Method, apparatus, and storage medium for determining a pore fraction of a reservoir

Abstract

The embodiment of the application provides a method, device and storage medium for determining the porosity ratio of a reservoir, and belongs to the technical field of oil and gas development. The method comprises the following steps: obtaining a first relationship curve of bottom hole pressure and pump stopping time, a second relationship curve of bottom hole pressure drop and pump stopping time, a third relationship curve of bottom hole pressure drop derivative and pump stopping time, and a fourth relationship curve of bottom hole pressure and logarithm of pump stopping time; determining a first pump stopping time and a second pump stopping time according to the second relationship curve and / or the third relationship curve; obtaining a straight line segment slope of a straight line segment corresponding to the porosity based on the fourth relationship curve, and according to the first pump stopping time and the second pump stopping time; obtaining a permeability corresponding to the porosity according to the straight line segment slope of the straight line segment corresponding to the porosity; obtaining a bottom hole pressure drop based on the first relationship curve, and according to the first pump stopping time and the second pump stopping time; and determining the porosity ratio according to the permeability and the bottom hole pressure drop. The application can improve the accuracy of determining the porosity ratio of various pores in the reservoir.

Description

Technical Field

[0001] This invention relates to the field of oil and gas development technology, and more specifically to a method, apparatus, and storage medium for determining the porosity of a reservoir. Background Technology

[0002] During fracturing, in addition to retaining the original pore system, the reservoir also gains main fractures, branch fractures, and numerous fracturing-induced microfractures, forming a complex "pore-fracture coupling" network. In actual underground fracturing zones, various types of pores (natural + artificial, matrix + fracture) are highly interwoven and interconnected, resulting in extremely complex spatial distribution and fluid response. Current technologies typically rely on core experiments to quantify the actual porosity of various pore types. However, core samples are small pieces (usually a few centimeters) taken from the reservoir, while actual fracturing zones cover a vast area of ​​"kilometers." Since the proportions measured from small samples cannot represent the whole, current technologies struggle to accurately quantify the actual porosity of various pore types. Therefore, existing technologies suffer from insufficient precision in determining the proportion of different pore types in the reservoir. Summary of the Invention

[0003] The purpose of this application is to provide a method, apparatus, storage medium, and computer program product for determining the porosity of a reservoir, in order to solve the problem that the porosity of various types of pores in the reservoir is not accurate enough in the prior art.

[0004] To achieve the above objectives, a first aspect of this application provides a method for determining the porosity of a reservoir, the method comprising:

[0005] After stopping the pumping of fracturing fluid into the fracturing well in the reservoir, the first relationship curve between the bottom hole pressure and the pumping stop time in the fracturing well during the first preset time period is obtained. Based on the first relationship curve between bottom hole pressure and pump stop time within the first preset time period, determine the second relationship curve between bottom hole pressure drop and pump stop time within the first preset time period, the third relationship curve between the derivative of bottom hole pressure drop and pump stop time within the first preset time period, and the fourth relationship curve between bottom hole pressure and the logarithm of pump stop time within the first preset time period. Based on the second relationship curve and / or the third relationship curve, determine the first pump stop time and the second pump stop time corresponding to the pores of each pore size category in the reservoir, wherein the first pump stop time corresponds to the pump stop time when the pores begin to be affected by the bottom hole pressure, and the second pump stop time corresponds to the pump stop time when the adjacent pores of the pores that are not affected by the bottom hole pressure begin to be affected by the bottom hole pressure. Based on the fourth relationship curve, the slope of the straight line segment corresponding to the pore size category in the reservoir is obtained according to the first and second pump stop times. Based on the pre-defined relationship between the slope of a straight line segment and permeability, the permeability corresponding to the pore is obtained according to the slope of the straight line segment corresponding to the pore. Based on the first relationship curve, the bottom hole pressure drop corresponding to the first and second pump stop times is obtained according to the first and second pump stop times corresponding to the pore size categories in the reservoir. The porosity of the reservoir is determined based on the permeability and bottom hole pressure drop corresponding to the pores.

[0006] In this embodiment of the application, obtaining the first relationship curve between bottom hole pressure and pump shutdown time within a preset target time period includes: after stopping the pumping of fracturing fluid into the fracturing well in the reservoir, obtaining the correspondence between bottom hole pressure and pump shutdown time in the fracturing well within a second preset time period; training an initial decreasing model based on the correspondence between bottom hole pressure and pump shutdown time within the second preset time period to obtain a trained target decreasing model; based on the target decreasing model, obtaining the correspondence between bottom hole pressure and pump shutdown time within the first preset time period, wherein the length of the first preset time period is greater than the length of the second preset time period; and determining the first relationship curve based on the correspondence between bottom hole pressure and pump shutdown time within the first preset time period.

[0007] In this embodiment of the application, an initial decreasing model is trained based on the correspondence between bottom hole pressure and pump shutdown time within a second preset time period to obtain a trained target decreasing model. This includes: based on the initial decreasing model, obtaining different bottom hole pressures corresponding to different pump shutdown times within the second preset time period, adjusting the decreasing index and average decreasing rate in the initial decreasing model until the different bottom hole pressures corresponding to different pump shutdown times within the second preset time period satisfy the correspondence between bottom hole pressure and pump shutdown time within the second preset time period, thereby obtaining the target decreasing model.

[0008] In this embodiment, the pores include main fractures, branch fractures, micro fractures, matrix macropores, matrix mesopores, and matrix micropores. Based on the second and / or third relationship curves, the first and second pump stop times corresponding to each pore size category in the reservoir are determined, including: determining the first pump stop time for the main fracture from a preset starting pump stop time; determining the second pump stop time for the main fracture from the moment when the trends of the second and third relationship curves change from being consistent to inconsistent; determining the first pump stop time for the branch fracture from the moment when the trends of the second and third relationship curves change from being consistent to inconsistent; determining the second pump stop time for the branch fracture from the moment after the first pump stop time of the branch fracture and when the third relationship curve reaches a first preset peak value; determining the first pump stop time for the micro fracture from the moment the third relationship curve reaches the first preset peak value; and determining the first pump stop time for the micro fracture from the moment the third relationship curve reaches the first preset peak value and then declines and rises again. The moment when the second preset peak value is reached is determined as the second pump stop time for the microslits, wherein the first preset peak value is less than the second preset peak value; the moment when the third relationship curve reaches the second preset peak value is determined as the first pump stop time for the macropores of the matrix, and the moment when the third relationship curve reaches the third preset peak value is determined as the second pump stop time for the macropores of the matrix, wherein the second preset peak value is less than the third preset peak value; the moment when the third relationship curve reaches the third preset peak value is determined as the first pump stop time for the mesopores of the matrix, and the moment when the third relationship curve reaches the third preset peak value, then drops and then rises to the fourth preset peak value is determined as the second pump stop time for the mesopores of the matrix, wherein the fourth preset peak value is less than the third preset peak value and greater than the second preset peak value; the moment when the third relationship curve reaches the fourth preset peak value is determined as the first pump stop time for the micropores of the matrix, and the moment when the third relationship curve reaches the preset termination pump stop time is determined as the second pump stop time for the micropores of the matrix.

