Complex stratum borehole wall stability prediction method, system, equipment and medium

Abstract

The invention discloses a complex formation well wall stability prediction method, system and equipment and a medium. The method comprises the following steps: acquiring actually measured formation data of a drilled reservoir section; calculating formation pore pressure and rock mechanical parameters according to actually measured formation data; calculating the crustal stress according to the formation pore pressure and the rock mechanical parameter profile; taking the additional density zero of the slurry as an initial value, taking the tectonic strain coefficient in the horizontal minimum principal stress direction and the tectonic strain coefficient in the horizontal maximum principal stress direction as initial tectonic strain coefficients, and obtaining the initial pore fluid pressure, the horizontal minimum principal stress and the horizontal maximum principal stress of the stratum on the basis of actually measured stratum data; the collapse pressure equivalent density and the fracture pressure equivalent density of the drilled well can be obtained according to the collapse pressure equivalent density calculation formula and the fracture pressure equivalent density calculation formula; and when the pressure corresponding to the drilling mud density is larger than the collapse pressure equivalent density and smaller than the fracture pressure equivalent density, the well wall is stable.

Description

Technical Field

[0001] The present invention belongs to the field of oil and gas exploration and development, and relates to a method, system, equipment and medium for predicting wellbore stability in complex formations. Background Art

[0002] Wellbore stability refers to the ability of the wellbore to maintain its original stress state. Wellbore instability is caused by the destruction of its original balanced stress state during drilling and other processes, leading to wellbore collapse, diameter expansion, and block collapse. There are many methods to study wellbore stability. One is the study of the chemical composition of drilling fluid, which mainly studies the hydration expansion effect and physical and chemical properties caused by the clay mineral content in the mineral composition of the collapsed formation section; the second is rock mechanics research. This method does not consider the chemical influence of drilling fluid, and studies wellbore stability purely from the perspective of rock mechanics.

[0003] The oil and gas reservoir section is generally the focus of oil and gas field exploration and development work. During the exploration and development process, the downhole information obtained from the reservoir section is relatively complete, while for the engineering section, the downhole information obtained has limitations, such as incomplete logging data, lack of measured data on formation pore fluid pressure, etc. With the deepening of oil and gas exploration and development, deep oil and gas resources have received more and more attention. During the drilling process of deep formations, the engineering section lacks measured formation pressure data and ground stress test data, and often uses the data of the reservoir section, which will result in the inability to accurately calculate the collapse pressure and fracture pressure of deep complex formations, bringing challenges to fast and efficient drilling. Summary of the invention

[0004] The purpose of the present invention is to overcome the shortcomings of the above-mentioned prior art and provide a method, system, equipment and medium for predicting the stability of wellbore in complex formations, which can accurately calculate the collapse pressure and fracture pressure of deep complex formations and accurately predict the stability of wellbore in complex formations.

[0005] In order to achieve the above object, the present invention adopts the following technical solutions:

[0006] A method for predicting wellbore stability in complex formations includes the following processes:

[0007] S1, obtaining measured stratigraphic data of the drilled reservoir section;

[0008] S2, calculate the formation pore pressure and rock mechanical parameters based on the measured formation data;

[0009] S3, the structural strain coefficient in the direction of the minimum horizontal principal stress and the structural strain coefficient in the direction of the maximum horizontal principal stress are calculated based on the formation pore pressure and rock mechanical parameter profile;

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

[0011] 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.

[0012] Preferably, the formation pore pressure is:

[0013]

[0014] Where: P p is the formation pore pressure; P0 is the overlying formation pressure; P w is the hydrostatic column pressure of formation water; △t is the measured acoustic time difference logging value; △t n is the acoustic time difference value on the normal compaction curve; C is the formation compaction index.

[0015] Preferably, the calculation process of the structural strain coefficient in the direction of the horizontal minimum principal stress and the structural strain coefficient in the direction of the horizontal maximum principal stress is:

[0016] P f =3σ H -σ h -α P +S t

[0017] Where: P f is the rupture pressure; H is the maximum horizontal principal stress; σ h is the minimum horizontal principal stress; α is the Biot coefficient; P P is the formation pore pressure; S t is the tensile strength of rock;

[0018]

[0019]

[0020]

[0021] Where: ν is the Poisson's ratio of rock; E is the elastic modulus of rock; ε H is the strain coefficient in the direction of the maximum principal stress; ε hThe strain coefficient for the horizontal minimum principal stress direction; σ V is the vertical geostress; H0 is the depth of the logging starting point; ρ0(h) is the density at the depth h of the unmeasured well section; g is the gravitational acceleration.

