to calculate formation pore pressure and rock mechanics parameters according to the measured formation data; The tectonic strain coefficient calculation module is configured to calculate the tectonic strain coefficient of the horizontal minimum principal stress direction and the tectonic strain coefficient of the horizontal maximum principal stress direction according to the formation pore pressure and rock mechanics parameter profile; The calculation process of the tectonic strain coefficient of the horizontal minimum principal stress direction and the tectonic strain coefficient of the horizontal maximum principal stress direction is as follows: where: P f is the fracture pressure; σ H is the horizontal maximum principal stress; σ h is the horizontal minimum principal stress; α is the Biot's coefficient; P P is the formation pore pressure; S t is the rock tensile strength; wherein: ν is the rock Poisson's ratio; E is the rock elastic modulus; ε H is the tectonic strain coefficient in the direction of the horizontal maximum principal stress; ε h is the tectonic strain coefficient in the direction of the horizontal minimum principal stress; σ V is the vertical in-situ stress; H 0 is the depth of the start of the well; ρ 0 h is the depth of the unlogged section; h is the density of the point; g is the acceleration of gravity; The density calculation module takes the additional density of the mud as an initial value, and takes the horizontal minimum principal stress direction and the horizontal maximum principal stress direction as initial tectonic strain coefficients; obtains initial pore fluid pressure, horizontal minimum principal stress and horizontal maximum principal stress of the stratum based on the measured stratum data; and obtains the collapse pressure equivalent density and the fracture pressure equivalent density of the drilled well according to the collapse pressure equivalent density calculation formula and the fracture pressure equivalent density calculation formula. The prediction module compares the drilling mud density with the collapse pressure equivalent density and the fracture pressure equivalent density; when the pressure corresponding to the drilling mud density is greater than the collapse pressure equivalent density and smaller than the fracture pressure equivalent density, the well wall is stable.

8. A computer device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, The processor executes the computer program to implement the steps of the complex stratum well wall stability prediction method according to any one of claims 1 to 6.

9. A computer-readable storage medium storing a computer program, the computer program comprising instructions that, when executed by a computer, cause the computer to perform the method of any one of claims 1 to 8. The computer program is executed by the processor to implement the steps of the complex stratum well wall stability prediction method according to any one of claims 1 to 6.

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