A porosity determination method, device, electronic equipment and storage medium
By establishing a geometric structure model and a three-dimensional numerical well test model for fractured-vuggy reservoirs, and combining bottom hole pressure simulation data with actual well logging data, the porosity of fractured-vuggy reservoirs can be accurately determined, solving the problem of difficulty in determining porosity during drilling.
Patent Information
- Authority / Receiving Office
- CN · China
- Patent Type
- Patents(China)
- Current Assignee / Owner
- CHINA PETROLEUM & CHEMICAL CORP
- Filing Date
- 2022-03-25
- Publication Date
- 2026-05-29
Smart Images
Figure CN116840910B_ABST
Abstract
Description
Technical Field
[0001] This invention belongs to the technical field of oil and gas field development, and specifically relates to a method, apparatus, electronic device and storage medium for determining porosity. Background Technology
[0002] In the development of oil and gas fields, it is necessary to obtain the oil and gas reserves. Porosity is an essential parameter for determining these reserves. There are generally two ways to obtain porosity: one is by analyzing collected core samples, and the other is by obtaining relevant parameters during drilling to determine the porosity of the target area. However, the latter method requires calibration based on the porosity results obtained from core analysis.
[0003] However, in actual operations, the presence of large fractures and cavities in the reservoir can lead to venting and leakage during drilling, making it impossible to obtain core and logging data, and thus difficult to determine the porosity of the target area. Summary of the Invention
[0004] To address the aforementioned technical problems, this invention proposes a method, apparatus, electronic device, and storage medium for determining porosity. This application establishes a geometric structure model of fractured-vuggy reservoirs using seismic data from the target area, then establishes a three-dimensional numerical well test model based on the geometric structure model, and finally determines the target porosity of the target area by comparing the bottom-hole pressure simulation data from the three-dimensional numerical well test model with actual well logging data, thus solving the problem of assigning porosity values to fractured-vuggy reservoirs.
[0005] To solve the above-mentioned technical problems, the technical solution adopted by the present invention includes four aspects.
[0006] In a first aspect, a method for determining porosity is provided, comprising: acquiring seismic data and actual well logging data of a target area; establishing a geometric structure model of a fractured-vuggy reservoir based on the seismic data; establishing a three-dimensional numerical well test model based on the geometric structure model and a corresponding fluid model; acquiring bottom hole pressure simulation data in the three-dimensional numerical well test model; and determining the target porosity of the target area based on the bottom hole pressure simulation data and the actual well logging data.
[0007] In some embodiments, the seismic data includes: multiple different seismic characterization data volumes; the step of establishing a geometric structure model of a fractured-vuggy reservoir based on the seismic data includes: determining different types of reservoirs based on multiple different seismic characterization data volumes; performing spatial fusion calculations on the different types of seismic characterization data volumes according to the priority of the reservoirs to obtain a single seismic characterization data volume that can simultaneously characterize multiple types of reservoirs; and establishing a geometric structure model of the fractured-vuggy reservoir based on the single seismic characterization data volume.
[0008] In some embodiments, the measured well data includes: interpreted porosity, wellbore venting length, leakage rate, and single-well production capacity; the step of establishing a three-dimensional numerical well test model based on the geometric structure model and the corresponding fluid model includes: determining a basic chart based on the inverted wave impedance and interpreted porosity after well-vibration calibration in the target area; completing the basic chart based on the wellbore venting length, leakage rate, and single-well production capacity to generate a comprehensive chart based on the inverted wave impedance and porosity; setting a preset porosity for the geometric structure model based on the comprehensive chart; setting a preset permeability for the geometric structure model based on the porosity-permeability relationship model; and establishing a three-dimensional numerical well test model based on the geometric structure model with the preset porosity and permeability and the corresponding fluid model.
[0009] In some embodiments, obtaining the bottom hole pressure simulation data in the three-dimensional numerical well test model includes: performing a simulated pressure recovery well test on the three-dimensional numerical well test model based on the working regime and test time to obtain data in the well test pressure recovery stage; and determining the bottom hole pressure difference simulation data based on the data in the well test pressure recovery stage.
[0010] In some embodiments, the measured well data includes: measured bottom hole pressure differential data; determining the target porosity of the fractured cavity based on the bottom hole pressure simulation data and the measured well data includes: determining a dimensionless simulation curve based on the bottom hole pressure differential simulation data; and determining a dimensionless measured curve based on the bottom hole pressure differential measurement data; fitting the dimensionless simulation curve and the dimensionless measured curve, and then determining the target porosity of the target region using the dimensionless simulation curve.