[0009] In this embodiment, based on a preset correspondence between the slope of a straight line segment and permeability, the permeability corresponding to the pore is obtained according to the slope of the straight line segment corresponding to the pore, including determining the permeability corresponding to the pore according to the following formula:

[0010] Where Q is the fracturing fluid discharge rate and h is the reservoir thickness. denoted as fracturing fluid viscosity, m as slope of the straight line segment, and k as permeability.

[0011] In this embodiment, the porosity of pores in the reservoir is determined based on the permeability and bottom-hole pressure drop corresponding to the pores. This includes: determining the ratio of the bottom-hole pressure drop of pores of each pore size category to the sum of the bottom-hole pressure drops of pores of each pore size category; obtaining the pressure drop ratio of pores of each pore size category; normalizing the permeability corresponding to pores of each pore size category to obtain the normalized permeability corresponding to pores of each pore size category; determining the product of the pressure drop ratio of pores of each pore size category and the normalized permeability corresponding to each type of pore to obtain the pore weighted value of pores of each pore size category; determining the sum of the pore weighted values ​​of pores of each pore size category to obtain the total pore weighted value; and determining the ratio of the pore weighted value of pores of each pore size category to the total pore weighted value to obtain the proportion of each type of pore.

[0012] In this embodiment, the permeability corresponding to each pore size category is normalized to obtain the normalized permeability corresponding to each pore size category, including determining the normalized permeability according to the following formula:

[0013] In the formula, y i Pore ​​type i The corresponding normalized penetration rate, K It is a preset well logging permeability, k i It is a pore type i penetration rate k min It is the permeability in the micropores of the matrix. k max It is the permeability within the micro-slits.

[0014] A second aspect of this application provides an apparatus for determining the porosity of a reservoir, characterized in that it includes: a memory configured to store instructions; and a processor configured to retrieve instructions from the memory and, when executing the instructions, to implement the method described above for determining the porosity of a reservoir.

[0015] A third aspect of this application provides a machine-readable storage medium, characterized in that the machine-readable storage medium stores instructions for causing a machine to execute the above-described method for determining the porosity of a reservoir.

[0016] A fourth aspect of this application provides a computer program product, including a computer program, characterized in that the computer program, when executed by a processor, implements the above-described method for determining the porosity ratio of a reservoir.

[0017] The above technical solution, after stopping the pumping of fracturing fluid into the fracturing well in the reservoir, obtains a first relationship curve between the bottom hole pressure and the pump stop time within a first preset time period. This provides data support for subsequent analysis by obtaining the bottom hole pressure variation curve over the pump stop time. Based on the first relationship curve between bottom hole pressure and pump stop time within the first preset time period, a second relationship curve between bottom hole pressure drop and pump stop time, a third relationship curve between the bottom hole pressure drop derivative and pump stop time, and a fourth relationship curve between bottom hole pressure and the logarithm of pump stop time within the first preset time period are determined. By mathematically transforming the first relationship curve, multi-dimensional feature curves are generated, expanding the single first relationship curve into multiple feature dimensions such as pressure drop, pressure drop derivative, and time logarithm, providing a multi-dimensional analytical basis for subsequently identifying the response characteristics of different pore types. Based on the second and / or third relationship curves, the first and second pump stop times corresponding to pore sizes in the reservoir are determined. The first pump stop time corresponds to the time when the pore begins to be affected by bottom hole pressure, and the second pump stop time corresponds to the time when the adjacent pore of an unaffected pore begins to be affected by bottom hole pressure. By utilizing the characteristic inflection points of the pressure drop and pressure drop derivative curves, the time intervals in which pores of different sizes begin to be affected by bottom hole pressure can be accurately located, achieving multi-scale pore classification. Based on the fourth relationship curve, according to the first and second pump stop times corresponding to pore sizes in the reservoir, the slope of the straight line segment corresponding to the pore is obtained. On the fourth relationship curve, the time intervals corresponding to different pore types exhibit linear characteristics. By calculating the slope of this straight line segment, the characteristics in the time domain are transformed into quantifiable mathematical parameters, providing a key indicator for permeability calculation. Based on a pre-defined relationship between the slope of a straight line segment and permeability, the permeability corresponding to a pore is obtained from the slope of the straight line segment corresponding to the pore. This directly transforms mathematical characteristics into reservoir physical parameters, enabling quantitative calculation of permeability for pores at different scales, overcoming the limitation of traditional methods that can only obtain overall permeability. Based on the first relationship curve, the bottom hole pressure drop corresponding to the first and second pump stop times for each pore size category in the reservoir is obtained. Combined with the first relationship curve, pressure drop values ​​corresponding to different pore types over time intervals are extracted, providing pressure difference data for subsequent calculations of the contribution ratio of each pore. Based on the permeability and bottom hole pressure drop corresponding to the pore, the pore proportion in the reservoir is determined. Through the joint calculation of permeability and pressure drop, multi-scale pores within the fracturing zone are analyzed. Other features and advantages of the embodiments of the present invention will be described in detail in the following detailed description section. Attached Figure Description

[0018] The accompanying drawings are provided to further illustrate embodiments of the present invention and form part of the specification. They are used together with the following detailed description to explain the embodiments of the present invention, but do not constitute a limitation thereof. In the drawings: Figure 1 The illustration shows a flowchart of a method for determining the porosity of a reservoir according to an embodiment of this application. Figure 2 The schematic diagram illustrates the measured wellhead pressure trend and fitting diagram in one embodiment of this application; Figure 3 This illustration shows a schematic diagram of the wellhead pressure converted to bottom hole pressure in one embodiment of this application; Figure 4 This illustration schematically shows a 30-day pressure drop prediction diagram of bottom hole pressure in one embodiment of this application; Figure 5 This schematic diagram illustrates the morphological characteristics of a double logarithmic curve of pump stop pressure drop in one embodiment of this application. Figure 6 This illustration schematically shows the semi-logarithmic change trend of the measured bottom hole pressure after pump shutdown in one embodiment of this application. Figure 1 ; Figure 7 This illustration schematically shows the semi-logarithmic change trend of the measured bottom hole pressure after pump shutdown in one embodiment of this application. Figure 2 . Detailed Implementation

[0019] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are only for illustration and explanation of the embodiments of this application and are not intended to limit the embodiments of this application. All other embodiments obtained by those skilled in the art based on the embodiments of this application without creative effort are within the scope of protection of this application.

