A production capacity prediction method and device for coupling wellbore parameters and wellbore trajectory

Abstract

The present invention relates to a production capacity prediction method and device for coupling wellbore parameters and wellbore trajectory. By conducting rock mineral component and physical property analysis experiments of core samples of highly deviated well reservoirs and logging the highly deviated well reservoirs, the error between the rock mineral component content, porosity and permeability calculated for the highly deviated well reservoirs and the rock mineral component content, porosity and permeability measured by the core samples is minimized as much as possible. By establishing a functional relationship between the open-flow rate of the highly deviated well and the relative value of the absolute value of the difference between the permeability, effective thickness, and the azimuth of the well inclination calculated by logging and the current maximum principal stress azimuth, the open-flow rate of the reservoir in the highly deviated well is calculated, thereby predicting the production capacity of the highly deviated well in the well to be drilled. The present invention avoids conducting a large number of core experiments, can effectively save costs, improve the benefits of exploration and development of fractured oil and gas reservoirs, and can accurately predict the production capacity of fractured reservoirs in highly deviated wells.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas exploration, and in particular to a method and device for predicting productivity by coupling wellbore parameters with wellbore trajectories. Background Art

[0002] For conventional oil and gas reservoirs without fractures in vertical wells, the production capacity prediction is mainly based on Darcy's law and Dupuit's formula, which is expressed as follows:

[0003]

[0004] Where: Q is the flow rate, unit is m 3 / s; π is pi, dimensionless; K is permeability, unit is mD; H e is the effective thickness, in m; P e is the boundary pressure, in Pa; P wf is the bottom hole pressure, in Pa; μ is the fluid viscosity, in mPa·s; R e is the effective supply radius, in m; R w is the borehole radius, in meters; S is the skin factor, dimensionless. From the above expression, we can see that the factors that affect the productivity of conventional oil and gas reservoirs without fractures in vertical wells are mainly: permeability, effective thickness, production pressure difference, effective oil supply radius and skin factor.

[0005] As oil and gas exploration and development continue to develop towards deep and ultra-deep layers, in terms of reservoir types, fractured reservoirs have gradually become the main force for increasing reserves and production; in terms of well types, in order to minimize operating costs and increase the drilling rate of oil and gas layers, special process wells such as highly deviated wells or horizontal wells have emerged one after another. The invasion profiles and seepage characteristics caused by the heterogeneity, anisotropy, and well deviation of highly deviated wells are different from those of conventional vertical wells. In addition, when fractured reservoirs are developed in highly deviated wells, the seepage law becomes more complicated due to the lateral and vertical communication of fractures, resulting in the factors affecting the production capacity of fractured reservoirs in highly deviated wells that are not completely limited to the factors described in the above expression, but are closely related to factors such as the well deviation azimuth of the highly deviated well and the direction of the current maximum principal stress, making the prediction of the production capacity of fractured reservoirs in highly deviated wells very difficult.

[0006] Since the operating costs of deep and ultra-deep layers are very high, accurate prediction of the production capacity of fractured reservoirs in highly deviated wells can not only significantly save operating costs, but also optimize well site deployment and the number of well sites, thereby improving economic benefits. Since there is no clear main controlling factor that restricts the production capacity of reservoirs in highly deviated wells (especially fractured reservoirs), the industry has not yet formed an effective production capacity prediction method for highly deviated wells. Therefore, for reservoirs in highly deviated wells (especially fractured reservoirs), a production capacity prediction method that couples wellbore parameters and wellbore trajectories is formed, which can accurately predict the production capacity of fractured reservoirs in highly deviated wells, thereby effectively improving the benefits of exploration and development of fractured oil and gas reservoirs. Summary of the invention

[0007] The purpose of the present invention is to provide a productivity prediction method and device for coupling wellbore parameters and wellbore trajectory, so as to solve the problem of difficulty in productivity prediction of fractured reservoirs in highly deviated wells in the prior art.

[0008] To achieve the above object, the present invention adopts the following technical solutions:

[0009] The present invention provides a production capacity prediction method for coupling wellbore parameters and wellbore trajectory, comprising:

[0010] The logging data of the highly deviated well reservoir is obtained by logging, and the rock mineral component content, porosity and permeability of the highly deviated well reservoir are calculated;

[0011] According to the logging data, the fracture parameters are obtained by interpreting the high-conductivity fractures, and the azimuth of the current maximum principal stress is obtained by interpreting the induced fractures;

[0012] According to the well logging data and fracture parameters, the sum of the thicknesses of all oil layers and gas layers in the reservoir of the highly deviated well is calculated to obtain the effective thickness of the highly deviated well;

[0013] Collecting well inclination data of the highly deviated well and calculating the well inclination azimuth of the highly deviated well;

[0014] According to the well inclination azimuth and the current maximum principal stress azimuth, the relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth is calculated;

[0015] Establish the functional relationship between the open flow rate of multiple highly deviated wells and the relative value of the permeability, effective thickness, and the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth calculated by logging, and obtain the productivity prediction formula of highly deviated wells;

[0016] Based on the productivity prediction formula of high-angle wells, the productivity of high-angle wells to be drilled is predicted by calculation.