[0011] In some embodiments, determining the dimensionless simulation curve based on the bottom hole pressure difference simulation data includes: performing dimensionless processing on the bottom hole pressure difference simulation data to obtain dimensionless simulated pressure difference data; determining dimensionless simulated pressure difference derivative data based on the dimensionless simulated pressure difference data; and plotting a dimensionless simulated pressure difference curve and a dimensionless simulated pressure difference derivative curve based on the dimensionless simulated pressure difference data and the dimensionless simulated pressure difference derivative data. Determining the dimensionless measured curve based on the bottom hole pressure difference measured data includes: performing dimensionless processing on the bottom hole pressure difference measured data to obtain dimensionless measured pressure difference data; determining dimensionless measured pressure difference derivative data based on the dimensionless measured pressure difference data; and plotting a dimensionless measured pressure difference curve and a dimensionless measured pressure difference derivative curve based on the dimensionless measured pressure difference data and the dimensionless measured pressure difference derivative data.
[0012] In some embodiments, fitting the dimensionless simulated curve and the dimensionless measured curve, and then determining the target porosity of the target region using the dimensionless simulated curve, includes: fitting the dimensionless simulated pressure difference curve to the dimensionless measured pressure difference curve; fitting the dimensionless simulated pressure difference derivative curve to the dimensionless measured pressure difference derivative curve; during the fitting process, adjusting the preset porosity and preset permeability in the three-dimensional numerical well test model according to the dimensionless measured pressure difference derivative curve, so that the dimensionless simulated pressure difference curve coincides with the dimensionless measured curve and the dimensionless simulated pressure difference derivative curve coincides with the dimensionless measured pressure difference derivative curve; after the dimensionless simulated pressure difference curve coincides with the dimensionless measured curve and the dimensionless simulated pressure difference derivative curve coincides with the dimensionless measured pressure difference derivative curve, the adjusted preset porosity is the target porosity of the target region.
[0013] Secondly, this application provides a porosity determination device, comprising: a first acquisition module for acquiring seismic data and actual well logging data of a target area; a first establishment module for establishing a geometric structure model of a fractured-vuggy reservoir based on the seismic data; a second establishment module for establishing a three-dimensional numerical well test model based on the geometric structure model and a corresponding fluid model; a second acquisition module for acquiring bottom hole pressure simulation data in the three-dimensional numerical well test model; and a first determination module for determining the target porosity of the target area based on the bottom hole pressure simulation data and the actual well logging data.
[0014] A third aspect provides an electronic device including a storage device and a processor, the storage device storing a computer program, the processor executing the computer program to implement the steps of a logistics order tracking method.
[0015] The fourth aspect provides a storage medium storing a computer program that can be executed by one or more processors, the computer program being able to implement the steps of any of the logistics order tracking methods in the first aspect.
[0016] The beneficial effects of this invention are as follows: This application establishes a geometric structure model of fractured-vuggy reservoirs using seismic data of the target area, then establishes a three-dimensional numerical well test model based on the geometric structure model, and finally determines the target porosity of the target area by comparing the bottom hole pressure simulation data of the three-dimensional numerical well test model with the actual well logging data, thus solving the problem of assigning porosity values to fractured-vuggy reservoirs. Attached Figure Description
[0017] The scope of this disclosure can be better understood by reading the following detailed description of exemplary embodiments in conjunction with the accompanying drawings. The accompanying drawings are:
[0018] Figure 1 This is an overall flowchart of a porosity determination method provided in an embodiment of this application;
[0019] Figure 2 A schematic diagram of a fitted curve provided for an embodiment of this application;
[0020] Figure 3 This is a schematic block diagram of a porosity determination device provided in an embodiment of this application. Detailed Implementation
[0021] To make the objectives, technical solutions, and advantages of this application clearer, the application will be further described in detail below with reference to the accompanying drawings. The described embodiments should not be regarded as limitations on this application. All other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this application.
[0022] In the following description, references are made to “some embodiments,” which describe a subset of all possible embodiments. However, it is understood that “some embodiments” may be the same subset or different subsets of all possible embodiments and may be combined with each other without conflict.
[0023] If the application documents contain similar descriptions such as "first, second, third", the following explanation shall be added: In the following description, the terms "first, second, third" are used only to distinguish similar objects and do not represent a specific order of objects. It is understood that "first, second, third" may be interchanged in a specific order or sequence where permitted, so that the embodiments of this application described herein can be implemented in an order other than that illustrated or described herein.
[0024] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this application belongs. The terminology used herein is for the purpose of describing embodiments of this application only and is not intended to limit this application.
[0025] Example 1:
[0026] In view of the problems existing in the background technology, such as Figure 1 As shown, this application provides a method for determining porosity. This method is applied to electronic devices, such as servers, mobile terminals, computers, and cloud platforms. The functions implemented by the device data processing provided in this application embodiment can be achieved by the processor of the electronic device calling program code. The program code can be stored in a computer storage medium. The porosity determination method includes:
[0027] Step S1: Obtain seismic data and measured well data for the target area.
[0028] Step S2: Establish a geometric structure model of the fracture-vuggy reservoir based on the seismic data.
[0029] Step S3: Establish a three-dimensional numerical well test model based on the geometric structure model and the corresponding fluid model.
[0030] Step S4: Obtain the bottom hole pressure simulation data in the three-dimensional numerical well test model.
[0031] Step S5: Determine the target porosity of the target area based on the bottom hole pressure simulation data and the actual well data.