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

[0023]

[0024]

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

[0026] Preferably, after S4 is completed, the predicted range of formation pore pressure, wellbore expansion rate, actual drilling mud density and ground breaking test data of other drilled wells are obtained, and the above data are used as constraints to adjust and optimize the additional density, the structural strain coefficient in the direction of the horizontal minimum principal stress and the structural strain coefficient in the direction of the horizontal maximum principal stress.

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

[0028] Preferably, after S4 is completed, the collapse pressure equivalent density of the well sections of different formations that have been drilled are interpolated using the calculated values ​​of multiple wells to obtain the recommended value of the collapse pressure equivalent density of the comparison wells in the same formation. If the actual mud density of the comparison wells in the same formation is greater than the recommended value and the wellbore is regular, the prediction result is correct; if the wellbore expansion rate is greater than 15%, the prediction result is wrong; if the actual mud density of the comparison wells is less than the recommended value and the wellbore is regular, the prediction result is wrong; if the wellbore expansion rate is greater than 15%, the prediction result is correct.

[0029] A complex formation wellbore stability prediction system, comprising:

[0030] A data acquisition module is used to obtain measured formation data of the drilled reservoir section;

[0031] Parameter calculation module, used to calculate the formation pore pressure and rock mechanics parameters based on measured formation data;

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

[0033] The density calculation module is used to take the additional density of the mud zero as the initial value, and the structural strain coefficient in the direction of the horizontal minimum principal stress and the structural strain coefficient in the direction of the horizontal maximum principal stress as the initial structural strain coefficient, and obtain the initial pore fluid pressure, horizontal minimum principal stress and horizontal maximum principal stress of the formation based on the measured formation data, and obtain the collapse pressure equivalent density and 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;

[0034] The prediction module is used to compare 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.

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

[0036] A computer-readable storage medium stores a computer program, which, when executed by a processor, implements the steps of the method for predicting wellbore stability in complex formations.

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

[0038] In the absence of downhole data in the engineering section, the present invention obtains the pore pressure and rock mechanical parameters of the formation by utilizing the measured formation data in the reservoir section, and then obtains the data of the ground stress, accurately calculates the collapse pressure equivalent density and the fracture pressure equivalent density, and accurately predicts the wellbore stability of complex formations by comparing the drilling mud density with the collapse pressure equivalent density and the fracture pressure equivalent density, without being affected by the lack of engineering section data.

[0039] Furthermore, the calculation process was adjusted and optimized based on multi-source information such as expansion rate, mud density, formation leakage, and ground failure test, which improved the prediction accuracy. BRIEF DESCRIPTION OF THE DRAWINGS

[0040] Figure 1 The flowchart of the wellbore stability prediction of complex formations of the present invention;

[0041] Figure 2 A normal compaction trend line diagram of a well of the present invention;

[0042] Figure 3 The calculation diagram of the collapse pressure profile and the fracture pressure profile of the complex formation in the A well of the present invention;

[0043] Figure 4 The collapse pressure profile and fracture pressure profile calculation diagram of the complex formation in Well B of the present invention;

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

[0045] The technical solutions in the embodiments of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, rather than all the embodiments; based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative work are within the scope of protection of the present invention.

[0046] It should be noted that the words "front", "rear", "left", "right", "up" and "down" used in the following description refer to directions in the drawings, and the words "inside" and "outside" refer to directions toward or away from the geometric center of a specific component, respectively.

[0047] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as those generally understood by those skilled in the art of the present invention. The terms used herein in the specification of the present invention are only for the purpose of describing specific embodiments and are not intended to limit the present invention. The term "and / or" used herein includes any and all combinations of one or more related listed items.

[0048] The method for predicting wellbore stability in complex formations according to the present invention comprises the following steps:

[0049] S1, obtain the measured stratigraphic data of the drilled reservoir section.

[0050] S2, the formation pore pressure and rock mechanical parameter profiles are calculated based on the measured formation data;

[0051] S3, the structural strain coefficient in the direction of the horizontal minimum principal stress and the structural strain coefficient in the direction of the horizontal maximum principal stress are calculated based on the formation pore pressure and rock mechanics parameter profile.