[0017] Furthermore, the method also includes the step of pre-calibrating the rock mineral component content, porosity and permeability of the high-angle well reservoir: conducting rock mineral component and physical property analysis experiments on core samples to obtain the rock mineral component content, porosity and permeability of the core samples, so that the error between the rock mineral component content, porosity and permeability calculated for the high-angle well reservoir and the rock mineral component content, porosity and permeability measured for the core samples is as small as possible.

[0018] Furthermore, the logging data includes natural gamma, deep resistivity, shallow resistivity, volume density, neutron porosity, P-wave time difference, electrical imaging, array acoustic wave, and the logging data is measured by a logging instrument;

[0019] Among them, the rock mineral component content and porosity of the high-angle well reservoir are calculated based on natural gamma, deep resistivity, shallow resistivity, volume density, neutron porosity, and P-wave time difference in the logging data;

[0020] The permeability of the reservoir in the highly deviated wells is calculated based on array acoustic waves in the well logging data;

[0021] Fractures in highly deviated well reservoirs are delineated based on electrical imaging in well logging data.

[0022] Furthermore, the calculation method of the permeability of the reservoir in the highly deviated well includes: matching the main frequency and arrival time of the Stoneley wave contained in the array acoustic wave obtained based on the logging data, and constructing a calculation formula for the reservoir permeability in the highly deviated well using the least square method:

[0023] K = f(Δf, Δt);

[0024] Where: K is the permeability, Δf is the frequency shift of Stoneley wave, and Δt is the time lag of Stoneley wave.

[0025] Furthermore, the logging interpretation method includes: based on the electrical imaging data obtained from the logging data, dividing high-conductivity fractures and induced fractures in the high-angle well reservoir, and obtaining fracture parameters including fracture dip, fracture density, fracture porosity, and fracture width by interpreting the high-conductivity fractures; and by interpreting the induced fractures, obtaining the direction of the induced fractures, which is the current maximum principal stress azimuth.

[0026] Furthermore, the method for obtaining the effective thickness of a highly deviated well includes: integrating the deep resistivity obtained from well logging data, the difference between deep and shallow resistivities obtained from well logging data, the porosity obtained from well logging calculation, the permeability obtained from well logging calculation, the fracture density obtained from well logging interpretation, and the fracture porosity obtained from well logging interpretation, and referring to the gas logging display of the reservoir in the highly deviated well, finely dividing the oil layer, gas layer, water layer and dry layer in the highly deviated well, and according to the thickness of the oil layer, gas layer, water layer and dry layer in the highly deviated well, the sum of the thickness of all the oil layers and gas layers in the highly deviated well is calculated, which is the effective thickness of the highly deviated well.

[0027] Furthermore, the well inclination data of the highly deviated well, including sounding, vertical depth, well inclination angle, and azimuth, are used to calculate the wellbore trajectory of the highly deviated well based on the well inclination data, and a tangent to the wellbore trajectory is made in the target layer section where the reservoir of the highly deviated well is located, so that the angle between the tangent and the north direction is the well inclination azimuth of the highly deviated well in the target layer section.

[0028] Furthermore, the method for calculating the relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth includes: calculating the difference between the well inclination azimuth and the current maximum principal stress azimuth based on the obtained well inclination azimuth and the current maximum principal stress azimuth, taking the absolute value of the difference, dividing the absolute value by 90 degrees, and obtaining the relative value.

[0029] Furthermore, the productivity prediction method of multiple highly deviated wells in an oil and gas field includes: establishing a functional relationship between the open flow rate of the highly deviated well and the relative value of the permeability, effective thickness, and the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth calculated by logging:

[0030] Q=f(K,He,Az)=15.026e 0.004×K×He×Az ;

[0031] Where: Q is the unimpeded flow, K is the permeability, H e is the effective thickness, Az is the relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth;

[0032] In the selected oil and gas field, the relative values ​​of the permeability, effective thickness, and the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth calculated by logging of multiple highly deviated wells are obtained in turn. The open flow rate of the reservoir in each highly deviated well is calculated through a functional relationship, and the production capacity of the highly deviated well is predicted based on the open flow rate.

