Perforation testing parameter inversion method, device, storage medium and program product

Abstract

The application discloses a perforation well test parameter inversion method and device, a storage medium and a program product, relates to the technical field of well test interpretation, and comprises the following steps: acquiring pressure data generated by fluid in the wellbore after perforation penetration in a target period in which no seepage interference occurs between adjacent perforation holes in a closed state; determining normalized pressure of the pressure data and a pressure derivative of the normalized pressure; and according to a target pressure derivative which is a constant value in the target period, obtaining the permeability of the original formation outside the well wall based on a microscopic radial seepage law. The application corrects the traditional physical misunderstanding and accurately obtains the real permeability of the original formation.

Description

Technical Field

[0001] This application relates to the field of well test interpretation technology, and in particular to perforation test parameter inversion methods, perforation test parameter inversion equipment, storage media and computer program products. Background Technology

[0002] Existing well test analysis methods are based on macroscopic wellbore radial flow models, which treat the entire perforated section as a macroscopic cylindrical surface with uniform fluid inflow. This macroscopic wellbore radial flow model ignores the spatially discrete point distribution of perforation holes when it is constructed and applied, and also assumes that the microscopic radial flow around each hole in the very early stage (i.e., before seepage interference occurs between adjacent holes) has no analytical value. At the same time, there is a physical misconception in traditional theory, which is that the independent radial flow of a single hole immediately terminates when the pressure detection radius reaches half the distance between adjacent holes. Based on this physical misconception, it is inferred that the duration of the very early stage is extremely short, not worthwhile and impossible to measure and interpret effectively. As a result, the industry cannot decouple the true permeability of the original formation outside the perforated compaction zone from the very early pressure data.

[0003] In summary, existing conventional macroscopic wellbore testing analysis, due to the use of macroscopic equivalent models and the existence of physical errors, is easily affected by macroscopic wellbore effects and formation bedding, and cannot accurately obtain the true permeability of the original formation. Summary of the Invention

[0004] The main purpose of this application is to provide a perforation test parameter inversion method, perforation test parameter inversion equipment, storage medium and computer program product, which aims to solve the existing technical problem of being unable to accurately obtain the true permeability of the original formation.

[0005] To achieve the above objectives, this application proposes a perforation test parameter inversion method, which includes: During the target period when there is no seepage interference between adjacent perforations while the well is shut in, acquire pressure data generated by fluid in the wellbore after perforation penetration. Determine the normalized pressure of the pressure data, and the pressure derivative of the normalized pressure; Based on the target pressure derivative, which is a constant value within the target time period, the permeability of the original formation outside the wellbore is obtained by inversion based on the microscopic radial seepage law.

[0006] In one embodiment, the step of acquiring pressure data generated by fluid within the wellbore after perforation penetration includes: Use bottom hole pressure data as pressure data inside the wellbore after perforation penetration; Alternatively, the superposition result obtained by superimposing the wellhead pressure data with the hydrostatic pressure of the fluid inside the wellbore can be used as the pressure data inside the wellbore after perforation penetration.

[0007] In one embodiment, the step of determining the normalized pressure of the pressure data includes: Determine the transient pressure drop data within the wellbore based on the pressure data; The equivalent instantaneous flow rate is determined based on the transient pressure drop data; Calculate the ratio of the transient pressure drop data to the equivalent instantaneous flow rate, and use the ratio as the normalized pressure.

[0008] In one embodiment, the step of determining the pressure derivative of the normalized pressure includes: The pressure derivative of the normalized pressure is obtained by taking the derivative of the normalized pressure with respect to the natural logarithm of time; wherein the time of the natural logarithm of time is the time after the perforation has penetrated.

[0009] In one embodiment, after the step of determining the pressure derivative of the normalized pressure, the method includes: Based on the pressure derivative, a double logarithmic diagnostic chart is plotted; Identify the horizontal plateau of the pressure derivative during the target time period on the double logarithmic diagnostic chart, and read the constant value corresponding to the horizontal plateau, using the constant value as the target pressure derivative.