[0032] This application establishes a geometric structure model of fractured-vuggy reservoirs using seismic data of the target area, then establishes a three-dimensional numerical well test model based on the geometric structure model, and finally determines the target porosity of the target area by comparing the bottom hole pressure simulation data of the three-dimensional numerical well test model with the actual well logging data, thus solving the problem of assigning porosity values to fractured-vuggy reservoirs.
[0033] The seismic data mentioned in step S1 above includes multiple different seismic characterization data volumes. Each seismic characterization data volume corresponds to a seismic attribute, and different seismic attributes characterize different types of reservoirs. For example, the inverted wave impedance (IMP) of a seismic event is used to characterize cavernous reservoirs, the clutter attribute (CHAOTIC) of a seismic event is used to characterize pore-type reservoirs, and the coherence enhancement attribute (AFE) is used to characterize fracture-type reservoirs.
[0034] Furthermore, in some embodiments, step S2, "establishing a geometric structural model of a fractured-vuggy reservoir based on the seismic data," includes:
[0035] Step S21: Identify different types of reservoirs based on multiple different seismic characterization data volumes.
[0036] Step S22: Based on the priority of the reservoir, perform spatial fusion calculation on different types of seismic characterization data volumes to obtain a single seismic characterization data volume that can simultaneously characterize multiple types of reservoirs.
[0037] During the simulation, different types of reservoirs have different priorities. Therefore, multiple different seismic characterization data volumes are fused according to the reservoir type priority. During the fusion process, if two seismic characterization data volumes represent overlapping reservoirs, the data from the seismic characterization data volume with the higher priority for that reservoir type becomes dominant. Ultimately, multiple different types of seismic characterization data volumes are fused into a single seismic characterization data volume, which can simultaneously represent multiple types of reservoirs.
[0038] Step S23: Establish a geometric structure model of the fracture-vuggy reservoir based on the single seismic characterization data volume.
[0039] Finally, a geometric structure model including various types of reservoirs was established based on this single seismic characterization data volume.
[0040] The measured well data in step S1 includes: interpreted porosity, drilling venting length, leakage, single-well production capacity, and bottom hole pressure differential measured data.
[0041] After establishing the geometric model of the fractured-vuggy reservoir in step S2, the established geometric model needs to be converted into a three-dimensional numerical well test model. Therefore, in some embodiments, step S3, "establishing a three-dimensional numerical well test model based on the geometric model and the corresponding fluid model," includes:
[0042] Step S31: Determine the foundation plan based on the inverted wave impedance and interpreted porosity after well-seismic calibration of the target area.
[0043] Well-seismic calibration is a further step in determining the seismic data for the target area. After determining the seismic data for the target area, an inversion impedance-interpreted porosity cross plot is drawn based on the inverted impedance and interpreted porosity after well-seismic calibration. This plot serves as the base plot and is supplemented in subsequent operations.
[0044] Step S32: Based on the drilling venting length, leakage rate, and single-well fluid production capacity, complete the basic chart to generate a comprehensive chart based on inverted wave impedance and porosity.
[0045] Based on the drilling venting length, leakage rate, and single-well fluid production capacity, porosity predictions are used to supplement the data from missing core samples and surrounding exploration data. This transforms the basic chart into a comprehensive chart.
[0046] Step S33: Set a preset porosity for the geometric structure model based on the integrated drawing.
[0047] An initial porosity is preset for the geometric structure model based on the porosity in the comprehensive drawing.
[0048] Step S34: Set a preset permeability for the geometric structure model based on the pore permeability relationship model.
[0049] At the same time, an initial permeability is set for the geometric structure model based on the existing pore permeability relationship model.
[0050] Step S35: Establish a three-dimensional numerical well test model based on the geometric structure model with preset porosity and preset permeability and the corresponding fluid model.
[0051] In some embodiments, step S4, "obtaining the bottom hole pressure simulation data in the three-dimensional numerical well test model," includes:
[0052] Step S41: Perform a simulated pressure recovery test on the three-dimensional numerical well test model based on the working system and test time to obtain data on the well test pressure recovery stage.
[0053] Existing well logging procedures include pressure drop testing and pressure recovery testing. The pressure recovery phase data in this application are derived from the pressure recovery testing process. During pressure recovery testing, the pressure at the bottom of the well gradually recovers over time.
[0054] Step S42: Determine the bottom hole pressure difference simulation data based on the data from the well test pressure recovery phase.
[0055] During the pressure recovery test, the bottom hole pressure at the time of shut-in is first recorded. Then, the bottom hole pressure at different times is measured over time, and the pressure difference is calculated using the following formula:
[0056] ΔP=P0-P i (1)
[0057] Where ΔP is the pressure difference, MPa; p0 is the bottom hole pressure at the shut-in time, MPa; P i Let be the bottom hole pressure at a certain moment during pressure recovery, in MPa. This yields the simulated bottom hole pressure differential data.
[0058] In some embodiments, step S5, "determining the target porosity of the fracture based on the bottom hole pressure simulation data and the measured well data," includes:
[0059] Step S51: Determine the dimensionless simulation curve based on the bottom hole pressure difference simulation data.