[0052] S4, taking the additional density of the mud zero as the initial value, and the structural strain coefficient in the direction of the horizontal minimum principal stress and the structural strain coefficient in the direction of the horizontal maximum principal stress as the initial structural strain coefficient, based on the measured formation data, 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 collapse pressure equivalent density and the fracture pressure equivalent density of the drilled well can be obtained according to the calculation formula of the collapse pressure equivalent density and the calculation formula of the fracture pressure equivalent density.

[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 wellbore is stable.

[0054] like Figure 1 As shown in FIG. 1 , the method for predicting wellbore stability in complex formations according to the present invention includes the following steps:

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

[0056] (2) Based on the information of the wells that have been drilled, collect the measured formation pore fluid pressure data, fracturing construction curves and other information of the drilled reservoir section.

[0057] (3) According to the compaction theory, the logging acoustic wave data is used to establish accurate normal compaction trend lines of multiple wells that have been drilled, so as to obtain the normal compaction trend equation of the study area (such as formula (1)). Combined with the measured formation pore fluid pressure data of the drilled reservoir section, based on the Eaton method theory (formula (2)), the compaction index of the reservoir section of multiple wells can be obtained, and the average formation compaction index of the study area can be obtained. If the compaction index of the formation is known, the formation pore pressure can be calculated using the Eaton method.

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

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

[0060]

[0061] Where: P p is the formation pore pressure, MPa; P0 is the overlying formation pressure, MPa; P w is the hydrostatic column pressure of formation water, MPa; △t is the measured acoustic time difference logging value, μs / ft; △t n is the acoustic time difference value on the normal compaction curve, μs / ft; C is the formation compaction index, dimensionless.

[0062] (4) According to geological data, downhole samples or outcrop samples are collected from the layers of the engineering section, and the core samples are made into cylindrical rock specimens with a diameter of 2.5 cm and a height of 5.0 cm in accordance with the relevant provisions and requirements of SY / T5336-1996 "Routine Analysis Methods for Cores" and GB / T50266-99 "Standards for Engineering Rock Test Methods", and 30-50 samples are prepared. Rock physics and rock mechanics tests are carried out on the cores simultaneously to obtain rock physics parameters such as acoustic wave 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, and then a rock mechanics parameter profile is obtained based on the logging data of the drilled wells, including Biot coefficient, rock Poisson's ratio, and rock elastic modulus.

[0063] (5) According to the fracturing construction curve of the reservoir section in the study area, the fracture pressure value and the closing 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 formula (3). On this basis, based on the spring combination model (formula (4)), the structural strain coefficient in the direction of the horizontal minimum principal stress and the structural strain coefficient in the direction of the horizontal maximum principal stress of the reservoir section can be obtained. Given the structural strain coefficient along the direction of the horizontal minimum principal stress and the structural strain coefficient along the direction of the horizontal maximum principal stress, the spring combination model can be used to calculate the magnitude of the formation stress.

[0064] P f =3σ H -σ h -αP P +S t (3)

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

[0066]

[0067]

[0068]

[0069] Where: ν is the Poisson's ratio of rock, dimensionless; E is the elastic modulus of rock (MPa); ε H is the structural strain coefficient in the direction of the maximum principal stress, dimensionless; ε his the structural strain coefficient in the horizontal minimum principal stress direction, dimensionless; σ V is the vertical geostress (MPa); H0 is the depth of the logging start point (m); ρ0(h) is the density of the unlogged section at a depth of h (g / cm 3 ); g is the acceleration due to gravity (m / s 3 ).

[0070] (6) Considering that there is a lack of data in the engineering section, it is easy to cause large errors if the reservoir section formation compaction index is used alone. Therefore, based on the calculation formula of the Eaton method, the influence of the additional pressure of the mud is considered, and the nonlinear equation for calculating the formation pore pressure by the Eaton method is constructed (Formula (5)). The additional density of the mud is zero as the initial value, and the structural strain coefficient in the direction of the horizontal minimum principal stress and the structural strain coefficient in the direction of the horizontal maximum principal stress are used as the initial structural strain coefficients. Based on the logging data of the drilled wells, 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 calculation formula (6) of the collapse pressure equivalent density and the calculation formula (8) of the fracture pressure equivalent density, the collapse pressure equivalent density and the fracture pressure equivalent density of the drilled formation can be obtained.

[0071]

[0072]

[0073]

[0074]

[0075] Where: 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 equivalent density of the burst pressure (g / cm 3 ), H is the well depth (m), and D is the depth, m.