[0020] It should be noted that the acquisition, transmission, storage, use, and processing of data in the technical solution of this application all comply with the relevant provisions of national laws and regulations. In the embodiments of this application, certain existing industry solutions such as software, components, and models may be mentioned. These should be considered exemplary, intended only to illustrate the feasibility of implementing the technical solution of this application, and do not imply that the applicant has already used or necessarily used such solutions.

[0021] It should be noted that if the embodiments of this application involve directional indicators (such as up, down, left, right, front, back, etc.), the directional indicators are only used to explain the relative positional relationship and movement of each component in a certain specific posture (as shown in the figure). If the specific posture changes, the directional indicators will also change accordingly.

[0022] Furthermore, if the embodiments of this application involve descriptions such as "first" or "second," these descriptions are for descriptive purposes only and should not be construed as indicating or implying their relative importance or implicitly specifying the number of technical features indicated. Therefore, features defined with "first" or "second" may explicitly or implicitly include at least one of those features. Additionally, the technical solutions of various embodiments can be combined with each other, but this must be based on the ability of those skilled in the art to implement them. If the combination of technical solutions is contradictory or impossible to implement, it should be considered that such a combination of technical solutions does not exist and is not within the scope of protection claimed in this application.

[0023] Figure 1 The illustration schematically shows a flowchart of a method for determining the porosity of a reservoir according to an embodiment of this application. Figure 1 As shown in the figure, this application provides a method for determining the porosity of a reservoir. Taking the application of this method to a processor as an example, the method may include the following steps: Step S101: After stopping the pumping of fracturing fluid into the fracturing well in the reservoir, obtain the first relationship curve between the bottom hole pressure and the pumping stop time in the fracturing well during the first preset time period. Step S102: Based on the first relationship curve between bottom hole pressure and pump stop time within the first preset time period, determine the second relationship curve between bottom hole pressure drop and pump stop time within the first preset time period, the third relationship curve between the derivative of bottom hole pressure drop and pump stop time within the first preset time period, and the fourth relationship curve between bottom hole pressure and the logarithm of pump stop time within the first preset time period. Step S103: Based on the second relationship curve and / or the third relationship curve, determine the first pump stop time and the second pump stop time corresponding to the pores of each pore size category in the reservoir, wherein the first pump stop time corresponds to the pump stop time when the pores begin to be affected by the bottom hole pressure, and the second pump stop time corresponds to the pump stop time when the adjacent pores of the pores that are not affected by the bottom hole pressure begin to be affected by the bottom hole pressure. Step S104: Based on the fourth relationship curve, according to the first and second pump stop times corresponding to the pores of each pore size category in the reservoir, the slope of the straight line segment corresponding to the pore is obtained. Step S105: Based on the preset correspondence between the slope of the straight line segment and the permeability, the permeability corresponding to the pore is obtained according to the slope of the straight line segment corresponding to the pore. Step S106: Based on the first relationship curve, according to the first pump stop time and the second pump stop time corresponding to the pore size categories in the reservoir, the bottom hole pressure drop corresponding to the first pump stop time and the second pump stop time is obtained. Step S107: Determine the porosity of the pores in the reservoir based on the permeability and bottom hole pressure drop corresponding to the pores.

[0024] It can be understood that the first preset time period is a pre-set time period, which can be 30 days. The first relationship curve can be a curve with bottomhole pressure as the ordinate and pump shutdown time as the abscissa. The second relationship curve can be a curve with bottomhole pressure drop as the ordinate and pump shutdown time as the abscissa. The third relationship curve can be a curve with the derivative of bottomhole pressure drop as the ordinate and pump shutdown time as the abscissa. The fourth relationship curve can be a curve with bottomhole pressure as the ordinate and the logarithm of pump shutdown time as the abscissa. The slope of the straight line segment is the slope of the straight line segment determined based on the fourth relationship curve, the first pump shutdown time, and the second pump shutdown time. Bottomhole pressure drop is the amount of decrease in bottomhole pressure. Porosity is the proportion of space occupied by each pore.

[0025] Specifically, the processor acquires a first relationship curve between bottom hole pressure and pump shutdown time in a fractured well within a first preset time period. Based on this first relationship curve, it determines a second relationship curve between bottom hole pressure drop and pump shutdown time, a third relationship curve between the derivative of bottom hole pressure drop and pump shutdown time, and a fourth relationship curve between the logarithm of bottom hole pressure and pump shutdown time within the first preset time period. Then, based on the second and / or third relationship curves, it determines the first and second pump shutdown times corresponding to pores of different pore size categories in the reservoir. Based on the fourth relationship curve, the processor obtains the slope of the straight line segment corresponding to each pore size category in the reservoir according to the first and second pump stop times. Based on the preset correspondence between the slope of the straight line segment and permeability, the processor obtains the permeability corresponding to the pore according to the slope of the straight line segment corresponding to the pore. At the same time, based on the first relationship curve, the processor obtains the bottom hole pressure drop corresponding to the first and second pump stop times according to the first and second pump stop times corresponding to each pore size category in the reservoir. Finally, based on the permeability and bottom hole pressure drop corresponding to the pore, the processor determines the porosity of the pores in the reservoir.