[0010] In one embodiment, the step of obtaining the permeability of the original formation outside the wellbore based on the target pressure derivative, which is a constant value during the target time period, and inverting it according to the microscopic radial seepage law includes: Obtain the effective number of perforations in the wellbore, the effective rock penetration length of a single perforation, the fluid volume coefficient, and the fluid viscosity; The permeability of the original formation is calculated according to the microscopic radial seepage law using the target pressure derivative, the effective number of perforations, the effective rock penetration length of a single perforation, the fluid volume coefficient, the fluid viscosity, and a preset coefficient.

[0011] In one embodiment, after the step of inverting the permeability of the original formation outside the wellbore based on the target pressure derivative, which is a constant value within the target time period, the method includes: Select at least one characteristic time point within the target time period, and obtain the transient pressure drop data and instantaneous flow data corresponding to the characteristic time point; Based on the permeability of the original formation, the transient pressure drop data, and the instantaneous flow rate data, the micro-skin coefficient of a single pore is calculated.

[0012] Furthermore, to achieve the above objectives, this application also proposes a perforation test parameter inversion device, which includes: The acquisition module is used to acquire pressure data generated by fluid in the wellbore after perforation penetration during the target period when there is no seepage interference between adjacent perforations and when the well is shut in. The determination module is used to determine the normalized pressure of the pressure data and the pressure derivative of the normalized pressure; The inversion module is used to invert the permeability of the original formation outside the wellbore based on the target pressure derivative, which is a constant value within the target time period, and the microscopic radial seepage law.

[0013] In addition, to achieve the above objectives, this application also proposes a perforation test parameter inversion device, the device comprising: a memory, a processor, and a computer program stored in the memory and executable on the processor, the computer program being configured to implement the steps of the perforation test parameter inversion method as described above.

[0014] In addition, to achieve the above objectives, this application also proposes a storage medium, which is a computer-readable storage medium, on which a computer program is stored, and when the computer program is executed by a processor, it implements the steps of the perforation test parameter inversion method described above.

[0015] In addition, to achieve the above objectives, this application also provides a computer program product, which includes a computer program that, when executed by a processor, implements the steps of the perforation test parameter inversion method described above.

[0016] One or more technical solutions proposed in this application have at least the following technical effects: This application obtains pressure data generated by fluid within the wellbore after perforation penetration during the target period (i.e., the very early stage) before seepage interference occurs between adjacent perforations and under shut-in conditions. This operation abandons the traditional macroscopic equivalent model that treats the entire perforation section as a continuous cylindrical surface, instead utilizing the independent time windows of the seepage fields around each perforation in the very early stage, thus avoiding interference from macroscopic wellbore effects and formation bedding. Secondly, by determining the normalized pressure and its pressure derivative of the pressure data, the distortion effect of variable flow rate on the pressure response under shut-in conditions is eliminated, enabling the very early pressure response to truly reflect the microscopic radial seepage characteristics. Furthermore, based on the target pressure, which is a constant value within the target period... The derivative, based on the microscopic radial seepage law, is used to invert the permeability of the original formation outside the wellbore. Since the appearance of this constant value of the target pressure derivative is the mark of the independent radial flow stage of a single orifice, and the independent radial flow stage of a single orifice has not been interfered with by adjacent orifices, the inverted permeability directly corresponds to the true permeability of the original formation outside the perforated compaction zone that has not been disturbed, without the interference of macroscopic bedding effects or orifice damage skin coefficient. This corrects the traditional physical misconceptions and accurately obtains the true permeability of the original formation, thus solving the technical problem that existing technologies cannot accurately obtain the true permeability of the original formation due to ignoring orifice discreteness and very early microscopic radial seepage and being affected by physical misconceptions. Attached Figure Description

[0017] The accompanying drawings, which are incorporated in and form part of this specification, illustrate embodiments consistent with this application and, together with the description, serve to explain the principles of this application.