[0076] (7) The formation collapse pressure and fracture pressure obtained according to step (6) do not match the actual formation conditions and need to be adjusted. On the basis of step (6), based on the well logging data, well logging data, and drilling and completion reports of the wells that have been drilled, obtain the formation pore pressure prediction range, wellbore expansion rate, actual drilling mud density, and ground breaking test data displayed by other well information. Using these data as constraints, continuously adjust and optimize the additional density, the structural strain coefficient in the direction of the minimum horizontal principal stress, and the structural strain coefficient in the direction of the maximum horizontal principal stress, so that the calculated formation collapse pressure and fracture pressure equivalent density meet the actual engineering conditions of the wells that have been drilled (wellbore expansion rate greater than 15% can be considered as wellbore collapse, The actual drilling mud density is less than the calculated collapse pressure equivalent density, and the wellbore expansion rate is less than 15%, which means the wellbore is stable, and the actual drilling mud density is greater than the calculated collapse pressure equivalent density; if the formation is not broken in the ground breaking test, the calculated fracture pressure equivalent density is greater than the pressure equivalent density during the ground breaking test, and if the formation is opened in the ground breaking test, the calculated fracture pressure equivalent density is less than the pressure equivalent density during the ground breaking test), the formation collapse pressure and fracture pressure equivalent density of the engineering section in the study area are obtained, and finally the reasonable mud density window of the engineering section is obtained. The flow chart is shown as follows: Figure 1 shown.

[0077] (8) After the collapse pressure equivalent density and fracture pressure equivalent density of the drilled well are obtained according to step (7), the method is used for prediction and application. In the process of drilling design, the mud density of adjacent wells is often used for interpolation to determine the recommended mud density values ​​of different formations of the new well. According to this idea, the collapse pressure equivalent density of different formations of the drilled wells calculated by multiple wells is interpolated to obtain the recommended collapse pressure equivalent density values ​​of the comparison wells of the same formation. If the actual mud density of the comparison wells of the same formation is greater than the recommended value and the wellbore is regular, the prediction result is correct, and the wellbore expansion rate is greater than 15%, the prediction result is wrong; if the actual mud density of the comparison well is less than the recommended value and the wellbore is regular, the prediction result is wrong, and the wellbore expansion rate is greater than 15%, the prediction result is correct.

[0078] (9) Compare 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.

[0079] The pressure range where the density is 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 drilling.

[0080] The following is an introduction to the above process using an actual well as an example:

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

[0082] (2) Based on the information of the wells that have been drilled, collect the measured formation pore fluid pressure data of the drilled reservoir section, fracturing construction curves and other information;

[0083] (3) Based on compaction theory, use the logging acoustic wave data to establish accurate normal compaction trend lines for multiple wells, such as Figure 2 As shown, the normal compaction trend equation of the study area is obtained (such as formula (1)). Combined with the measured formation pore fluid pressure data of the drilled reservoir section, based on the Eaton method theory (formula (2)), the compaction index of the reservoir section of multiple wells can be obtained, and the average formation compaction index of the study area can be obtained, such as 1.42. If the compaction index of the formation is known, the formation pore fluid pressure can be calculated using the Eaton method.

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

[0085] Where 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 is the hydrostatic column pressure of formation water, MPa; △t is the measured acoustic time difference logging value, μs / ft; △t n is the acoustic time difference value on the normal compaction curve, μs / ft; C is the formation compaction index, dimensionless.

[0088] (4) According to the geological data, the downhole samples or outcrop samples of the layers of the engineering section are cored, and the core samples are made into cylindrical rock specimens with a diameter of 2.5 cm and a height of 5.0 cm in accordance with the relevant provisions and requirements of SY / T5336-1996 "Routine Analysis Methods for Cores" and GB / T50266-99 "Standards for Engineering Rock Test Methods", and 30-50 samples are prepared. Rock physics and rock mechanics tests are carried out on the cores simultaneously to obtain rock physics parameters such as acoustic wave velocity and density of the cores, as well as rock mechanics parameters such as uniaxial compressive strength, elastic modulus, Poisson's ratio, cohesion, and internal friction angle, so as to construct a rock mechanics parameter prediction model for the engineering section, as shown in Table 1, so as to obtain the rock mechanics parameter profile based on the logging data of the drilled wells.