[0026] The above technical solution, after stopping the pumping of fracturing fluid into the fracturing well in the reservoir, obtains a first relationship curve between the bottom hole pressure and the pump stop time within a first preset time period. This provides data support for subsequent analysis by obtaining the bottom hole pressure variation curve over the pump stop time. Based on the first relationship curve between bottom hole pressure and pump stop time within the first preset time period, a second relationship curve between bottom hole pressure drop and pump stop time, a third relationship curve between the bottom hole pressure drop derivative and pump stop time, and a fourth relationship curve between bottom hole pressure and the logarithm of pump stop time within the first preset time period are determined. By mathematically transforming the first relationship curve, multi-dimensional feature curves are generated, expanding the single first relationship curve into multiple feature dimensions such as pressure drop, pressure drop derivative, and time logarithm, providing a multi-dimensional analytical basis for subsequently identifying the response characteristics of different pore types. Based on the second and / or third relationship curves, the first and second pump stop times corresponding to pore sizes in the reservoir are determined. The first pump stop time corresponds to the time when the pore begins to be affected by bottom hole pressure, and the second pump stop time corresponds to the time when the adjacent pore of an unaffected pore begins to be affected by bottom hole pressure. By utilizing the characteristic inflection points of the pressure drop and pressure drop derivative curves, the time intervals in which pores of different sizes begin to be affected by bottom hole pressure can be accurately located, achieving multi-scale pore classification. Based on the fourth relationship curve, according to the first and second pump stop times corresponding to pore sizes in the reservoir, the slope of the straight line segment corresponding to the pore is obtained. On the fourth relationship curve, the time intervals corresponding to different pore types exhibit linear characteristics. By calculating the slope of this straight line segment, the characteristics in the time domain are transformed into quantifiable mathematical parameters, providing a key indicator for permeability calculation. Based on a pre-defined relationship between the slope of a straight line segment and permeability, the permeability corresponding to a pore is obtained from the slope of the straight line segment corresponding to the pore. This directly transforms mathematical characteristics into reservoir physical parameters, enabling quantitative calculation of permeability for pores at different scales, overcoming the limitation of traditional methods that can only obtain overall permeability. Based on the first relationship curve, the bottom hole pressure drop corresponding to the first and second pump stop times for each pore size category in the reservoir is obtained. Combined with the first relationship curve, pressure drop values ​​corresponding to different pore types over time intervals are extracted, providing pressure difference data for subsequent calculations of the contribution ratio of each pore. Based on the permeability and bottom hole pressure drop corresponding to the pore, the pore proportion in the reservoir is determined. Through the joint calculation of permeability and pressure drop, a quantitative characterization of the relative proportion of multi-scale pores in the fracturing zone is achieved, providing a key basis for evaluating fracturing effects and optimizing subsequent development plans.

[0027] In one embodiment, obtaining the first relationship curve between bottomhole pressure and pump shutdown time within a preset target time period includes: after stopping the pumping of fracturing fluid into the fracturing well in the reservoir, obtaining the correspondence between bottomhole pressure and pump shutdown time in the fracturing well within a second preset time period; training an initial decreasing model based on the correspondence between bottomhole pressure and pump shutdown time within the second preset time period to obtain a trained target decreasing model; based on the target decreasing model, obtaining the correspondence between bottomhole pressure and pump shutdown time within the first preset time period, wherein the length of the first preset time period is greater than the length of the second preset time period; and determining the first relationship curve based on the correspondence between bottomhole pressure and pump shutdown time within the first preset time period.

[0028] It is understandable that the second preset time period is a pre-set time period, which can be 1 hour. The target decreasing model is the final decreasing model obtained, which can be... , , In the formula, P0 is the initial pressure; n is the decrease exponent; Dp is the decrease rate or average decrease rate; and t is the pump stop time.

[0029] Specifically, after stopping the pumping of fracturing fluid into the fracturing well in the reservoir, the processor obtains the correspondence between the bottom hole pressure and the pump stop time in the fracturing well during a second preset time period. Based on the correspondence between the bottom hole pressure and the pump stop time during the second preset time period, an initial decreasing model is trained. That is, the pump stop time is input into the initial decreasing model, and the decreasing index in the decreasing model is adjusted to obtain the trained target decreasing model. Based on the target decreasing model, the correspondence between the bottom hole pressure and the pump stop time during the first preset time period is obtained, wherein the length of the first preset time period is greater than the length of the second preset time period. That is, based on the trained target decreasing model, a pump stop time greater than the second preset time period is input, and the corresponding bottom hole pressure is output. Then, based on the correspondence between the bottom hole pressure and the pump stop time during the first preset time period, the first relationship curve is determined.

[0030] In this embodiment, pressure prediction is performed on a longer first preset time period based on a trained model, breaking through the time limitation of measured data. This allows the generation of bottom hole pressure-time correspondences covering longer pump shutdown cycles, extending the effective range of the data. It eliminates the need for long-term, complete pump shutdown cycle pressure measurements; long-cycle pressure changes can be derived from short-term measured data, significantly reducing the time and manpower costs of on-site testing.

[0031] In one embodiment, an initial decreasing model is trained based on the correspondence between bottom hole pressure and pump shutdown time within a second preset time period to obtain a trained target decreasing model. This includes: based on the initial decreasing model, obtaining different bottom hole pressures corresponding to different pump shutdown times within the second preset time period, and adjusting the decreasing index and average decreasing rate in the initial decreasing model until the different bottom hole pressures corresponding to different pump shutdown times within the second preset time period satisfy the correspondence between bottom hole pressure and pump shutdown time within the second preset time period, thereby obtaining the target decreasing model.

[0032] Specifically, this application adjusts the decline index and average decline rate of the initial decline model based on the relationship between the pump stop time and the bottom hole pressure within the second preset time period, until the initial decline model satisfies the correspondence between the pump stop time and the bottom hole pressure, so as to obtain the target decline model.

[0033] In this embodiment, the application uses measured bottom hole pressure and pump shutdown time data during a second preset time period to train a decreasing model. By adjusting the decreasing index, an accurate target decreasing model is obtained, ensuring the accuracy of the model.

[0034] In one embodiment, the pores include main fractures, branch fractures, micro fractures, matrix macropores, matrix mesopores, and matrix micropores. Based on a second relationship curve and / or a third relationship curve, the first and second pump stop times corresponding to each pore size category in the reservoir are determined, including: determining the first pump stop time for the main fracture as a preset initial pump stop time; determining the second pump stop time for the main fracture as the moment when the trends of the second and third relationship curves change from being consistent to inconsistent; determining the first pump stop time for the branch fracture as the moment when the trends of the second and third relationship curves change from being consistent to inconsistent; determining the second pump stop time for the branch fracture as the moment after the first pump stop time of the branch fracture and when the third relationship curve reaches a first preset peak value; determining the first pump stop time for the micro fracture as the moment when the third relationship curve reaches the first preset peak value and then decreases and then rises again to the first preset peak value. The time when the second preset peak value is reached is determined as the second pump stop time for the microslits, wherein the first preset peak value is less than the second preset peak value; the time when the third relationship curve reaches the second preset peak value is determined as the first pump stop time for the macropores of the matrix, and the time when the third relationship curve reaches the third preset peak value is determined as the second pump stop time for the macropores of the matrix, wherein the second preset peak value is less than the third preset peak value; the time when the third relationship curve reaches the third preset peak value is determined as the first pump stop time for the mesopores of the matrix, and the time when the third relationship curve reaches the third preset peak value, then drops and then rises to the fourth preset peak value is determined as the second pump stop time for the mesopores of the matrix, wherein the fourth preset peak value is less than the third preset peak value and greater than the second preset peak value; the time when the third relationship curve reaches the fourth preset peak value is determined as the first pump stop time for the micropores of the matrix, and the time when the third relationship curve reaches the preset termination pump stop time is determined as the second pump stop time for the micropores of the matrix.