[0060] In some embodiments, step S51, "determining the dimensionless simulation curve based on the bottom hole pressure differential simulation data," includes:
[0061] Step S511: Dimensionless processing is performed on the bottom hole pressure difference simulation data to obtain dimensionless simulated pressure difference data.
[0062] Step S512: Determine the dimensionless simulated pressure difference derivative data based on the dimensionless simulated pressure difference data.
[0063] Step S513: Plot the dimensionless simulated pressure difference curve and the dimensionless simulated pressure difference derivative curve based on the dimensionless simulated pressure difference data and the dimensionless simulated pressure difference derivative data.
[0064] Step S52: Determine the dimensionless measured curve based on the measured bottom hole pressure difference data.
[0065] In some embodiments, step S52, "and determining the dimensionless measured curve based on the measured bottom hole pressure difference data", includes:
[0066] Step S521: Dimensionless processing is performed on the measured bottom hole pressure difference data to obtain dimensionless measured pressure difference data.
[0067] Step S522: Determine the dimensionless measured pressure difference derivative data based on the dimensionless measured pressure difference data.
[0068] Step S523: Plot the dimensionless measured pressure difference curve and the dimensionless measured pressure difference derivative curve based on the dimensionless measured pressure difference data and the dimensionless measured pressure difference derivative data.
[0069] Step S53: Fit the dimensionless simulation curve and the dimensionless measured curve, and then determine the target porosity of the target region through the dimensionless simulation curve.
[0070] In some embodiments, step S53, "fitting the dimensionless simulation curve and the dimensionless measured curve, and then determining the target porosity of the target region using the dimensionless simulation curve," includes:
[0071] Step S531: Fit the dimensionless simulated pressure difference curve with the dimensionless measured pressure difference curve.
[0072] Step S532: Fit the dimensionless simulated differential pressure derivative curve with the dimensionless measured differential pressure derivative curve.
[0073] Step S533: During the fitting process, the preset porosity and preset permeability in the three-dimensional numerical well test model are adjusted according to the dimensionless measured differential pressure derivative curve, so that the dimensionless simulated differential pressure curve coincides with the dimensionless measured curve and the dimensionless simulated differential pressure derivative curve coincides with the dimensionless measured differential pressure derivative curve.
[0074] Step S534: After the dimensionless simulated pressure difference curve coincides with the dimensionless measured curve and the dimensionless simulated pressure difference derivative curve coincides with the dimensionless measured pressure difference derivative curve, the adjusted preset porosity becomes the target porosity of the target region.
[0075] This application adjusts the preset porosity of the established three-dimensional numerical well test model so that the dimensionless simulated pressure difference curve and the dimensionless simulated pressure difference derivative curve of the three-dimensional numerical well test model correspond to and overlap with the dimensionless measured pressure difference curve and the dimensionless measured pressure difference derivative curve. When the curves overlap pairwise, the adjusted preset porosity in the three-dimensional numerical well test model becomes the target porosity. This solves the problem of assigning porosity values to fractured-vuggy reservoirs.
[0076] Example 2:
[0077] In steps S51 and S52, when the simulated bottom hole pressure differential data is processed into dimensionless value using measured bottom hole pressure differential data, the formula used is:
[0078]
[0079]
[0080]
[0081] Among them, P D —Dimensionless pressure; t D —Dimensionless time; C D —Dimensionless wellbore storage coefficient; h—Effective reservoir thickness; ΔP—Pressure difference; q—Crude oil production; B—Crude oil volume coefficient; μ—Crude oil viscosity; K—Matrix permeability; t—Production time; —Porosity; C t —Comprehensive compressibility coefficient; μ—Crude oil viscosity; r w — Wellbore radius; C — Wellbore reservoir coefficient.
[0082] The dimensionless simulated pressure difference data and the dimensionless measured pressure difference data are obtained according to formula (3). Then, the dimensionless simulated pressure difference derivative data and the dimensionless measured pressure difference derivative data are obtained using formulas (3) and (4).
[0083] Finally, the dimensionless simulated pressure difference data, the dimensionless simulated pressure difference derivative data, the dimensionless measured pressure difference data, and the dimensionless measured pressure difference derivative data are simultaneously plotted on the first double logarithmic chart, so that the first double logarithmic chart forms the dimensionless simulated pressure difference curve, the dimensionless simulated pressure difference derivative curve, the dimensionless measured pressure difference curve, and the dimensionless measured pressure difference derivative curve.
[0084] Example 3:
[0085] In step S53, when fitting the dimensionless simulated curve and the dimensionless measured curve, the preset porosity in the three-dimensional numerical well test model is adjusted according to the fitting and parameter adjustment principles of the pressure and pressure derivative curves of fractured-vuggy reservoirs obtained from numerical well testing forward modeling. This ensures that the dimensionless simulated pressure difference curve and the dimensionless measured pressure difference curve coincide, and simultaneously, that the dimensionless simulated pressure difference derivative curve and the dimensionless measured pressure difference derivative curve coincide. The first double logarithmic chart after the curves coincide is shown below. Figure 2 As shown.