[0033] Based on the above-mentioned method for predicting the production capacity by coupling wellbore parameters and wellbore trajectory, the present invention also provides an analysis device for the method for predicting the production capacity by coupling wellbore parameters and wellbore trajectory of a highly deviated well, comprising a processor, wherein the processor is configured to execute the above-mentioned method for predicting the production capacity by coupling wellbore parameters and wellbore trajectory.

[0034] The present invention has the following beneficial effects due to the adoption of the above technical solution:

[0035] 1. The method of the present invention avoids carrying out a large number of core experiments, can effectively save costs, improve the benefits of exploration and development of fractured oil and gas reservoirs, and has strong economic efficiency;

[0036] 2. The method of the present invention can accurately predict the production capacity of fractured reservoirs in highly deviated wells, and provides a simple and practical new method while ensuring accurate prediction of the production capacity of fractured reservoirs in highly deviated wells. BRIEF DESCRIPTION OF THE DRAWINGS

[0037] By reading the detailed description of the preferred embodiment below, various other advantages and benefits will become clear to those of ordinary skill in the art. The accompanying drawings are only used to illustrate the purpose of the preferred embodiment and are not considered to be limitations of the present invention. In the entire drawings, the same reference numerals are used to represent the same components.

[0038] In the attached picture:

[0039] Figure 1 It is a schematic flow chart of a production capacity prediction method for coupling wellbore parameters and wellbore trajectory provided by an embodiment of the present invention;

[0040] Figure 2 It is an electrical imaging diagram of high-conductivity fractures in highly deviated well logging according to an embodiment of the present invention;

[0041] Figure 3 is a distribution diagram of the calculation results of the high conductivity fracture trend of the highly deviated well logging in an embodiment of the present invention;

[0042] Figure 4 It is an electrical imaging diagram of the induced fracture of the highly deviated well logging in the embodiment of the present invention;

[0043] Figure 5 is a distribution diagram of the calculation results of the current maximum principal stress direction of a highly deviated well in an embodiment of the present invention;

[0044] Figure 6 This is a result diagram of well logging evaluation of fractured reservoirs in Well A, a highly deviated well in the B gas field, in an embodiment of the present invention;

[0045] Figure 7 is a curve diagram of calculation results of wellbore trajectory and well inclination azimuth of a highly deviated well in an embodiment of the present invention;

[0046] Figure 8 It is a schematic diagram of a method of the wellbore inclination azimuth and the current maximum principal stress azimuth of a highly deviated well in an embodiment of the present invention;

[0047] Fig. 9 It is a schematic diagram of a method of the wellbore inclination azimuth and the current maximum principal stress azimuth of a highly deviated well in an embodiment of the present invention;

[0048] Fig.10 is a curve diagram showing the relationship between the permeability, effective thickness, relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth, and the open flow rate of the B gas field model well in the embodiment of the present invention;

[0049] Fig.11 It is a curve diagram showing the relationship between the permeability, effective thickness, relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth of the B gas field C well in the embodiment of the present invention and the open flow rate. DETAILED DESCRIPTION

[0050] The exemplary embodiments of the present invention will be described in more detail below with reference to the accompanying drawings. Although the exemplary embodiments of the present invention are shown in the accompanying drawings, it should be understood that the present invention can be implemented in various forms and should not be limited by the embodiments described herein. On the contrary, these embodiments are provided in order to enable a more thorough understanding of the present invention and to fully convey the scope of the present invention to those skilled in the art.

[0051] Since fractured reservoirs are currently developed in highly deviated wells, the horizontal and vertical communication of fractures makes the seepage law more complicated, resulting in the production capacity of fractured reservoirs in highly deviated wells being closely related to factors such as the well inclination azimuth of the highly deviated wells and the direction of the current maximum principal stress, making it very difficult to predict the production capacity of fractured reservoirs in highly deviated wells. Therefore, the present invention provides a production capacity prediction method and device for coupling wellbore parameters and wellbore trajectories, by conducting rock mineral composition and physical property analysis experiments of core samples of highly deviated well reservoirs, and logging the highly deviated well reservoirs, so that the errors of the rock mineral composition content, porosity and permeability calculated by the highly deviated well reservoirs and the rock mineral composition content, porosity and permeability measured by the core samples are minimized, and by establishing a functional relationship between the unimpeded flow of the highly deviated well and the relative values ​​of the absolute value of the difference between the permeability, effective thickness, well inclination azimuth and the current maximum principal stress azimuth calculated by logging, the unimpeded flow of the reservoir in the highly deviated well is calculated, thereby accurately predicting the production capacity of the highly deviated wells in the wells to be drilled.