[0035] Specifically, such as Figure 5 As shown, Figure 5 This diagram schematically illustrates the morphological characteristics of a double logarithmic curve of pump shutdown pressure drop in one embodiment of this application. Figure 5The first blue vertical line corresponds to the first pump stop time of the main joint. After the pump stop time corresponding to the first blue vertical line, when the trends of the second and third relationship curves change from consistent to inconsistent (beginning to bifurcate), the second blue vertical line corresponds to the second pump stop time of the main joint, which is also the first pump stop time of the branch joint. After the second blue vertical line, the moment when the third relationship curve reaches its first peak is determined as the second pump stop time of the branch joint, which is also the first pump stop time of the micro-joint, i.e., the pump stop time corresponding to the third blue vertical line. The moment when the third relationship curve reaches its first peak, then declines, and then rises again to its second peak is determined as the second pump stop time of the micro-joint, i.e., the pump stop time corresponding to the fourth blue vertical line. The moment when the third relationship curve reaches its second peak is determined as the first pump stop time of the macropores in the matrix. The moment when the third relationship curve reaches its third peak is determined as the second pump stop time for the macropores of the matrix, which is the pump stop time corresponding to the fifth blue vertical line; the moment when the third relationship curve reaches its third peak is determined as the first pump stop time for the mesopores of the matrix, which is the pump stop time corresponding to the fifth blue vertical line; the moment when the third relationship curve reaches its third peak, then drops and then rises to the fourth peak is determined as the second pump stop time for the mesopores of the matrix, which is the pump stop time corresponding to the sixth blue vertical line; the moment when the third relationship curve reaches its fourth peak is determined as the first pump stop time for the micropores of the matrix, which is the pump stop time corresponding to the sixth blue vertical line; and the moment when the third relationship curve reaches the preset termination pump stop time is determined as the second pump stop time for the micropores of the matrix.

[0036] In this embodiment, time intervals are defined using dynamic features such as curve trend divergence points and peak values, replacing the traditional method of division based on empirical thresholds, thus improving the objectivity and accuracy of identification. The start and end response times for each pore or crack type are clearly defined, providing precise time boundaries for calculating parameters such as permeability of various pore types.

[0037] In one embodiment, based on a preset correspondence between the slope of a straight line segment and permeability, the permeability corresponding to the pore is obtained according to the slope of the straight line segment corresponding to the pore, including determining the permeability corresponding to the pore according to the following formula:

[0038] Where Q is the fracturing fluid discharge rate and h is the reservoir thickness. denoted as fracturing fluid viscosity, m as slope of the straight line segment, and k as permeability.

[0039] It can be understood that fracturing fluid displacement refers to the volume of fracturing fluid injected into the well. Fracturing fluid viscosity refers to the viscosity of the fracturing fluid injected into the well.

[0040] Specifically, this application establishes a direct quantitative relationship between the slope of the linear segment of the pressure drop curve and permeability, and combines this with measurable engineering parameters such as fracturing fluid discharge and reservoir thickness to achieve accurate calculation of reservoir permeability. This elevates reservoir analysis from qualitative observation to quantitative characterization, effectively reducing errors caused by empirical estimation and significantly improving the accuracy of permeability assessment.

[0041] In one embodiment, determining the porosity of pores in the reservoir based on the permeability and bottom-hole pressure drop corresponding to the pores includes: determining the ratio of the bottom-hole pressure drop of pores of each pore size category to the sum of the bottom-hole pressure drops of pores of each pore size category; to obtain the pressure drop ratio of pores of each pore size category; normalizing the permeability corresponding to pores of each pore size category to obtain the normalized permeability corresponding to pores of each pore size category after normalization; determining the product of the pressure drop ratio of pores of each pore size category and the normalized permeability corresponding to each type of pore to obtain the pore weighted value of pores of each pore size category; determining the sum of the pore weighted values ​​of pores of each pore size category to obtain the total pore weighted value; and determining the ratio of the pore weighted value of pores of each pore size category to the total pore weighted value to obtain the ratio of each type of pore.

[0042] It can be understood that the pressure drop ratio is the ratio of the bottom-hole pressure drop of each pore size category to the sum of the bottom-hole pressure drops of all pore size categories. Normalized permeability is the normalized permeability. The pore weighted value is the product of the pressure drop ratio of each pore size category and the normalized permeability corresponding to each pore type. The total pore weighted value is the sum of the pore weighted values ​​of each pore size category. The pore type ratio is the ratio of the pore weighted value of each pore size category to the sum of the pore weighted values.

[0043] Specifically, first, the proportion xi of the pressure drop in each segment to the total pressure drop over 30 days is calculated; then, using the reservoir logging permeability as a moderate value, the interpreted permeability of each segment is normalized to obtain yi. Since pressure drop and permeability are proportional to porosity, finally, xi×yi for each stage and the total value of each segment are calculated, and the proportion of each segment is the porosity proportion. In the embodiments of this application, this application establishes a quantifiable porosity proportion calculation method by weighting the pressure drop proportion with the normalized permeability, breaking through the limitations of traditional qualitative descriptions, realizing accurate quantitative assessment of the proportion of different size categories of pores in the reservoir, and achieving accurate quantitative characterization of porosity proportion. It is a reproducible and standardized porosity proportion calculation method that does not rely on complex core experiments and has high engineering applicability.

[0044] In one embodiment, the permeability corresponding to pores of each pore size category is normalized to obtain the normalized permeability corresponding to pores of each pore size category, including determining the normalized permeability according to the following formula:

[0045] In the formula, y i Pore ​​type i The corresponding normalized penetration rate, K It is a preset well logging permeability, k i It is a pore type i penetration rate k min It is the permeability in the micropores of the matrix. k max It is the permeability within the micro-slits.

[0046] It is understandable that the preset logging permeability rate is a pre-set logging permeability threshold.

[0047] Specifically, this application determines the normalized permeability according to the following formula. This normalization formula maps the permeability of different pore types (from matrix micropores to microfractures) to a unified comparable range, eliminating calculation bias caused by excessive differences in permeability values ​​at different scales, and providing a consistent quantitative basis for subsequent weighted calculation of porosity. Using well logging permeability as a benchmark and combining it with the extreme values ​​of permeability (minimum value of matrix micropores, maximum value of microfractures) for normalization reduces the impact of permeability anomalies of a single pore type on the overall calculation results, improving the stability of subsequent porosity assessment. The normalized permeability can be directly weighted and combined with parameters such as pressure drop ratio, realizing multi-parameter linkage calculation and laying a foundation for accurately characterizing reservoir porosity.