[0086] In actual well logging, the presence of fractures and vulnerabilities affects the obtained dimensionless differential pressure derivative curve. Therefore, the principle for fitting and adjusting the pressure and pressure derivative curves of fractured and vulnerable reservoirs obtained from numerical well testing forward modeling refers to determining the fracture and vulnerabilities in the well test based on the dimensionless differential pressure derivative curve. Specifically, a straight line segment with a slope of 1 / 2 on the dimensionless differential pressure derivative curve indicates the presence of fractures with limited conductivity. A concave shape on the dimensionless differential pressure derivative curve indicates the presence of a cavernous reservoir. The porosity of the cavern affects the opening size at the concave point of the dimensionless differential pressure derivative curve, while the permeability of the cavern affects the degree of concavity. When two caverns of similar size and physical properties exist, only one concave point may appear on the dimensionless differential pressure derivative curve. When the storage space of the distant cavern is larger than that of the nearby cavern by a certain amount, two obvious depressions will appear on the dimensionless pressure differential derivative curve. The greater the porosity of the distant cavern, the more obvious its corresponding depression.
[0087] In this application, the distribution of fractures and vulcanization in the well test is determined based on the dimensionless measured differential pressure derivative curve. Then, the dimensionless simulated differential pressure derivative curve is adjusted to coincide with the dimensionless measured differential pressure derivative curve. At this point, it indicates that the situation of the three-dimensional numerical well test model is similar to the distribution of fractures and vulcanization in the actual reservoir. Therefore, the adjusted preset porosity in the three-dimensional numerical well test model can be equivalent to the target porosity.
[0088] Example 4:
[0089] In step S42, after obtaining the bottom hole simulated pressure differential data, the data is plotted on a second double logarithmic chart. When plotting the bottom hole simulated pressure differential data on the second double logarithmic chart, the data needs to be evenly distributed. Therefore, it is necessary to adjust the simulation time step corresponding to each simulated pressure differential in the bottom hole simulated pressure differential data to ensure that the simulation time step conforms to a logarithmic law. Therefore, the model for adjusting the simulation time step is as follows:
[0090] t i =1×10 a[0.025(i-1)] (2)
[0091] Where 'a' is a negative integer, and the smaller the value of 'a', the smaller the initial time step; 'i' is a one-dimensional array, taking positive integer values from 1 to n, and the value of 'n' determines the number of pressure values to be calculated and output; 'a' and 'i' together determine the size of each time step.
[0092] Therefore, this application fuses different seismic characterization data volumes from the seismic data of the target area to obtain a single seismic characterization data volume, and establishes a geometric structure model of fractured-vuggy reservoirs based on the single seismic characterization data volume. Then, based on the geometric structure model, preset porosity and preset permeability are set, and a three-dimensional numerical well test model is established in conjunction with the fluid model corresponding to the geometric structure model. Finally, by adjusting the preset porosity and preset permeability, the dimensionless simulation curve of the three-dimensional numerical well test model is made to coincide with the dimensionless measured curve of the actual well logging data. The final preset porosity, after adjustment, becomes the target porosity, solving the problem of assigning porosity values to fractured-vuggy reservoirs.
[0093] Example 5:
[0094] Based on the foregoing embodiments, this application provides a porosity determination device. The various modules and units included in the device can be implemented by a processor in a computer device; of course, they can also be implemented by specific logic circuits. In the implementation process, the processor can be a central processing unit (CPU), a microprocessor unit (MPU), a digital signal processor (DSP), or a field programmable gate array (FPGA), etc.
[0095] like Figure 3 As shown, the second aspect provides a porosity determination device, including: a first acquisition module 1, a first establishment module 2, a second establishment module 3, a second acquisition module 4, and a first determination module 5.
[0096] The first acquisition module 1 is used to acquire seismic data and measured well data for the target area. The first establishment module 2 is used to establish a geometric structure model of a fractured-vuggy reservoir based on the seismic data. The second establishment module 3 is used to establish a three-dimensional numerical well test model based on the geometric structure model and the corresponding fluid model. The second acquisition module 4 is used to acquire bottom hole pressure simulation data from the three-dimensional numerical well test model. The first determination module 5 is used to determine the target porosity of the target area based on the bottom hole pressure simulation data and the measured well data.
[0097] In some embodiments, the first establishment module 2 includes: a second determination module, a first execution module, and a third establishment module.
[0098] The second determination module is used to determine different types of reservoirs based on multiple different seismic characterization data volumes. The first execution module is used to perform spatial fusion calculations on the different types of seismic characterization data volumes according to the priority of the reservoirs, to obtain a single seismic characterization data volume that can simultaneously characterize multiple types of reservoirs. The third establishment module is used to establish a geometric structure model of fractured-vuggy reservoirs based on the single seismic characterization data volume.
[0099] In some embodiments, the second establishment module 3 includes: a third determination module, a second execution module, a first preset module, a second preset module, and a fourth establishment module.