[0052] The scheme of the present invention is described in detail below through examples.

[0053] Example

[0054] like Figure 1 As shown, the present invention provides a production capacity prediction method for coupling wellbore parameters and wellbore trajectory, comprising:

[0055] S1. Well logging obtains the well logging data of the highly deviated well reservoir, and calculates the rock mineral component content, porosity and permeability of the highly deviated well reservoir;

[0056] S2. Based on the logging data, the high-conductivity fractures are interpreted to obtain the fracture parameters, and the induced fractures are interpreted to obtain the current maximum principal stress azimuth;

[0057] S3. According to the well logging data and fracture parameters, the thickness of all oil layers and gas layers in the reservoir of the highly deviated well is calculated to obtain the effective thickness of the highly deviated well;

[0058] S4, collecting the well inclination data of the highly deviated well, and calculating the well inclination azimuth of the highly deviated well;

[0059] S5. According to the well inclination azimuth and the current maximum principal stress azimuth, a relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth is calculated;

[0060] S6. Establish a functional relationship between the open flow rate of multiple highly deviated wells and the relative value of the permeability, effective thickness, and the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth calculated by logging, and obtain a productivity prediction formula for highly deviated wells;

[0061] S7. Based on the productivity prediction formula of high-angle wells, the productivity of the high-angle wells to be drilled is predicted by calculation.

[0062] It should be noted that the above steps are not all necessary settings, nor are they limited to the above order, and can be set according to specific needs.

[0063] Specifically, step S1 also includes the step of pre-calibrating the rock mineral component content, porosity and permeability of the high-angle well reservoir: conducting rock mineral component and physical property analysis experiments on core samples to obtain the rock mineral component content, porosity and permeability of the core samples, so that the error between the rock mineral component content, porosity and permeability calculated for the high-angle well reservoir and the rock mineral component content, porosity and permeability measured for the core samples is as small as possible.

[0064] Among them, the logging data include natural gamma, deep resistivity, shallow resistivity, volume density, neutron porosity, P-wave time difference, electrical imaging, array acoustic wave, etc., and the logging data can be obtained by direct measurement through existing conventional logging instruments. On this basis, the rock mineral component content and porosity of the high-angle well reservoir are calculated based on the natural gamma, deep resistivity, shallow resistivity, volume density, neutron porosity, and P-wave time difference in the logging data; the permeability of the high-angle well reservoir is calculated based on the array acoustic wave in the logging data; the fractures of the high-angle well reservoir are divided based on the electrical imaging in the logging data.

[0065] Further, in step S2, the method for calculating the permeability of the reservoir in the highly deviated well includes: matching the main frequency and arrival time of the Stoneley wave contained in the array acoustic wave obtained based on the logging data, and constructing a calculation formula for the reservoir permeability in the highly deviated well using the least squares method:

[0066] K = f(Δf, Δt);

[0067] Where: K is the permeability, unit is mD; Δf is the frequency shift of Stoneley wave, unit is kHz; Δt is the time lag of Stoneley wave, unit is ms.

[0068] Further, in step S3, the logging interpretation method includes: based on the electrical imaging data obtained from the logging data, dividing high-conductivity fractures and induced fractures in the high-angle well reservoir, and obtaining fracture parameters including fracture inclination, fracture density, fracture porosity, and fracture width by interpreting the high-conductivity fractures, and also obtaining the strike of the induced fractures, which is the current maximum principal stress azimuth, by interpreting the induced fractures.

[0069] Further, in step S4, the method for obtaining the effective thickness of the highly deviated well includes: integrating the deep resistivity obtained from the well logging data, the difference between the deep and shallow resistivities obtained from the well logging data, the porosity obtained from the well logging calculation, the permeability obtained from the well logging calculation, the fracture density obtained from the well logging interpretation, and the fracture porosity obtained from the well logging interpretation, and referring to the gas logging display of the reservoir in the highly deviated well, finely dividing the oil layer, gas layer, water layer and dry layer in the highly deviated well, and according to the thickness of the oil layer, gas layer, water layer and dry layer in the highly deviated well, the sum of the thickness of all the oil layers and gas layers in the highly deviated well is calculated, which is the effective thickness of the highly deviated well.