[0048] A specific embodiment of this application provides a method for determining the porosity of a reservoir, the specific steps of which are as follows: I. Pump Stop Pressure Drop Data Processing The measured pressure drop curve after pump shutdown fluctuates wildly and is quite noisy in the initial stage. Direct differentiation can easily produce significant deviations, so the raw data needs to be smoothed. Based on the trend characteristics of the pressure drop data within 1 hour after pump shutdown, a quadratic function is used for smoothing and fitting, ensuring that the data shows a monotonically decreasing trend while achieving data smoothing.

[0049] Next, based on the wellbore static pressure generated by the wellbore fluid density before the fracturing fluid pump was stopped, the wellhead pressure was converted to the bottom hole pressure, which is the basis for derivative analysis.

[0050] Then, based on the bottom hole pressure pattern within 1 hour, a hyperbolic decreasing model was applied to predict the pressure drop over 30 days.

[0051] Finally, the Bourdet method and the three-point central difference method are used to estimate the derivatives of the data points.

[0052] Wellhead pressure smoothing treatment, such as Figure 2 As shown. Figure 2 The diagram illustrates the measured wellhead pressure trend and fitting schematic in one embodiment of this application.

[0053] The formula for converting the fitted wellhead pressure to the bottom of the well is:

[0054] In the formula, p w The bottom hole pressure is expressed in MPa; ph is the wellhead pressure, expressed in MPa. H is the relative density of the wellbore fluid. D Let be the vertical depth of the reservoir, in meters (m).

[0055] The fitting of the adjusted bottom hole pressure uses a hyperbolic decreasing model, the formula of which is:

[0056]

[0057] In the formula, P0 is the initial pressure, MPa; n is the decline exponent; Dp is the decline rate and average decline rate, s⁻¹; and t is the pump shutdown time, s. The bottom hole pressure fitting curve is shown below. Figure 3 As shown. Figure 3 This illustration shows a schematic diagram of the wellhead pressure converted to bottom hole pressure in one embodiment of this application; Based on the fitting results, the pressure drop over 30 days at the bottom of the well was predicted, and the results are as follows: Figure 4 As shown. Figure 4 This illustration schematically shows a 30-day pressure drop prediction diagram of bottom hole pressure in one embodiment of this application; II. Logarithmic characteristic of pump shutdown pressure drop In pump shutdown pressure drop derivative analysis, the pressure drop effect between the initial pressure and the time-varying pressure is often used as the data object. The initial pressure drop derivative of the data points is processed using the central difference quotient method based on the given point spacing, and then the mean of adjacent data points is selected as the final pressure drop derivative of the data points using the Bourdet method. The theoretical formula for calculating the derivative is as follows:

[0058] Alternatively, the following formula can be used instead:

[0059] Plotting the time and pressure drop of the bottom hole pressure over 30 days, along with the time and pressure drop derivative, in a double logarithmic graph allows for analysis of the pressure drop during pump shutdown, reflecting seepage characteristics. For example... Figure 5 As shown. Figure 5 This schematic diagram illustrates the morphological characteristics of a double logarithmic curve of pump stop pressure drop in one embodiment of this application. The double logarithmic curve reflects the influence of well reservoir and follow-through for the first 30 seconds. After that, the two lines coincide, indicating the start of the reservoir seepage stage. The double logarithmic trend can be used to divide the reservoir seepage control mode after pump shutdown and pressure drop into six stages.

[0060] ① Main fracture seepage stage. The double logarithmic curves show a straight line with a slope of 1 / 2, which essentially reflects the seepage characteristics under the influence of the well's additional resistance or the equivalent skin layer. ② Fractured seepage stage. The pressure drop and its derivative bifurcation reflect the seepage entering the fractured system from the reservoir. This dominant mode ends after the pressure drop derivative reaches its peak. ③ Microcrack seepage stage. The seepage in the microcrack system reflects the transition between the flow fields of the fracture system and the matrix system, exhibiting a characteristic of the derivative first rapidly decreasing and then rising; ④ Macropore seepage stage in the matrix. The seepage in the macropores of the matrix occurs almost simultaneously with that in the micro-cracks, but the change in pressure drop is much stronger in the micro-cracks. After the short micro-crack seepage transition, the seepage enters the macropores of the matrix, and the pressure drop derivative shows a slow and continuous upward trend.

[0061] ⑤ The seepage stage in the macropores of the matrix. After the seepage in the macropores of the matrix, the pressure drop derivative slowly declines, dips, and then rises to a small peak. This stage lasts a long time, and the overall pressure drop decreases very slowly.

[0062] ⑥ Microporous seepage stage in the matrix. The last seepage control mode of the double logarithmic curve is microporous seepage in the matrix. Its pressure drop derivative shows a continuous decrease from the previous peak, and the pressure drop is basically stable, reaching an approximate equilibrium state.

[0063] The time points of each seepage control mode can be obtained from the double logarithmic curve, which is an important dividing criterion in subsequent calculations.

[0064] III. Calculation of permeability for different pore types The fracturing process can be approximated as a well injecting at a constant rate. Stopping the pump is equivalent to shutting down the well, at which point the pressure drop superposition principle in unsteady flow theory can be used for analysis. After pump shutdown, it can be assumed that the well continues to inject at the original rate, while simultaneously, another well at the original location begins production at the original rate. The bottom hole pressure is the result of interference between the two virtual wells. The resulting formula is:

[0065] In the formula, pr is the bottom hole pressure after pump shutdown, in Pa; pr is the formation pressure after fracturing, in Pa; Q is the discharge rate, in m3 / s; t is the viscosity of the liquid, Pa·s; Δt is the pump stop time, s; tp is the fracturing time, s.

[0066] According to the theory of unsteady flow, the bottom hole pressure after shut-in has a linear relationship with the logarithmic time in the radial flow stage. The intercept of the straight line is the extrapolated pressure, and the pore permeability that dominates the flow in this stage can be calculated by the slope of the straight line segment. At the same time, the appearance of different straight line segments also corresponds to different flow stages.

[0067] According to the formula, there is a linear relationship between the pressure after pump shutdown and the semi-logarithmic curve of pump shutdown time. The semi-logarithmic curve of bottom hole pressure after pump shutdown in an actual well is shown below. Figure 6 As shown, Figure 6 This illustration schematically shows the semi-logarithmic change trend of the measured bottom hole pressure after pump shutdown in one embodiment of this application. Figure 1 ; Depend on Figure 6 It can be seen that the bottom hole pressure change diagram does not have obvious straight lines. However, based on the seepage characteristics reflected by the double logarithmic curves of pressure drop and its derivative, the measured bottom hole pressure change can be divided into four segments: Initially, due to bottom hole follow flow and wellbore storage, the pressure change cannot reflect reservoir characteristics, lasting approximately 30 seconds; then the first straight line segment appears, representing the pressure drop process of the main fracture, which is very short; subsequently, the second straight line segment appears, reflecting the seepage characteristics of the fracture system in the reservoir stimulation zone; the third straight line segment represents the seepage manifestation of micro-fractures or large pores within the fracturing stimulation zone. The time points of each segment are based on... Figure 4 The seepage control stage is determined using a double logarithmic diagram.