[0100] The third determining module is used to determine the basic map based on the inverted wave impedance and interpreted porosity after well-vibration calibration of the target area. The second execution module is used to complete the basic map based on the drilling venting length, leakage rate, and single-well production capacity, generating a comprehensive map based on the inverted wave impedance and porosity. The first preset module is used to set a preset porosity for the geometric structure model based on the comprehensive map. The second preset module is used to set a preset permeability for the geometric structure model based on the porosity-permeability relationship model. The fourth establishing module is used to establish a three-dimensional numerical well test model based on the geometric structure model with preset porosity and preset permeability and the corresponding fluid model.
[0101] In some embodiments, the second acquisition module 4 includes a third acquisition module and a fourth determination module.
[0102] The third acquisition module is used to simulate pressure recovery testing on the three-dimensional numerical well test model based on the working system and test time to obtain data during the well test pressure recovery phase. The fourth determination module is used to determine the simulated bottom hole pressure difference data based on the data from the well test pressure recovery phase.
[0103] In some embodiments, the first determining module 5 includes a fifth determining module, a sixth determining module, and a seventh determining module.
[0104] The fifth determining module is used to determine a dimensionless simulation curve based on the bottom hole pressure difference simulation data. The sixth determining module is used to determine a dimensionless measured curve based on the bottom hole pressure difference measured data. The seventh determining module is used to fit the dimensionless simulation curve and the dimensionless measured curve, and then determine the target porosity of the target region using the dimensionless simulation curve after fitting.
[0105] In some embodiments, the fifth determining module includes: a third execution module, an eighth determining module, and a fourth execution module.
[0106] The third execution module is used to perform dimensionless processing on the bottom hole pressure difference simulation data to obtain dimensionless simulated pressure difference data. The eighth determination module is used to determine the dimensionless simulated pressure difference derivative data based on the dimensionless simulated pressure difference data. The fourth execution module is used to plot the dimensionless simulated pressure difference curve and the dimensionless simulated pressure difference derivative curve based on the dimensionless simulated pressure difference data and the dimensionless simulated pressure difference derivative data.
[0107] In some embodiments, the sixth determining module includes: a fifth execution module, a ninth determining module, and a sixth execution module.
[0108] The fifth execution module is used to perform dimensionless processing on the measured bottom hole pressure difference data to obtain dimensionless measured pressure difference data. The ninth determination module is used to determine the dimensionless measured pressure difference derivative data based on the dimensionless measured pressure difference data. The sixth execution module is used to plot the dimensionless measured pressure difference curve and the dimensionless measured pressure difference derivative curve based on the dimensionless measured pressure difference data and the dimensionless measured pressure difference derivative data.
[0109] In some embodiments, the seventh determining module includes: a seventh execution module, an eighth execution module, a ninth execution module, and a tenth determining module.
[0110] The seventh execution module is used to fit the dimensionless simulated pressure difference curve with the dimensionless measured pressure difference curve. The eighth execution module is used to fit the dimensionless simulated pressure difference derivative curve with the dimensionless measured pressure difference derivative curve. The ninth execution module is used to adjust the preset porosity and preset permeability in the three-dimensional numerical well test model according to the dimensionless measured pressure difference derivative curve during the fitting process, so that the dimensionless simulated pressure difference curve coincides with the dimensionless measured curve, and the dimensionless simulated pressure difference derivative curve coincides with the dimensionless measured pressure difference derivative curve. The tenth determination module is used to determine that after the dimensionless simulated pressure difference curve coincides with the dimensionless measured curve, and the dimensionless simulated pressure difference derivative curve coincides with the dimensionless measured pressure difference derivative curve, the adjusted preset porosity becomes the target porosity of the target region.
[0111] Therefore, this application fuses different individual seismic data volumes from the seismic data of the target area to obtain a single seismic characterization data volume, and establishes a geometric structure model of fractured-vuggy reservoirs based on the single seismic characterization data volume. Then, based on the geometric structure model, preset porosity and permeability are set, and a three-dimensional numerical well test model is established in conjunction with the fluid model corresponding to the geometric structure model. Finally, by adjusting the preset porosity and permeability, the dimensionless simulation curve of the three-dimensional numerical well test model is made to coincide with the dimensionless measured curve of the actual well logging data. The final preset porosity, after adjustment, becomes the target porosity, solving the problem of assigning porosity values to fractured-vuggy reservoirs.
[0112] The modules in the aforementioned porosity determination device can be implemented entirely or partially through software, hardware, or a combination thereof. These modules can be embedded in the processor of the device in hardware form or independently of it, or stored in the memory of the processing device in software form, so that the processor can call and execute the operations corresponding to each module. It should be noted that the module division in this embodiment is illustrative and only represents a logical functional division; in actual implementation, there may be other division methods.
[0113] Example 6:
[0114] The third aspect provides an electronic device including a storage device and a processor, the storage device storing a computer program, the processor executing the computer program to implement the steps of a porosity determination method.