[0018] To more clearly illustrate the technical solutions in the embodiments of this application or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, for those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0019] Figure 1 This is a schematic flowchart of an embodiment of the perforation test parameter inversion method of this application; Figure 2 A schematic diagram of an embodiment of the perforation test parameter inversion method of this application Figure 1 ; Figure 3 A schematic diagram of an embodiment of the perforation test parameter inversion method of this application Figure 2 ; Figure 4 A schematic diagram of an embodiment of the perforation test parameter inversion method of this application. Figure 3 ; Figure 5 This is a schematic diagram of the module structure of the perforation test parameter inversion device of this application; Figure 6 This is a schematic diagram of the equipment structure of the hardware operating environment involved in the perforation test parameter inversion method of this application.

[0020] Explanation of reference numerals in the attached figures: 100 represents the surface; 200 represents the compacted zone; 300 represents the wellbore; 400 represents the perforation channel; 500 represents the formation. The purpose, features, and advantages of this application will be further explained in conjunction with the embodiments and with reference to the accompanying drawings. Detailed Implementation

[0021] It should be understood that the specific embodiments described herein are only used to explain the technical solutions of this application and are not intended to limit this application.

[0022] To better understand the technical solution of this application, a detailed description will be provided below in conjunction with the accompanying drawings and specific implementation methods.

[0023] Existing well test analysis (PTA) methods are based on the theory of "macro-wellbore radial flow," which equates the entire perforated section to a macro-cylindrical surface with uniform fluid inflow. This macro-equivalent model, however, ignores two facts: first, the perforations are discretely distributed as points on the casing wall, not a continuous fluid inflow surface; second, in the instant of perforation penetration and in the very early stages thereafter, the fluid is not uniformly forced in from the macro-wellbore, but rather seeps into the formation through individual perforations. However, the traditional macro-equivalent model fails to distinguish the independence of micro-flows, resulting in the calculation of permeability by superimposing the flows from multiple perforations. This makes it impossible to separate the true permeability of the original formation outside the compacted zone around each individual perforation, and instead, it is severely affected by macro-wellbore reservoir effects and formation bedding.

[0024] Furthermore, existing theories contain a physical misconception: they assume that the independent radial flow of each well terminates when the pressure detection radius reaches half the distance between adjacent wells. This misconception stems from equating the propagation distance of pressure waves with the actual seepage distance of fluid particles. In reality, pressure waves propagate much faster in the formation than fluid particles move. Although the pressure detection radius can cover the distance between adjacent wells in a very short time, the fluid particles have not yet undergone substantial movement. Therefore, the duration of the microscopic independent radial seepage stage (i.e., the very early stage) is not in the millisecond range, but can reach several seconds, tens of seconds, or even minutes. Because this physical misconception has remained uncorrected for a long time, the industry generally believes that the microscopic independent radial seepage stage is extremely short and cannot be effectively captured by conventional pressure gauges, thus never proposing pressure data acquisition schemes or parameter inversion methods for this stage.

[0025] In summary, the existing technology has the following unresolved technical problems: there is a lack of a method that can use high-frequency pressure data to invert the true permeability of the original formation based on the microscopic radial seepage law of a single pore within a very early time window before the interference of the streamlines of adjacent pores, and further obtain the microscopic damage epidermal coefficient of a single pore.

[0026] This application provides a solution that enables the acquisition of pressure data generated by fluid within the wellbore after perforation penetration during the target time period before seepage interference occurs between adjacent perforations and under shut-in conditions. By determining the normalized pressure and its pressure derivative of this pressure data, the distortion effect of variable flow rate on pressure response under shut-in conditions is eliminated. Furthermore, based on the target pressure derivative, which is a constant value within the target time period, the true permeability of the original formation outside the wellbore is directly inverted based on the microscopic radial seepage law. On this basis, the microscopic damage skin coefficient of a single perforation is further obtained. This overcomes the shortcomings of existing macroscopic equivalent models that cannot separate single perforation seepage and are susceptible to wellbore effects and bedding interference. It also corrects the physical misconception in traditional theory that there is no usable information in the very early stages due to the mistaken equation of pressure wave propagation distance with particle seepage distance.