[0089] Table 1 Prediction model of formation rock mechanics parameters

[0090] Parameter name Prediction Model Elastic modulus <h2 style=";text-align:left;direction:ltr"><![CDATA[E <h2 style=";text-align:left;direction:ltr"> s <h2 style=";text-align:left;direction:ltr"> =-164.69AC+21605]]><h2 style=";text-align:left;direction:ltr"> Poisson's ratio <![CDATA[μ s =0.5855exp(-0.012AC)]]> Uniaxial compressive strength <![CDATA[σ c =22.173(304.8 / AC)-21.645]]> Cohesion <![CDATA[C=142.23e -0.023AC ]]> Tensile Strength <![CDATA[σ t =5×10 -5 AND d +1.21]]>

[0091] (5) According to the fracturing construction curve of the reservoir section in the study area, the fracture pressure value and the closing 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 formula (3). On this basis, based on the spring combination model (formula (4)), the structural strain coefficient in the horizontal minimum principal stress direction and the structural strain coefficient in the horizontal maximum principal stress direction of the reservoir section can be obtained, such as 0.0008705 and 0.003954. Knowing the structural strain coefficient along the horizontal minimum principal stress direction and the structural strain coefficient along the horizontal maximum principal stress direction, the spring combination model can be used to calculate the formation stress.

[0092] P f =3σ H -σ h -αP P +S t (3)

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

[0094]

[0095]

[0096]

[0097] Where: ν is the Poisson's ratio of rock, dimensionless; E is the elastic modulus of rock (MPa); ε H is the structural strain coefficient in the direction of the maximum principal stress, dimensionless; ε h is the structural strain coefficient in the horizontal minimum principal stress direction, dimensionless; σ V is the vertical geostress (MPa); H0 is the depth of the logging start point (m); ρ0(h) is the density of the unlogged section at a depth of h (g / cm 3 ); g is the acceleration due to gravity (m / s 3 ).

[0098] (6) Considering that there is a lack of data in the engineering section, it is easy to cause large errors if the reservoir section formation compaction index is used alone. Therefore, based on the calculation formula of the Eaton method, the influence of additional pressure is considered and the nonlinear equation (Equation (5)) for calculating the formation pore fluid pressure is constructed by the Eaton method. The additional density zero is taken as the initial value, and the structural strain coefficient in the direction of the horizontal minimum principal stress and the structural strain coefficient in the direction of the horizontal maximum principal stress are taken as the initial structural strain coefficients. Based on the logging data of the drilled wells, the initial pore fluid pressure profile, horizontal minimum principal stress profile and horizontal maximum principal stress profile of the formation are obtained. According to the calculation formula (6) of the collapse pressure equivalent density and the calculation formula (8) of the fracture pressure equivalent density, the collapse pressure profile and fracture pressure profile of the drilled formation can be obtained.

[0099]

[0100]

[0101]

[0102]

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

[0104] (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 well logging data, well logging data, and drilling and completion reports of the drilled wells, the formation pore pressure prediction range, wellbore expansion rate, actual drilling mud density, and ground breaking test data of the formation shown in the drilled information are obtained. These data are used as constraints to continuously adjust and optimize the additional density, the structural strain coefficient in the direction of the minimum horizontal principal stress, and the structural strain coefficient in the direction of the maximum horizontal principal stress, so that the calculated formation collapse pressure and fracture pressure profiles meet the actual engineering conditions of the drilled wells (wellbore expansion rate greater than 15% can be considered as wellbore wall collapse). , then the actual drilling mud density is less than the calculated collapse pressure equivalent density, and the wellbore expansion rate is less than 15%, which means the wellbore is considered stable, then the actual drilling mud density is greater than the calculated collapse pressure equivalent density; if the formation is not broken in the ground-breaking test, the calculated fracture pressure equivalent density is greater than the pressure equivalent density during the ground-breaking test, and if the formation is opened in the ground-breaking test, the calculated fracture pressure equivalent density is less than the pressure equivalent density during the ground-breaking test), the formation collapse pressure and fracture pressure profiles of the engineering section in the study area are obtained, and finally the reasonable mud density window of the engineering section is obtained. The flow chart is shown as follows Figure 3 The collapse pressure profile and fracture pressure obtained based on this method are shown in Figure 3-Figure 4 As shown in the figure, it can be seen that the calculation results meet the engineering needs and can ensure the safe drilling of the well.