[0070] Furthermore, in step S5, the method for obtaining the well inclination azimuth of a highly deviated well includes: using well inclination data of the highly deviated well including sounding, vertical depth, well inclination angle, and azimuth angle, calculating the wellbore trajectory of the highly deviated well according to the well inclination data, and making a tangent to the wellbore trajectory in the target layer section where the reservoir of the highly deviated well is located, so that the angle between the tangent and the north direction is the well inclination azimuth of the highly deviated well in the target layer section.

[0071] Further, in step S6, the method for calculating the relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth includes: calculating the difference between the well inclination azimuth and the current maximum principal stress azimuth based on the obtained well inclination azimuth and the current maximum principal stress azimuth, taking the absolute value of the difference, dividing the absolute value by 90 degrees, and obtaining the relative value.

[0072] Further, in step S7, the productivity prediction method of multiple highly deviated wells in the oil and gas field includes: establishing a functional relationship between the open flow of the highly deviated well and the relative value of the permeability, effective thickness, and the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth calculated by logging:

[0073] Q=f(K,He,Az)=15.026e 0.004×K×He×Az ;

[0074] Where: Q is the unimpeded flow rate, unit is ×10 4 m 3 / d; K is permeability, unit is mD; H e is the effective thickness, in meters; Az is the relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth, dimensionless;

[0075] In the selected oil and gas field, steps S2-S6 are repeated to obtain the relative values ​​of the permeability, effective thickness, and the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth calculated by logging of multiple highly deviated wells in turn, and the open flow rate of the reservoir in each highly deviated well is calculated through a functional relationship, and the production capacity of the highly deviated well is predicted based on the open flow rate.

[0076] Based on the above-mentioned production capacity prediction method of coupling wellbore parameters and wellbore trajectory, the fractured reservoir in the highly deviated well of the B gas field is taken as an example, and the specific process of coupling the wellbore parameters and wellbore trajectory of the highly deviated well is described in detail in combination with the attached drawings:

[0077] 1) Based on the core samples at a certain depth in the fractured reservoir of the high-angle well of the B gas field, rock mineral composition and physical property analysis experiments of the core samples were carried out, so that the rock mineral component content, porosity and permeability of the core samples can be measured, as shown in Table 1.

[0078]

[0079]

[0080] Table 1 Rock mineral content, porosity and permeability of fractured reservoir core samples in the B gas field

[0081] 2) For the fractured reservoir in the highly deviated well of gas field B, the logging instrument can measure a series of logging data in the highly deviated well (natural gamma, deep resistivity, shallow resistivity, volume density, neutron porosity, P-wave time difference, electrical imaging, array acoustic wave, etc.); based on the logging data such as natural gamma, deep resistivity, shallow resistivity, volume density, neutron porosity, P-wave time difference, the rock mineral component content and porosity of the fractured reservoir in the highly deviated well can be calculated, and the error between the rock mineral component content and porosity calculated by logging and the rock mineral component content and porosity obtained by experimental measurement in step 1) can be minimized.

[0082] 3) Based on the Stoneley wave in the array acoustic wave of the fractured reservoir in a highly deviated well of the gas field collected in step 2), the main frequency and arrival time of the Stoneley wave are matched, and the calculation formula of the permeability of the fractured reservoir in the highly deviated well is constructed by the least square method:

[0083] K = f(Δf, Δt);

[0084] Where: K is the permeability, unit is mD; Δf is the frequency shift of Stoneley wave, unit is kHz; Δt is the time lag of Stoneley wave, unit is ms.

[0085] The error between the permeability calculated by logging and the permeability obtained by experimental measurement in step 1) should be minimized. The calculation results of the porosity and permeability of the fractured reservoirs in the four highly deviated wells in the B gas field are shown in Table 2.

[0086] hashtag Porosity Permeability / mD A1 6.00％ 1.34 A2 4.90％ 1.09 A3 5.70％ 1.58 A4 4.90％ 1.50

[0087] Table 2 Porosity and permeability of fractured reservoirs in four highly deviated wells in the B gas field

[0088] 4) Based on the electrical imaging logging data of the fractured reservoir in a high-angle well of the gas field collected in step 2), different types of fractures such as high-conductivity fractures and induced fractures can be classified. Further interpretation of high-conductivity fractures can obtain parameters such as fracture dip, fracture density, fracture porosity, and fracture width, see Figure 2 and Figure 3 ; Further explanation of the induced fracture can give the direction of the induced fracture, which is the azimuth of the current maximum principal stress, see Figure 4 and Figure 5 The calculation results of fracture parameters of fractured reservoirs in four highly deviated wells in the B gas field are shown in Table 3.