[0027] It should be noted that the executing entity in this embodiment can be a perforation test parameter inversion device, such as a downhole data acquisition and processing module, or a general-purpose computing service device with data processing, network communication, and program execution functions, such as a tablet computer, personal computer, mobile phone, or server, or an embedded system, industrial controller, or cloud computing platform capable of realizing the above functions. The following description uses a perforation test parameter inversion device (hereinafter referred to as the parameter inversion device) as an example to illustrate this embodiment and the following embodiments.

[0028] Based on this, the embodiments of this application provide a method for inverting perforation test parameters, referring to... Figure 1 , Figure 1 This is a schematic flowchart of an embodiment of the perforation test parameter inversion method of this application.

[0029] It should be noted that the application scenario of this application can be the very early well test after perforation completion in oil and gas fields. Specifically, within a time window of several seconds to several minutes after perforation penetration, the true permeability of the original formation and the micro-skin coefficient of a single perforation are inverted through high-frequency pressure data, taking advantage of the physical condition that no seepage interference has occurred between adjacent perforations.

[0030] It should also be noted that conventional macroscopic well test analysis treats the entire perforated section as a cylindrical surface with uniform fluid inflow, and there is currently a physical misconception that "independent radial flow ends when the pressure detection radius reaches half the distance between adjacent boreholes," resulting in a lack of parameter inversion methods specifically for the very early microscopic flow state in the industry. This application, by distinguishing the difference between pressure wave propagation and fluid particle seepage, utilizes high-frequency pressure data from the very early independent radial flow stage to decouple the permeability of the original formation from the microscopic skin coefficient (i.e., the microscopic skin coefficient of a single borehole).

[0031] In this embodiment, the perforation test parameter inversion method includes steps S1 to S3: Step S1: During the target period when there is no seepage interference between adjacent perforations while the well is shut in, acquire the pressure data generated by the fluid in the wellbore after the perforation has penetrated. It should be noted that before performing parameter inversion, a time window needs to be determined. Within this time window, the fluid particles between adjacent perforations have not actually moved or overlapped, meaning that the seepage fields around each perforation are independent of each other. This time window is the target time period.

[0032] Optionally, the wellhead must be kept shut in, meaning the surface valves are closed and no fluid flows from the wellbore to the surface. During this target time period and in the shut-in state, a high-frequency pressure gauge is installed to continuously record the transient data of the fluid pressure change in the wellbore over time immediately after the perforating projectile explodes, penetrates the casing and cement sheath, and enters the formation. This transient data is the pressure data.

[0033] Optionally, the high-frequency pressure gauge has a sampling frequency greater than 100 Hz, which can capture pressure changes at the millisecond level.

[0034] Optionally, the high-frequency pressure gauge can be installed at the wellhead or the bottom of the well.

[0035] Optionally, the shut-in state ensures that there is no surface outflow from the wellbore. In this case, the only reason for the drop in bottom hole pressure is that the fluid pressure inside the wellbore is higher than the formation pressure and enters the formation.

[0036] Optionally, seepage interference between adjacent perforations refers to the phenomenon where fluid particles seeping from different perforations move through the formation and their seepage influence ranges overlap. Before this phenomenon occurs, each perforation seeps independently, and the pressure response only reflects the formation characteristics around a single perforation.

[0037] Optionally, the duration of the target time period can range from several seconds to several minutes, depending on parameters such as perforation spacing and formation permeability. The boundary of the target time period can be inferred by calculating the stability of the true permeability value of the original formation obtained by this method: when the permeability value calculated from early pressure data segments of different time lengths (e.g., data segments with different cutoff times such as 1 second, 2 seconds, and 5 seconds from the moment of perforation penetration) remains stable, it indicates that seepage interference between adjacent perforations has not yet occurred; when the permeability value begins to deviate significantly from the stable value (e.g., continuously rising or falling), it indicates that the interference stage has begun.