[0115] Example 7:
[0116] The fourth aspect provides a storage medium storing a computer program that can be executed by one or more processors, the computer program being able to implement the steps of any of the porosity determination methods in the first aspect.
[0117] Those skilled in the art will understand that all or part of the processes in the methods of the above embodiments can be implemented by a computer program instructing related hardware. The computer program can be stored in a non-volatile computer-readable storage medium, and when executed, it can include the processes of the embodiments of the methods described above. Any references to memory, storage, databases, or other media used in the embodiments provided in this application can include at least one of non-volatile and volatile memory. Non-volatile memory can include read-only memory (ROM), magnetic tape, floppy disk, flash memory, or optical storage, etc. Volatile memory can include random access memory (RAM) or external cache memory. By way of illustration and not limitation, RAM can be in various forms, such as static random access memory (SRAM) or dynamic random access memory (DRAM), etc.
[0118] It should be understood that the phrase "one embodiment" or "an embodiment" throughout the specification means that a specific feature, structure, or characteristic related to the embodiment is included in at least one embodiment of this application. Therefore, "in one embodiment" or "in an embodiment" appearing throughout the specification does not necessarily refer to the same embodiment. Furthermore, these specific features, structures, or characteristics can be combined in any suitable manner in one or more embodiments. It should be understood that in the various embodiments of this application, the sequence numbers of the above-described processes do not imply a sequential order of execution; the execution order of each process should be determined by its function and internal logic, and should not constitute any limitation on the implementation process of the embodiments of this application. The sequence numbers of the above-described embodiments are merely descriptive and do not represent the superiority or inferiority of the embodiments.
[0119] It should be noted that, in this document, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. Unless otherwise specified, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes that element.
[0120] In the several embodiments provided in this application, it should be understood that the disclosed devices and methods can be implemented in other ways. The device embodiments described above are merely illustrative. For example, the division of units is only a logical functional division, and in actual implementation, there may be other division methods, such as: multiple units or components can be combined, or integrated into another system, or some features can be ignored or not executed. In addition, the coupling, direct coupling, or communication connection between the various components shown or discussed can be through some interfaces, and the indirect coupling or communication connection between devices or units can be electrical, mechanical, or other forms.
[0121] The units described above as separate components may or may not be physically separate. The components shown as units may or may not be physical units. They may be located in one place or distributed across multiple network units. Some or all of the units may be selected to achieve the purpose of this embodiment according to actual needs.
[0122] In addition, each functional unit in the various embodiments of this application can be integrated into one processing unit, or each unit can be a separate unit, or two or more units can be integrated into one unit; the integrated unit can be implemented in hardware or in the form of hardware plus software functional units.
[0123] Those skilled in the art will understand that all or part of the steps of the above method embodiments can be implemented by hardware related to program instructions. The aforementioned program can be stored in a computer-readable storage medium. When the program is executed, it performs the steps of the above method embodiments. The aforementioned storage medium includes various media that can store program code, such as mobile storage devices, read-only memory (ROM), magnetic disks, or optical disks.
[0124] Alternatively, if the integrated units described above are implemented as software functional modules and sold or used as independent products, they can also be stored in a computer-readable storage medium. Based on this understanding, the technical solutions of the embodiments of this application, or the parts that contribute to the prior art, can be embodied in the form of a software product. This computer software product is stored in a storage medium and includes several instructions to cause a controller to execute all or part of the methods described in the various embodiments of this application. The aforementioned storage medium includes various media capable of storing program code, such as mobile storage devices, ROMs, magnetic disks, or optical disks.
[0125] The above description is merely an embodiment of this application, but the scope of protection of this application is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the scope of the technology disclosed in this application should be included within the scope of protection of this application. Therefore, the scope of protection of this application should be determined by the scope of the claims.
Claims
1. A method for determining porosity, characterized in that, include: Acquire seismic data and measured well data for the target area; A geometric model of fractured-vuggy reservoirs was established based on the aforementioned seismic data; The seismic data includes: multiple different seismic characterization data volumes; the establishment of a geometric structural model of a fractured-vuggy reservoir based on the seismic data includes: Different types of reservoirs were identified based on multiple different seismic characterization data volumes; Based on the priority of the reservoir, different types of seismic characterization data volumes are spatially fused to obtain a single seismic characterization data volume that can simultaneously characterize multiple types of reservoirs. During the fusion process, when the reservoirs represented by two seismic characterization data volumes have overlapping parts, the data from the seismic characterization data volume with higher priority for the corresponding reservoir type shall prevail. A geometric structural model of fractured-vuggy reservoirs is established based on the single seismic characterization data volume. A three-dimensional numerical well test model is established based on the geometric structure model and the corresponding fluid model; Obtain the bottom hole pressure simulation data from the three-dimensional numerical well test model; The target porosity of the target area is determined based on the bottom hole pressure simulation data and the actual well measurement data.