[0089]

[0090]

[0091] Table 3 Fracture parameters in four highly deviated wells in B gas field

[0092] 5) Based on the deep resistivity, deep-shallow resistivity difference, logging porosity, logging permeability, fracture density, and fracture porosity of the fractured reservoir in the highly deviated wells of the gas field, and referring to the gas logging display of the fractured reservoir in the highly deviated wells, the oil layer, gas layer, water layer, and dry layer of the fractured reservoir in a highly deviated well are finely divided. Based on the thickness of the oil layer, gas layer, water layer, and dry layer of the fractured reservoir in the highly deviated well, the sum of the thickness of all oil layers and gas layers in this well is calculated to obtain the effective thickness of this well. The calculation results of the effective thickness of the fractured reservoir in the four highly deviated wells of the B gas field are shown in Table 4.

[0093] hashtag Porosity Permeability / mD Effective thickness / m A1 6.00％ 1.34 285.20 A2 4.90％ 1.09 238.36 A3 5.70％ 1.58 302.10 A4 4.90％ 1.50 329.20

[0094] Table 4 Porosity, permeability and effective thickness of fractured reservoirs in four highly deviated wells in B gas field

[0095] The present invention can obtain the rock mineral component content, porosity, permeability, fracture dip, fracture density, fracture porosity, fracture width, effective thickness, etc. of the fracture reservoir in the high-angle well through processing and interpretation by software such as Geolog, GeoFrame, Forward, and Lead.

[0096] The wellbore parameters of the fractured reservoir in the highly deviated well A in the B gas field are shown in Figure 6 . The first track is the measured depth of the formation; the second track is the natural gamma, which indicates the lithological characteristics of the formation; the third track is the deep and shallow resistivity logging curves, which characterize the electrical characteristics of the formation; the fourth track is the volume density, neutron porosity and acoustic time difference, which reflect the physical characteristics of the formation; the fifth track is the fracture inclination; the sixth track is the fracture density; the seventh track is the porosity of the core analysis and the porosity calculated by the well logging; the eighth track is the permeability of the core analysis and the permeability calculated by the well logging; the ninth track is the rock mineral composition profile calculated by the well logging; the tenth track is the well logging interpretation conclusion; the eleventh track is the quartz content of the core analysis of the well logging interpretation conclusion and the quartz content calculated by the well logging; the twelfth track is the feldspar content of the core analysis of the well logging interpretation conclusion and the feldspar content calculated by the well logging; the thirteenth track is the mica content of the core analysis of the well logging interpretation conclusion and the mica content calculated by the well logging.

[0097] 6) Using the well inclination data of a highly deviated well in gas field B, including sounding depth, vertical depth, well inclination angle, azimuth, etc., the wellbore trajectory of the highly deviated well can be calculated; a tangent line of the wellbore trajectory is drawn in the target layer section where the fractured reservoir is located, and the angle between the tangent line and the true north direction is the well inclination azimuth of the highly deviated well in the target layer section, see Figure 7 The well inclination azimuths of the four highly deviated wells in the B gas field are shown in Table 5.

[0098]

[0099]

[0100] Table 5 Well inclination azimuth of four highly deviated wells in B gas field

[0101] 7) Take the absolute value of the difference between the wellbore inclination azimuth of the highly deviated well in step 6) and the current maximum principal stress azimuth in step 4), and then divide it by 90 degrees to obtain the relative value, see Figure 8 and Fig. 9 The relative values ​​of the absolute values ​​of the differences between the well inclination azimuths and the current maximum principal stress azimuths of the four highly deviated wells in the B gas field are shown in Table 6.

[0102]

[0103] Table 6 Relative values ​​of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth of the four highly deviated wells in the B gas field

[0104] 8) Repeat the above steps 2) to 7), so as to obtain the relative values ​​of the absolute value of the difference between the permeability, effective thickness, well inclination azimuth and the current maximum principal stress azimuth of the fractured reservoir in multiple highly deviated wells of the gas field, and establish the functional relationship between the open flow rate of these highly deviated wells and the relative values ​​of the absolute value of the difference between the permeability, effective thickness, well inclination azimuth and the current maximum principal stress azimuth, as shown in the following formula and Fig.10 :

[0105] Q=f(K,He,Az)=15.026e 0.004×K×He×Az ;

[0106] Where: Q is the unimpeded flow rate, unit is ×10 4 m 3 / d; K is permeability, unit is mD; H e is the effective thickness, in meters; Az is the relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth, dimensionless.

[0107] The permeability, effective thickness, relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth, and open flow rate of the four highly deviated wells in the B gas field are shown in Table 7.