[0038] Understandably, existing well testing theories mistakenly equate the pressure detection radius with the fluid particle seepage distance, leading to the assumption that the independent radial flow stage is extremely short and unusable. This step eliminates surface flow interference by shutting in the well and collects pressure data within the target time period, thus avoiding interference from macroscopic wellbore effects and formation bedding on very early pressure data and ensuring the reliability and accuracy of subsequent microscopic inversion.

[0039] In one feasible implementation, step S1 includes: Step S11: Use the bottom hole pressure data as the pressure data inside the wellbore after perforation penetration; It should be noted that, during the target period when there is no seepage interference between adjacent perforations and when the well is shut in, when acquiring pressure data generated by the fluid in the wellbore after perforation penetration, a high-frequency pressure gauge can be installed according to the actual situation.

[0040] Optionally, if the high-frequency pressure gauge is installed directly at the bottom of the well (i.e., at the depth of the perforated section), the value recorded by the high-frequency pressure gauge is the bottom-hole pressure data, which can be directly used as the pressure data required for subsequent processing.

[0041] Optionally, the bottom hole pressure data are transient pressure drop values ​​continuously collected by a high-frequency pressure gauge installed at the bottom of the well during the instant of perforation penetration and the very early stage thereafter. The transient pressure drop values ​​reflect the change of fluid pressure in the wellbore over time.

[0042] Understandably, since the bottom hole pressure gauge directly measures the pressure at the perforation section without additional conversion, it can avoid conversion errors caused by uneven fluid density distribution or flow resistance in the wellbore, thereby improving the accuracy of pressure data.

[0043] Step S12, or, the superposition result obtained by superimposing the wellhead pressure data with the hydrostatic pressure of the fluid inside the wellbore, is used as the pressure data inside the wellbore after perforation penetration.

[0044] It should be noted that when a high-frequency pressure gauge cannot be installed at the bottom of the well due to high temperature, high pressure, or space limitations, and can only be installed at the wellhead, bottom-hole pressure data cannot be directly obtained. In this case, the pressure value at the wellhead can be recorded using a wellhead pressure gauge, which is called wellhead pressure data. At the same time, based on the density of the fluid in the wellbore, the acceleration due to gravity, and the vertical distance from the fluid surface at the wellhead to the depth of the perforated section, the hydrostatic pressure generated by the fluid in the wellbore under that vertical liquid column can be calculated.

[0045] Optionally, the wellhead pressure data is the pressure value of the fluid at the top of the wellbore after perforation, recorded by a pressure gauge installed at the wellhead.

[0046] Optionally, hydrostatic pressure is the pressure generated by the weight of a stationary liquid column, where the density of the liquid inside the wellbore is taken as the actual measured value of the completion fluid or kill fluid on site, and the vertical distance is the difference between the liquid surface at the wellhead and the center depth of the perforation section.

[0047] Alternatively, hydrostatic pressure can also be obtained directly through measurement.

[0048] Optionally, the overlay is to add the wellhead pressure data to the hydrostatic pressure to obtain the downhole pressure data at the perforated section, and the overlay result is used as the pressure data in the wellbore after the perforation has penetrated.

[0049] Optionally, this superposition operation assumes that the fluid in the wellbore is in a static or very low-velocity seepage state in the very early shut-in state, ignoring the pressure drop caused by flow resistance.

[0050] Understandably, in actual engineering projects, high temperatures at the bottom of the well or limitations in instrument size often prevent the deployment of high-frequency pressure gauges. This step, by superimposing and converting the wellhead pressure and hydrostatic pressure, can obtain the equivalent pressure data at the perforation section without increasing the cost of downhole instruments, thereby expanding the applicable scenarios of the method. It can both reduce costs and improve applicability. At the same time, since the fluid inside the wellbore is almost static in the shut-in state, the hydrostatic pressure calculation is accurate, the superposition error is controllable, and the accuracy is high.