[0068] The relationship between bottom-hole pressure and time is theoretically linear in a semi-logarithmic curve, and the permeability of the seepage pores can be obtained from the slope. That is:

[0069] In the formula, m is the slope of the straight line, and h is the thickness of the reservoir, m.

[0070] The three straight segments in the measured pump stop pressure drop curve reflect the seepage process of the main fracture, the branch fracture, and the original or fracture-induced micro-fracture of the formation, respectively. The corresponding permeability can be obtained based on the slope of each straight segment.

[0071] After the third straight segment (based on the trend extrapolated from the measured pressure curve), the bottom hole pressure continues to decrease, forming a semi-logarithmic curve as shown below. Figure 7 As shown. Figure 7 This illustration schematically shows the semi-logarithmic change trend of the measured bottom hole pressure after pump shutdown in one embodiment of this application. Figure 2 .

[0072] The curve is divided into three straight segments. The fourth segment reflects the seepage process in the large pores of the reservoir; the fifth segment shows a small pressure drop, reflecting the seepage process in the medium pores; and the sixth segment reflects the seepage process in the micropores. The permeability of different pore types can be calculated based on the slopes of these three segments. The time points of the straight lines are also determined by… Figure 4 The data was obtained from the phase division of the double logarithmic curve.

[0073] IV. Determination of the contribution ratio of seepage pores The pressure drop analysis from pump shutdown to the predicted 30-day period involved six stages: seepage through the main fracture, seepage through branch fractures, seepage through micro-fractures, seepage through macropores in the matrix, seepage through mesopores in the matrix, and seepage through micropores in the matrix. These stages were divided using six straight lines. Based on the displacement principle of elastic action, the reduction in pore volume and the expansion of fluid volume caused by pressure drop are closely related to the seepage space. A comprehensive weighting coefficient was constructed based on the pressure drop amplitude and permeability of each seepage stage, and its proportion to the total weight was used to characterize the seepage contribution of each type of pore. The steps are as follows: First, calculate the proportion xi of the pressure drop in each segment to the total pressure drop over 30 days; Then, using the reservoir logging permeability as a moderate value, the interpreted permeability of each section is normalized to obtain yi, the formula of which is:

[0074] In the formula, K is the logging permeability, mD; ki is the permeability of each seepage control stage, mD; kmin is the permeability in the matrix micropores, mD; and kma is the permeability in the microfractures, mD.

[0075] Since pressure drop and permeability are proportional to porosity, the final calculation of xi×yi for each stage and the total value of each stage is the porosity percentage.

[0076] It should be noted that the pore volume of the main crack and branch cracks can be calculated from the on-site crack geometry interpretation results, while the pore volume of microcracks, large pores, medium pores and micropores need to be estimated using this method.

[0077] The calculation results are shown in Table 1.

[0078] Table 1. Pressure drop and seepage porosity data for each seepage mode.

[0079] The proportions of seepage pores are as follows: macropores account for 47.97%, micropores account for 21.88%, mesopores account for 18.46%, and micropores account for 10.81%.

[0080] V. Innovation Points This study is the first to apply hydraulic fracturing shutdown pressure drop analysis to pore structure inversion, overcoming the limitations of traditional static or idealized assumptions and providing a more realistic reflection of the effective permeable pore structure of shale oil reservoirs under fluid-fracture coupling. This method eliminates the need for additional coring or costly imaging logging; it utilizes only the shutdown pressure drop data collected during fracturing operations to achieve quantitative pore structure evaluation of multiple reservoir sections throughout the well, significantly reducing the technical application threshold and cost. The interpretation results strongly support the establishment of integrated geological and engineering approaches, promoting the efficient development of shale oil.

[0081] VI. Advantages and Positive Effects This invention is based on dynamic analysis and uses data from one hour after fracturing pump shutdown, offering significant advantages: Closer to actual flow conditions: The inversion results are based on the pressure response after actual fracturing operations, reflecting the effective pore structure of underground porous media under the coupling effects of stress, fluid saturation and fracture network, rather than the pore distribution under static or idealized assumptions; Higher precision: It avoids problems such as insufficient representativeness of core sampling and mismatch between laboratory scale and reservoir scale, and can effectively identify invalid pores that "appear to exist but do not participate in seepage". Economical and efficient: No additional coring or expensive imaging logging is required. The pore structure of multiple reservoir sections throughout the well can be quantitatively evaluated using only the pressure drop data collected during conventional fracturing operations, which significantly reduces evaluation costs. Strong engineering guidance: The inversion results can be directly used to optimize subsequent fracturing design, sweet spot selection and production capacity prediction, supporting "geology-engineering integration" decision-making.

[0082] Therefore, the porosity inversion method based on dynamic pressure drop analysis not only better reflects the actual seepage mechanism of shale oil reservoirs in a physical sense, but also significantly outperforms single methods such as pure experiments, pure logging, or pure numerical simulation in terms of accuracy, applicability, and economy, providing reliable technical support for the efficient development of shale oil.

[0083] In one embodiment, this application provides an apparatus for determining the porosity of a reservoir, characterized in that it includes: a memory configured to store instructions; and a processor configured to retrieve instructions from the memory and, when executing the instructions, to implement the method described above for determining the porosity of a reservoir.

[0084] In one embodiment, this application provides a machine-readable storage medium, characterized in that the machine-readable storage medium stores instructions for causing a machine to execute the above-described method for determining the porosity of a reservoir.

[0085] In one embodiment, this application provides a computer program product, including a computer program, characterized in that the computer program, when executed by a processor, implements the above-described method for determining the porosity ratio of a reservoir.

[0086] It should also be noted that 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 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.

[0087] The above are merely embodiments of this application and are not intended to limit the scope of this application. Various modifications and variations can be made to this application by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of this application should be included within the scope of the claims of this application.