2. The porosity determination method according to claim 1, characterized in that, The actual well logging data includes: interpreted porosity, drilling vent length, lost circulation, and single-well production capacity; the establishment of a three-dimensional numerical well test model based on the geometric structure model and the corresponding fluid model includes: The foundation plan is determined based on the inverted wave impedance and interpreted porosity after well seismic calibration of the target area. Based on the drilling venting length, leakage, and single-well fluid production capacity, the basic chart is completed to generate a comprehensive chart based on inverted wave impedance and porosity. Based on the comprehensive drawing, a preset porosity is set for the geometric structure model; A preset permeability is set for the geometric structure model based on the pore permeability relationship model; A three-dimensional numerical well test model is established based on the geometric structure model with preset porosity and preset permeability and the corresponding fluid model.
3. The porosity determination method according to claim 1, characterized in that, The acquisition of bottom hole pressure simulation data from the three-dimensional numerical well test model includes: The three-dimensional numerical well test model was simulated for pressure recovery testing based on the working system and testing time to obtain data on the well test pressure recovery stage; The simulated bottom hole pressure differential data are determined based on the data from the well test pressure recovery phase.
4. The porosity determination method according to claim 2, characterized in that, The measured well data includes: measured bottom hole pressure differential data; determining the target porosity of the fractured cavity based on the simulated bottom hole pressure data and the measured well data includes: The dimensionless simulation curve is determined based on the bottom hole pressure differential simulation data. And a dimensionless measured curve is determined based on the measured bottom hole pressure difference data; The dimensionless simulation curve and the dimensionless measured curve are fitted together, and the target porosity of the target region is determined by the dimensionless simulation curve after fitting.
5. The porosity determination method according to claim 4, characterized in that, The determination of the dimensionless simulation curve based on the bottom hole pressure difference simulation data includes: The bottom hole pressure difference simulation data is dimensionless to obtain dimensionless simulation pressure difference data; The dimensionless simulated pressure difference derivative data are determined based on the dimensionless simulated pressure difference data. Dimensionless simulated pressure difference curves and dimensionless simulated pressure difference derivative curves are plotted based on the dimensionless simulated pressure difference data and the dimensionless simulated pressure difference derivative data. The determination of the dimensionless measured curve based on the measured bottom hole pressure difference data includes: The measured bottom hole pressure difference data is dimensionless to obtain dimensionless measured pressure difference data; The dimensionless measured pressure difference derivative data are determined based on the dimensionless measured pressure difference data. Dimensionless measured pressure difference curves and dimensionless measured pressure difference derivative curves are plotted based on the dimensionless measured pressure difference data and the dimensionless measured pressure difference derivative data.
6. The porosity determination method according to claim 5, characterized in that, The step of fitting the dimensionless simulation curve and the dimensionless measured curve, and then determining the target porosity of the target region using the dimensionless simulation curve after fitting, includes: The dimensionless simulated pressure difference curve is fitted with the dimensionless measured pressure difference curve; The dimensionless simulated pressure difference derivative curve is fitted with the dimensionless measured pressure difference derivative curve; During the fitting process, the preset porosity and preset permeability in the three-dimensional numerical well test model are adjusted according to the dimensionless measured pressure difference derivative curve so that the dimensionless simulated pressure difference curve coincides with the dimensionless measured pressure difference curve, and the dimensionless simulated pressure difference derivative curve coincides with the dimensionless measured pressure difference derivative curve. After the dimensionless simulated pressure difference curve coincides with the dimensionless measured pressure difference curve, and the dimensionless simulated pressure difference derivative curve coincides with the dimensionless measured pressure difference derivative curve, the adjusted preset porosity becomes the target porosity of the target region.
7. A porosity determining device, characterized in that, include: The first acquisition module is used to acquire seismic data and measured well data of the target area; The first module is used to establish a geometric structure model of the fractured-vuggy reservoir based on the seismic data. The first establishment module includes: a second determination module, a first execution module, and a third establishment module; The second determination module is used to determine different types of reservoirs based on multiple different seismic characterization data volumes; The first execution module is used to perform spatial fusion calculation on different types of seismic characterization data volumes according to the priority of the reservoir, so as to obtain a single seismic characterization data volume that can simultaneously characterize multiple types of reservoirs. During the fusion process, when the reservoirs represented by two seismic characterization data volumes have overlapping parts, the data from the seismic characterization data volume with higher priority for the corresponding reservoir type shall prevail. The third module is used to establish a geometric structure model of a fractured-vuggy reservoir based on the single seismic characterization data volume. The second module is used to establish a three-dimensional numerical well test model based on the geometric structure model and the corresponding fluid model. The second acquisition module is used to acquire the bottom hole pressure simulation data in the three-dimensional numerical well test model; The first determining module is used to determine the target porosity of the target area based on the bottom hole pressure simulation data and the measured well data.
8. An electronic device, characterized in that, include: The device includes a memory and a processor, wherein the memory stores a computer program that, when executed by the processor, performs a porosity determination method as described in any one of claims 1 to 6.
9. A storage medium, characterized in that, The computer program stored in the storage medium can be executed by one or more processors, and the computer program can be used to implement the steps of the porosity determination method as described in any one of claims 1 to 6.