[0051] Step S2: Determine the normalized pressure of the pressure data and the pressure derivative of the normalized pressure; It should be noted that after obtaining the pressure data, it is necessary to eliminate the distortion interference of the instantaneous variable flow rate on the pressure response under shut-in conditions. To this end, the equivalent instantaneous variable flow rate at the bottom of the well, which decays continuously over time, can be calculated from the measured pressure data based on the wellbore reservoir model or the closed cavity dynamics model.

[0052] In one embodiment, this step may also be: performing flow normalization processing on the pressure data to obtain normalized pressure, and determining the pressure derivative of the normalized pressure.

[0053] Optionally, the wellbore storage model is a mathematical model that describes the volume compression of fluid within the wellbore due to pressure changes; based on the wellbore storage model, the instantaneous variable flow rate at each moment can be obtained by performing time difference processing on the pressure data.

[0054] Alternatively, the closed cavity dynamics model treats the wellbore space near the perforation section as a closed cavity, assuming that the outflow rate of the fluid in the cavity is proportional to the rate of pressure change, and the equivalent instantaneous variable flow rate at the bottom of the well can be calculated in reverse.

[0055] Optionally, the normalized pressure is calculated, which is equal to the measured transient pressure drop data (i.e., the difference between the initial static pressure before perforation and the current pressure) divided by the equivalent instantaneous variable flow rate at the same time.

[0056] Optionally, transient pressure drop data can be directly recorded by a high-frequency pressure gauge or obtained by conversion from hydrostatic pressure.

[0057] Optionally, normalized pressure is the pressure response per unit flow rate. Its purpose is to eliminate the influence of variable flow rate on the amplitude of the pressure signal and make the pressure responses at different times comparable.

[0058] Optionally, the pressure derivative is obtained by differentiating the normalized pressure with respect to the natural logarithm of time.

[0059] Optionally, the pressure derivative can effectively reduce high-frequency noise in the measured data.

[0060] Understandably, since the flow rate at the bottom of the well is not constant after perforation, the characteristics of the seepage stage cannot be identified by directly using measured pressure data. This step normalizes the pressure response under variable flow conditions through flow rate normalization and derivative transformation, thereby enabling the identification of the constant value of the pressure derivative in the independent radial flow stage (i.e., the target pressure derivative).

[0061] Step S3: Based on the target pressure derivative, which is a constant value within the target time period, the permeability of the original formation outside the wellbore is obtained by inversion based on the microscopic radial seepage law.

[0062] It should be noted that the calculated normalized pressure and its pressure derivative are plotted on a double logarithmic diagnostic chart (the horizontal axis represents logarithmic time, and the vertical axis represents logarithmic normalized pressure and logarithmic pressure derivative). Within the target time period, the first stable horizontal plateau is found on the pressure derivative curve (i.e., the curve obtained by taking the logarithmic derivative of normalized pressure with respect to time). The constant value of the vertical axis corresponding to this stable horizontal plateau is called the target pressure derivative.

[0063] Alternatively, the method for finding a stable horizontal platform can be as follows: starting from the starting point after perforation, select early data segments of different lengths in sequence, calculate the permeability value for the selected ordinate of each data segment, and when the calculated permeability value remains stable, take the average value of all pressure derivatives in the data segment as the target pressure derivative; if the derivative curve is not completely horizontal due to the small spacing between the perforations, take the characteristic value at the middle position where the curve becomes flat.