Claims

1. A method for determining the porosity of a reservoir, characterized in that, The method includes: After stopping the pumping of fracturing fluid into the fracturing well in the reservoir, a first relationship curve between the bottom hole pressure and the pumping stop time in the fracturing well during a first preset time period is obtained. Based on the first relationship curve between bottom hole pressure and pump stop time within the first preset time period, determine the second relationship curve between bottom hole pressure drop and pump stop time within the first preset time period, the third relationship curve between the derivative of bottom hole pressure drop and pump stop time within the first preset time period, and the fourth relationship curve between bottom hole pressure and the logarithm of pump stop time within the first preset time period. Based on the second relationship curve and / or the third relationship curve, determine the first pump stop time and the second pump stop time corresponding to the pores of each pore size category in the reservoir, wherein the first pump stop time corresponds to the pump stop time when the pore begins to be affected by the bottom hole pressure, and the second pump stop time corresponds to the pump stop time when the adjacent pores of the pores that are not affected by the bottom hole pressure begin to be affected by the bottom hole pressure. Based on the fourth relationship curve, according to the first and second pump stop times corresponding to the pores of each pore size category in the reservoir, the slope of the straight line segment corresponding to the pore is obtained. Based on the preset correspondence between the slope of a straight line segment and the permeability, the permeability corresponding to the pore is obtained according to the slope of the straight line segment corresponding to the pore. Based on the first relationship curve, according to the first and second pump stop times corresponding to the pore size categories in the reservoir, the bottom hole pressure drop corresponding to the first and second pump stop times is obtained; The porosity of the pores in the reservoir is determined based on the permeability corresponding to the pores and the bottom hole pressure drop corresponding to the pores.

2. The method according to claim 1, characterized in that, The first relationship curve between bottom hole pressure and pump shutdown time within a preset target time period includes: After stopping the pumping of fracturing fluid into the fracturing well in the reservoir, the correspondence between the bottom hole pressure of the fracturing well and the pumping stop time is obtained during a second preset time period. Based on the correspondence between bottom hole pressure and pump shutdown time within the second preset time period, an initial decreasing model is trained to obtain a trained target decreasing model. Based on the target decrease model, the correspondence between bottom hole pressure and pump stop time within the first preset time period is obtained according to the first preset time period, wherein the length of the first preset time period is greater than the length of the second preset time period. The first relationship curve is determined based on the correspondence between bottom hole pressure and pump shutdown time within the first preset time period.

3. The method according to claim 2, characterized in that, The step of training an initial decreasing model based on the correspondence between bottom hole pressure and pump shutdown time within the second preset time period to obtain a trained target decreasing model includes: Based on the initial decreasing model, the different bottom hole pressures corresponding to different pump stop times within the second preset time period are obtained. The decreasing index and average decreasing rate in the initial decreasing model are adjusted until the different bottom hole pressures corresponding to different pump stop times within the second preset time period satisfy the correspondence between bottom hole pressure and pump stop time within the second preset time period, so as to obtain the target decreasing model.

4. The method according to claim 1, characterized in that, The pores include main fractures, secondary fractures, micro fractures, matrix macropores, matrix mesopores, and matrix micropores. Determining the first and second pump stop times corresponding to each pore size category in the reservoir, based on the second relationship curve and / or the third relationship curve, includes: The preset start pump stop time is determined as the first pump stop time of the main seam, and the moment when the change trends of the second relationship curve and the third relationship curve change from being consistent to inconsistent is determined as the second pump stop time of the main seam. The moment when the second relationship curve and the third relationship curve change from having the same trend to having different trends is determined as the first pump stop time of the branch joint, and the moment after the first pump stop time of the branch joint and when the third relationship curve reaches the first preset peak value is determined as the second pump stop time of the branch joint. The moment when the third relationship curve reaches the first preset peak value is determined as the first pump stop time of the microslit, and the moment when the third relationship curve reaches the first preset peak value, drops, and then rises to the second preset peak value is determined as the second pump stop time of the microslit, wherein the first preset peak value is less than the second preset peak value. The moment when the third relationship curve reaches the second preset peak value is determined as the first pump stop time of the matrix macropores, and the moment when the third relationship curve reaches the third preset peak value is determined as the second pump stop time of the matrix macropores, wherein the second preset peak value is less than the third preset peak value; The moment when the third relationship curve reaches the third preset peak value is determined as the first pump stop time of the matrix pores, and the moment when the third relationship curve reaches the third preset peak value, drops, and then rises to the fourth preset peak value is determined as the second pump stop time of the matrix pores, wherein the fourth preset peak value is less than the third preset peak value and greater than the second preset peak value. The moment when the third relationship curve reaches the fourth preset peak value is determined as the first pump stop time of the matrix micropores, and the moment when the third relationship curve reaches the preset termination pump stop time is determined as the second pump stop time of the matrix micropores.

5. The method according to claim 1, characterized in that, The permeability corresponding to the pore is obtained based on the preset correspondence between the slope of the straight line segment and the permeability, according to the slope of the straight line segment corresponding to the pore. This includes determining the permeability corresponding to the pore according to the following formula: Where Q is the fracturing fluid discharge rate and h is the reservoir thickness. denoted as fracturing fluid viscosity, m as slope of the straight line segment, and k as permeability.

6. The method according to claim 1, characterized in that, The step of determining the porosity of the pores in the reservoir based on the permeability corresponding to the pores and the bottom hole pressure drop corresponding to the pores includes: Determine the ratio of the bottom hole pressure drop of the pores in each pore size category to the sum of the bottom hole pressure drops of the pores in each pore size category; to obtain the pressure drop percentage of the pores in each pore size category. The permeability corresponding to the pores of each pore size category is normalized to obtain the normalized permeability corresponding to the pores of each pore size category after normalization. The product of the pressure drop ratio of each pore size category and the normalized permeability corresponding to each pore size category is determined to obtain the pore weighting value of each pore size category. Determine the sum of the pore weight values ​​for each pore size category to obtain the total pore weight value; The ratio of the pore weighted value of each pore size category to the sum of the pore weighted values ​​is determined to obtain the proportion of each pore category.

7. The method according to claim 6, characterized in that, The normalization process for the permeability corresponding to each pore size category, to obtain the normalized permeability corresponding to each pore size category, includes determining the normalized permeability according to the following formula: In the formula, y i Pore ​​type i The corresponding normalized penetration rate, K It is a preset well logging permeability, k i It is a pore type i penetration rate k min It is the permeability in the micropores of the matrix. k max It is the permeability within the micro-slits.

8. An apparatus for determining the porosity of a reservoir, characterized in that, include: The memory is configured to store instructions; as well as The processor is configured to retrieve the instructions from the memory and, when executing the instructions, to implement the method for determining the porosity of a reservoir according to any one of claims 1 to 7.

9. A machine-readable storage medium, characterized in that, The machine-readable storage medium stores instructions for causing the machine to perform the method for determining the porosity of a reservoir according to any one of claims 1 to 7.

10. A computer program product, comprising a computer program, characterized in that, When executed by a processor, the computer program implements the method for determining the porosity of a reservoir according to any one of claims 1 to 7.

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