[0108] hashtag Permeability / mD Effective thickness / m |Azimuth of well inclination-azimuth of current maximum principal stress|Relative value <![CDATA[Open flow rate / 10 4 m 3 / d]]> A1 1.34 285.20 0.59 30 A2 1.09 238.36 0.25 22 A3 1.58 302.10 0.89 80 A4 1.50 329.20 0.94 104

[0109] Table 7 Permeability, effective thickness, relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth, and open flow rate of the highly deviated wells in the B gas field

[0110] 9) Using the permeability calculated in step 3), the effective thickness calculated in step 5), the relative value of the absolute value of the difference between the well inclination azimuth calculated in step 7) and the current maximum principal stress azimuth, the open flow rate of the fractured reservoir in the newly drilled high-angle well can be calculated based on the functional relationship in step 8), so as to predict the production capacity of the fractured reservoir in the newly drilled high-angle well, see Fig.11 .

[0111] The permeability, effective thickness, relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth, and predicted open-flow rate of the newly drilled high-angle wells in the B gas field are shown in Table 8.

[0112] hashtag Permeability / mD Effective thickness / m |Azimuth of well inclination-azimuth of current maximum principal stress|Relative value <![CDATA[Predicted unobstructed flow rate / 10 4 m 3 / d]]> C 1.73 234.00 0.65 47

[0113] Table 8 Predicted open flow rate of high-angle well C in B gas field

[0114] The predicted open flow rate of the newly drilled high-angle well C is 42.84×10 4 m 3 / d, the actual unimpeded flow rate is 47.00×10 4 m 3 / d, the absolute error is 4.16×10 4 m 3 / d, the relative error is 9.71%.

[0115] Based on the above-mentioned method for predicting the production capacity by coupling wellbore parameters and wellbore trajectory, the present invention also provides an analysis device for the method for predicting the production capacity by coupling wellbore parameters and wellbore trajectory of a highly deviated well, comprising a processor, wherein the processor is configured to execute the above-mentioned method for predicting the production capacity by coupling wellbore parameters and wellbore trajectory.

[0116] The present invention is described in terms of flowcharts and / or block diagrams of methods, devices (systems), and computer program products according to specific embodiments. It should be understood that each process and / or block in the flowchart and / or block diagram, as well as the combination of processes and / or blocks 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.

[0117] 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.

[0118] 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.

[0119] The present invention conducts rock mineral composition and physical property analysis experiments on core samples of highly deviated well reservoirs and performs well logging on highly deviated well reservoirs, so that the errors between the rock mineral composition content, porosity and permeability calculated for the highly deviated well reservoirs and the rock mineral composition content, porosity and permeability measured with core samples are minimized as much as possible. The present invention also establishes a functional relationship between the open-flow rate of the highly deviated well and the relative values ​​of the permeability, effective thickness, and the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth calculated by well logging, so as to calculate the open-flow rate of the reservoir in the highly deviated well, thereby accurately predicting the production capacity of the highly deviated well in the well to be drilled, avoiding the need to conduct a large number of core experiments, effectively saving costs, and improving the benefits of exploration and development of fractured oil and gas reservoirs, and having strong economic efficiency.

[0120] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, rather than to limit it. Although the present invention has been described in detail with reference to the aforementioned embodiments, those skilled in the art should understand that they can still modify the technical solutions described in the aforementioned embodiments, or make equivalent replacements for some of the technical features therein. However, these modifications or replacements do not deviate the essence of the corresponding technical solutions from the spirit and scope of the technical solutions of the embodiments of the present invention.