[0064] Optionally, after identifying the horizontal plateau segment on the derivative curve, the corresponding ordinate should theoretically be a constant. However, due to high-frequency noise in the measured data, limitations in pressure gauge resolution, and numerical differentiation errors, the actual derivative points often fluctuate around this constant. Therefore, taking the average pressure derivative at all time points within the horizontal plateau segment as the target pressure derivative can suppress random noise, improve the robustness of feature extraction, approximate the theoretical true value, and avoid errors caused by manually selecting individual points, ensuring the repeatability and accuracy of the inversion results.

[0065] Optionally, the physical meaning of the target pressure derivative being constant is that, during the independent radial flow stage, the rate of change of normalized pressure with logarithmic time is constant, which is a characteristic feature of the microscopic radial seepage law on the double logarithmic diagnostic chart. Then, the extracted target pressure derivative is substituted into the derivative equation determined by the microscopic radial seepage law to invert and obtain the permeability of the original formation outside the wellbore (denoted as k).

[0066] Alternatively, the original formation outside the wellbore refers to the original reservoir rock that is closely attached to the outside of the perforation compaction zone and has not been disturbed by the perforation explosion.

[0067] Alternatively, the micro-radial seepage law is a radial seepage model centered on a single perforation channel, which replaces the macro-formation thickness with the total length of the effective inlet orifice.

[0068] Optionally, after obtaining the permeability of the original formation, any effective feature point can be selected within the derivative platform time period. The dynamic data such as pressure drop and flow rate corresponding to the effective feature point within the target time period, as well as the obtained permeability value, are substituted into the micro-radial flow pressure drop equation to obtain the micro-skin coefficient of a single pore. This micro-skin coefficient can be used to quantify the additional seepage resistance caused by the perforation compaction zone and pore fragmentation. The selected effective feature point should be located within the stable section of the derivative platform, avoiding the transition area near the beginning or end of the platform, to ensure that the substituted pressure drop and flow rate data are in the micro-radial flow stage (also called the independent radial flow stage), thereby ensuring the accuracy of the micro-skin coefficient.

[0069] Understandably, macroscopic wellbore effects (such as wellbore reservoir and follow current) and formation bedding (such as anisotropy and interlayer flow) can interfere with very early pressure data, causing measured pressure data to be mixed with formation information, wellbore damage information, wellbore fluid information, and non-radial flow information caused by bedding. These information are coupled together and cannot be distinguished. This application limits the data acquisition time window to the very early stage "before the flow interference of adjacent wellbore streamlines". Within this time window: macroscopic wellbore effects have been corrected by variable flow rate back-calculation; the influence of formation bedding has not yet been transmitted to the microscale due to the extremely slow particle movement and the extremely short propagation distance of pressure disturbances; each wellbore seeps outward radially independently without mutual interference. At this time, the very early pressure data is only affected by the formation seepage capacity (permeability) and the additional resistance near the wellbore (microscopic skin coefficient). Therefore, by identifying the target pressure derivative (i.e., the constant value corresponding to the stable horizontal plateau), the permeability of the original formation, independent of the microscopic skin coefficient, can be directly calculated. Substituting this back into the microscopic radial flow pressure drop equation yields the microscopic skin coefficient, achieving precise decoupling between the true permeability of the original formation and the additional resistance near the wellbore. If macroscopic wellbore effects and bedding interference are not eliminated, even with very early radial flow, the pressure data will still contain pressure drop distortion caused by wellbore reservoir accumulation and flow direction deviations due to bedding. Pure formation radial flow characteristic values ​​cannot be extracted, making it impossible to solve for permeability independently, and thus, decoupling cannot be achieved.