[0105] (8) After obtaining the collapse pressure profile and fracture pressure profile of the drilled well according to step (7), the method is applied for prediction. In the process of drilling design, the mud density of adjacent wells is often used for interpolation to determine the recommended mud density values ​​for different formations of the new well. According to this idea, the collapse pressure equivalent density of different formations of the drilled wells calculated by multiple wells is interpolated to obtain the recommended collapse pressure equivalent density values ​​of the comparison wells of the same formation. If the actual mud density of the comparison wells of the same formation 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 wrong; if the actual mud density of the comparison well is less than the recommended value and the wellbore is regular, the prediction result is wrong, and if the wellbore expansion rate is greater than 15%, the prediction result is correct. The comparison well location map is as follows: Figure 5 The collapse pressure prediction effect evaluation table of different wells in a certain block is shown in Table 2. As can be seen from the table, the prediction coincidence rate reaches 88%, which shows the reliability of the prediction results. This also shows the feasibility of this method.

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

[0107]

[0108]

[0109] The following are device embodiments of the present invention, which can be used to perform method embodiments of the present invention. For details not disclosed in the device embodiments, please refer to the method embodiments of the present invention.

[0110] In another embodiment of the present invention, a complex formation wellbore stability prediction system is provided. The complex formation wellbore stability prediction system can be used to implement the above-mentioned complex formation wellbore stability prediction method. Specifically, the complex formation wellbore stability prediction system includes a data acquisition module, a parameter calculation module, a structural strain coefficient calculation module, a density calculation module and a prediction module.

[0111] Among them, the data acquisition module is used to obtain the measured formation data of the drilled reservoir section.

[0112] The parameter calculation module is used to calculate the formation pore pressure and rock mechanics parameters based on the measured formation data.

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

[0114] The density calculation module is used to take the additional density of the mud zero as the initial value, and the structural strain coefficient in the direction of the horizontal minimum principal stress and the structural strain coefficient in the direction of the horizontal maximum principal stress as the initial structural strain coefficient. Based on the measured formation data, the initial pore fluid pressure, horizontal minimum principal stress and horizontal maximum principal stress of the formation are obtained. According to the calculation formula of the collapse pressure equivalent density and the calculation formula of the fracture pressure equivalent density, the collapse pressure equivalent density and the fracture pressure equivalent density of the drilled well can be obtained.

[0115] The prediction module is used to compare 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.

[0116] In another embodiment of the present invention, a terminal device is provided, the terminal device includes a processor and a memory, the memory is used to store a computer program, the computer program includes program instructions, and the processor is used to execute the program instructions stored in the computer storage medium. The processor may be a central processing unit (CPU), or other general-purpose processors, digital signal processors (DSP), application specific integrated circuits (ASIC), field-programmable gate arrays (FPGAs), or other processors. GateArray, FPGA) or other programmable logic devices, discrete gate or transistor logic devices, discrete hardware components, etc., which are the computing core and control core of the terminal, which are suitable for implementing one or more instructions, and are specifically suitable for loading and executing one or more instructions to realize the corresponding method flow or corresponding function; the processor described in the embodiment of the present invention can be used for the operation of the method for predicting the stability of the wellbore in a complex formation, including: S1, obtaining the measured formation data of the drilled reservoir section; S2, calculating the formation pore pressure and rock mechanical parameters according to the measured formation data; S3, calculating the structural strain coefficient in the horizontal minimum principal stress direction and the horizontal minimum principal stress direction according to the formation pore pressure and rock mechanical parameter profile Structural strain coefficient in the direction of the largest principal stress; S4, taking the additional density of the mud as zero as the initial value, and the structural strain coefficient in the direction of the horizontal minimum principal stress and the structural strain coefficient in the direction of the horizontal maximum principal stress as the initial structural strain coefficient, based on the measured formation data, the initial pore fluid pressure, horizontal minimum principal stress and horizontal maximum principal stress of the formation are obtained, and the collapse pressure equivalent density and fracture pressure equivalent density of the drilled well can be obtained according to the calculation formula of the collapse pressure equivalent density and the calculation formula of the fracture pressure equivalent density; 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 invention further provides a computer-readable storage medium (Memory), which is a memory device in a terminal device for storing programs and data. It is understandable that the computer-readable storage medium here can include both the built-in storage medium in the terminal device and the extended storage medium supported by the terminal device. The computer-readable storage medium provides a storage space, which stores the operating system of the terminal. In addition, one or more instructions suitable for being loaded and executed by the processor are also stored in the storage space, and these instructions can be one or more computer programs (including program codes). It should be noted that the computer-readable storage medium here can be a high-speed RAM memory or a non-volatile memory, such as at least one disk memory.