Claims

1. A production capacity prediction method for coupling wellbore parameters and wellbore trajectory, comprising: The logging data of the highly deviated well reservoir is obtained by logging, and the rock mineral component content, porosity and permeability of the highly deviated well reservoir are calculated; According to the logging data, the fracture parameters are obtained by interpreting the high-conductivity fractures, and the azimuth of the current maximum principal stress is obtained by interpreting the induced fractures; According to the well logging data and fracture parameters, the thickness of all oil layers and gas layers in the reservoir of the highly deviated well is calculated to obtain the effective thickness of the highly deviated well; Collecting well inclination data of the highly deviated well and calculating the well inclination azimuth of the highly deviated well; According to the well inclination azimuth and the current maximum principal stress azimuth, the relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth is calculated; Establish the functional relationship between the open flow rate of multiple highly deviated wells and the relative value of the permeability, effective thickness, and the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth calculated by logging, and obtain the productivity prediction formula of highly deviated wells; Based on the productivity prediction formula of high-angle wells, the productivity of high-angle wells to be drilled is predicted by calculation; The logging data include natural gamma, deep resistivity, shallow resistivity, volume density, neutron porosity, P-wave time difference, electrical imaging, array acoustic wave, and the logging data are measured by logging instruments; Among them, the rock mineral component content and porosity of the high-angle well reservoir are calculated based on natural gamma, deep resistivity, shallow resistivity, volume density, neutron porosity, and P-wave time difference in the logging data; The permeability of the reservoir in the highly deviated wells is calculated based on array acoustic waves in the well logging data; Fractures in highly deviated well reservoirs are delineated based on electrical imaging in well logging data; The calculation method of the permeability of the reservoir in the highly deviated well includes: matching the main frequency and arrival time of the Stoneley wave contained in the array acoustic wave obtained based on the logging data, and constructing the calculation formula of the reservoir permeability in the highly deviated well by the least square method: ； Where: K is the permeability, is the frequency shift of the Stoneley wave, for the time lag of the Stoneley wave; The productivity prediction method of multiple highly deviated wells in oil and gas fields includes: establishing a functional relationship between the open-flow rate of highly deviated wells and the relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth calculated by logging, effective thickness, and well inclination azimuth: ； Where: Q For unimpeded flow, K is the permeability, H e is the effective thickness, Az It is the relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth; In the selected oil and gas field, the relative values ​​of the absolute value of the difference between the permeability, effective thickness, well inclination azimuth and the current maximum principal stress azimuth calculated by logging of multiple highly deviated wells are obtained in turn, and the open flow rate of the reservoir in each highly deviated well is calculated through a functional relationship. The highly deviated well is predicted based on the open flow rate.

2. A production capacity prediction method for coupling wellbore parameters and wellbore trajectory according to claim 1, characterized in that: The method also includes the step of pre-calibrating the rock mineral component content, porosity and permeability of the high-angle well reservoir: conducting rock mineral component and physical property analysis experiments on core samples to obtain the rock mineral component content, porosity and permeability of the core samples, so that the error between the rock mineral component content, porosity and permeability calculated for the high-angle well reservoir and the rock mineral component content, porosity and permeability measured for the core samples is as small as possible.

3. A production capacity prediction method for coupling wellbore parameters and wellbore trajectory according to claim 1, characterized in that: The logging interpretation method includes: based on the electrical imaging data obtained from the logging data, dividing high-conductivity fractures and induced fractures in the high-angle well reservoir, and obtaining fracture parameters including fracture dip, fracture density, fracture porosity, and fracture width by interpreting the high-conductivity fractures. In addition, by interpreting the induced fractures, the direction of the induced fractures is obtained, which is the current maximum principal stress azimuth.

4. A production capacity prediction method for coupling wellbore parameters and wellbore trajectory according to claim 3, characterized in that: The method for obtaining the effective thickness of a highly deviated well includes: integrating the deep resistivity obtained from well logging data, the difference between deep and shallow resistivities obtained from well logging data, the porosity calculated from well logging, the permeability calculated from well logging, the fracture density obtained from well logging interpretation, the fracture porosity obtained from well logging interpretation, and referring to the gas logging display of the reservoir in the highly deviated well, finely dividing the oil layer, gas layer, water layer and dry layer in the highly deviated well, and according to the thickness of the oil layer, gas layer, water layer and dry layer in the highly deviated well, the sum of the thickness of all the oil layers and gas layers in the highly deviated well is calculated, which is the effective thickness of the highly deviated well.

5. A production capacity prediction method for coupling wellbore parameters and wellbore trajectory according to claim 1, characterized in that: The method for obtaining the well inclination azimuth of a highly deviated well includes: using well inclination data of the highly deviated well including sounding, vertical depth, well inclination angle, and azimuth angle, calculating the wellbore trajectory of the highly deviated well according to the well inclination data, and making a tangent to the wellbore trajectory in the target layer section where the reservoir of the highly deviated well is located, so that the angle between the tangent and the north direction is the well inclination azimuth of the highly deviated well in the target layer section.

6. A production capacity prediction method for coupling wellbore parameters and wellbore trajectory according to claim 1, characterized in that: The method for calculating the relative value of the absolute value of the difference between the well inclination azimuth and the current maximum principal stress azimuth includes: calculating the difference between the well inclination azimuth and the current maximum principal stress azimuth based on the obtained well inclination azimuth and the current maximum principal stress azimuth, taking the absolute value of the difference, dividing the absolute value by 90 degrees, and obtaining the relative value.

7. An analysis device for coupling the wellbore parameters of a highly deviated well with the wellbore trajectory productivity prediction method, comprising a processor, wherein the processor is configured to execute the method described in any one of claims 1-6.

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