[0118] The processor may load and execute one or more instructions stored in a computer-readable storage medium to implement the corresponding steps of the method for predicting wellbore stability in complex formations in the above-mentioned embodiment; one or more instructions in the computer-readable storage medium are loaded by the processor and the following steps are executed: S1, obtaining measured formation data of the drilled reservoir section; S2, calculating the formation pore pressure and rock mechanics parameters according to the measured formation data; S3, calculating the structural strain coefficient in the direction of the horizontal minimum principal stress and the structural strain coefficient in the direction of the horizontal maximum principal stress according to the formation pore pressure and rock mechanics parameter profile; S4, taking the additional density of the mud as zero is the initial value, and the structural strain coefficient in the direction of the horizontal minimum principal stress and the structural strain coefficient in the direction of the horizontal maximum principal stress are taken as the initial structural strain coefficients. Based on the measured formation data, the initial pore fluid pressure, the horizontal minimum principal stress and the horizontal maximum principal stress of the formation are obtained. According to the calculation formula of the collapse pressure equivalent density and the calculation formula of the fracture pressure equivalent density, the collapse pressure equivalent density and the fracture pressure equivalent density of the drilled well can be obtained; S5, 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.

[0119] Those skilled in the art will appreciate that the embodiments of the present application may be provided as methods, systems, or computer program products. Therefore, the present application may adopt the form of a complete hardware embodiment, a complete software embodiment, or an embodiment in combination with software and hardware. Moreover, the present application may adopt the form of a computer program product implemented in one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) that include computer-usable program code.

[0120] The present application is described with reference to the flowcharts and / or block diagrams of the methods, devices (systems), and computer program products according to the embodiments of the present application. It should be understood that each process and / or box in the flowchart and / or block diagram, as well as the combination of the processes and / or boxes in the flowchart and / or block diagram, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing device to generate a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the processes in the flowchart and / or block diagram. Figure 1 A process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0121] These computer program instructions may also be stored in a computer-readable memory capable of directing a computer or other programmable data processing device to operate in a specific manner, so that the instructions stored in the computer-readable memory produce an article of manufacture comprising an instruction device, which implements the process Figure 1 A process or multiple processes and / or boxes Figure 1 A function specified in one or more boxes.

[0122] These computer program instructions can also be loaded onto a computer or other programmable data processing device so that a series of operating steps are executed on the computer or other programmable device to produce a computer-implemented process, thereby providing instructions for implementing the process. Figure 1 A process or multiple processes and / or boxes Figure 1 The steps for the functions specified in one or more boxes.

[0123] It should be noted that, in this article, relational terms such as first and second, etc. are only used to distinguish one entity or operation from another entity or operation, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Moreover, the terms "include", "comprise" or any other variants thereof are intended to cover non-exclusive inclusion, so that a process, method, article or device including a series of elements includes not only those elements, but also other elements not explicitly listed, or also includes elements inherent to such process, method, article or device.

[0124] It should be understood that the above description is for illustration and not for limitation. Many embodiments and many applications beyond the examples provided will be apparent to those skilled in the art upon reading the above description. Therefore, the scope of the present teachings should not be determined with reference to the above description, but rather with reference to the foregoing claims and the full scope of equivalents to which such claims are entitled. For the purpose of comprehensiveness, all articles and references, including disclosures of patent applications and publications, are incorporated herein by reference. The omission of any aspect of the subject matter disclosed herein in the foregoing claims is not intended to be a waiver of such subject matter, nor should it be considered that the applicant has not considered such subject matter to be part of the disclosed inventive subject matter.

Claims

1. A method for predicting wellbore stability in complex formations, characterized in that: The process includes: S1, obtaining measured stratigraphic data of the drilled reservoir section; S2, calculate the formation pore pressure and rock mechanical parameters based on the measured formation data; S3, the structural strain coefficient in the direction of the minimum horizontal principal stress and the structural strain coefficient in the direction of the maximum horizontal principal stress are calculated based on the formation pore pressure and rock mechanical parameter profile; S4, taking the additional density of the mud as zero as the initial value, and the structural strain coefficient in the direction of the horizontal minimum principal stress and the structural strain coefficient in the direction of the horizontal maximum principal stress as the initial structural strain coefficient, based on the measured formation data, the initial pore fluid pressure, the horizontal minimum principal stress and the horizontal maximum principal stress of the formation are obtained, and the collapse pressure equivalent density and the fracture pressure equivalent density of the drilled well can be obtained according to the calculation formula of the collapse pressure equivalent density and the calculation formula of the fracture pressure equivalent density; 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.

2. The method for predicting wellbore stability in complex formations according to claim 1, characterized in that: The formation pore pressure is: Where: P p is the formation pore pressure; P0 is the overlying formation pressure; P w is the hydrostatic column pressure of formation water; △t is the measured acoustic time difference logging value; △t n is the acoustic time difference value on the normal compaction curve; C is the formation compaction index.

3. The method for predicting wellbore stability in complex formations according to claim 1, characterized in that: The calculation process of the structural strain coefficient in the direction of the horizontal minimum principal stress and the structural strain coefficient in the direction of the horizontal maximum principal stress is: P f =3σ H -s h -αP P +S t Where: P f is the rupture pressure; H is the maximum horizontal principal stress; σ h is the minimum horizontal principal stress; α is the Biot coefficient; P P is the formation pore pressure; S t is the tensile strength of rock; Where: ν is the Poisson's ratio of rock; E is the elastic modulus of rock; ε H is the strain coefficient in the direction of the maximum principal stress; ε h The strain coefficient for the horizontal minimum principal stress direction; σ V is the vertical geostress; H0 is the depth of the logging starting point; ρ0(h) is the density at the depth h of the unmeasured well section; g is the gravitational acceleration.

4. The method for predicting wellbore stability in complex formations according to claim 1, characterized in that: The calculation process of collapse pressure equivalent density and fracture pressure equivalent density is: Where: Δρ is the additional density; ρ mc is the collapse pressure equivalent density; ρ mf is the equivalent density of the rupture pressure; σ H is the maximum horizontal principal stress; σ h is the horizontal minimum principal stress; C is the formation compaction index; P P is the formation pore pressure; S t is the tensile strength of rock; α is the Biot coefficient; H is the well depth; D is the depth.

5. The method for predicting wellbore stability in complex formations according to claim 1, characterized in that: After S4 is completed, the predicted range of formation pore pressure, wellbore expansion rate, actual drilling mud density and ground breaking test data of other drilled wells are obtained. Using the above data as constraints, the additional density, structural strain coefficient in the direction of horizontal minimum principal stress and structural strain coefficient in the direction of horizontal maximum principal stress are adjusted and optimized.

6. The method for predicting wellbore stability in complex formations according to claim 1, characterized in that: The pressure in the range of 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.

7. The method for predicting wellbore stability in complex formations according to claim 1, characterized in that: After S4 is completed, the collapse pressure equivalent density of different formations in the drilled wells is interpolated to obtain the recommended value of the collapse pressure equivalent density of the comparison wells in the same formation. If the actual mud density of the comparison wells in the same formation is greater than the recommended value and the wellbore is regular, the prediction result is correct. If the wellbore expansion rate is greater than 15%, the prediction result is wrong. If the actual mud density used in the comparison well is less than the recommended value and the wellbore is regular, the prediction result is wrong. If the wellbore expansion rate is greater than 15%, the prediction result is correct.

8. A complex formation wellbore stability prediction system, characterized in that: include: A data acquisition module is used to obtain measured formation data of the drilled reservoir section; Parameter calculation module, used to calculate the formation pore pressure and rock mechanics parameters based on measured formation data; The structural strain coefficient calculation module is used to calculate the structural strain coefficient in the direction of the minimum horizontal principal stress and the structural strain coefficient in the direction of the maximum horizontal principal stress according to the formation pore pressure and rock mechanical parameter profile; The density calculation module is used to take the additional density of the mud zero as the initial value, and the structural strain coefficient in the direction of the horizontal minimum principal stress and the structural strain coefficient in the direction of the horizontal maximum principal stress as the initial structural strain coefficient, and obtain the initial pore fluid pressure, horizontal minimum principal stress and horizontal maximum principal stress of the formation based on the measured formation data, and obtain the collapse pressure equivalent density and 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 is used to compare 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.

9. A computer device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that: When the processor executes the computer program, the steps of the method for predicting wellbore stability in complex formations as described in any one of claims 1 to 7 are implemented.

10. A computer-readable storage medium storing a computer program, characterized in that: When the computer program is executed by a processor, the steps of the method for predicting wellbore stability in complex formations as described in any one of claims 1 to 7 are implemented.

Images