[0070] This embodiment provides a method for inverting perforation test parameters. By acquiring pressure data generated by fluid within the wellbore after perforation penetration during the target period (i.e., the very early stage) before seepage interference occurs between adjacent perforations and under shut-in conditions, this method abandons the traditional approach of treating the entire perforation section as a continuous cylindrical surface in macroscopic equivalent models. Instead, it utilizes time windows where the seepage fields around each perforation are independent in the very early stage, thus avoiding interference from macroscopic wellbore effects and formation bedding. Secondly, by determining the normalized pressure and its pressure derivative of the pressure data, the distortion effect of variable flow rate on the pressure response under shut-in conditions is eliminated, allowing the very early pressure response to truly reflect the microscopic radial seepage characteristics. Furthermore, based on the target period... The constant value of the target pressure derivative is used to invert the permeability of the original formation outside the wellbore based on the microscopic radial seepage law. Since the appearance of this constant value of the target pressure derivative is the mark of the independent radial flow stage of a single orifice, and the independent radial flow stage of a single orifice has not been interfered with by adjacent orifices, the inverted permeability directly corresponds to the true permeability of the original formation outside the perforated compaction zone that has not been disturbed, without the interference of macroscopic bedding effects or orifice damage skin coefficient. This corrects the traditional physical misconceptions and accurately obtains the true permeability of the original formation, thus solving the technical problem that existing technologies cannot accurately obtain the true permeability of the original formation due to ignoring orifice discreteness and very early microscopic radial seepage and being affected by physical misconceptions.

[0071] For example, to help understand the implementation process of the perforation test parameter inversion method obtained by combining the above embodiments, please refer to... Figure 2 , Figure 2 A schematic diagram of a perforation test parameter inversion method is provided. Specifically: 100 represents the surface. After positive pressure perforation is completed, high-pressure fluid in the wellbore 300 enters the formation through the perforation channel 400. Figure 2 Multiple perforations are drawn in the diagram, with the direction of fluid seepage. A compaction zone with a permeability lower than that of the original formation is formed around the perforations. Subsequently, the fluid seeps and diffuses into the outer formation 500 region in a simplified radial flow form. Figure 2 This demonstrates the microscopic seepage path of fluid within the wellbore, starting from the perforation orifice, passing through the compacted zone, and entering the original formation. Figure 2 As can be seen, the fluids flowing out of the various perforations do not overlap at this point, which can be called the very early stage.

[0072] Based on the above embodiments of this application, in another embodiment of this application, the same or similar content as the above embodiments can be referred to the above description, and will not be repeated hereafter. Based on this, step S2 includes: Step S21: Determine the transient pressure drop data inside the wellbore based on the pressure data; It should be noted that after obtaining the pressure data inside the wellbore after perforation penetration, it is necessary to extract the transient pressure drop data that reflects the magnitude of pressure changes. Specifically, determine the stable initial pressure value inside the wellbore before perforation penetration (which can be the average pressure value in the few seconds before perforation detonation), and then subtract the pressure data at each moment from the initial pressure value. The difference obtained is the transient pressure drop data.

[0073] Optionally, the transient pressure drop data is denoted as Δp(t), which represents the magnitude of the decrease in fluid pressure in the wellbore over time from the moment of perforation penetration. It is equal to the initial pressure value minus the pressure data value at the current moment.

[0074] Optionally, the transient pressure drop data is continuously recorded by a high-frequency pressure gauge in the shut-in state, reflecting the pressure decay process caused by fluid entering the formation from the wellbore.

[0075] Understandably, since the decrease in wellbore pressure relative to the initial static pressure after perforation is the direct driving force for fluid to enter the formation, this step converts absolute pressure into relative pressure drop, which can eliminate the interference caused by the difference in initial static pressure between different wells.

[0076] Step S22: Determine the equivalent instantaneous flow rate based on the transient pressure drop data; It should be noted that after obtaining the transient pressure drop data, it is necessary to reverse-calculate the instantaneous flow rate entering the formation from the wellbore at each moment. This instantaneous flow rate is not the surface measurement value (the surface flow rate is zero in the shut-in state), but rather the equivalent flow rate generated by the fluid inside the wellbore. For example, a wellbore reservoir model or a closed-cavity dynamic model can be used for calculation.

[0077] Optionally, the wellbore reservoir model is based on the mass balance equation: ,in, For equivalent instantaneous flow, Δp is the wellbore storage coefficient (calculated by multiplying the fluid volume in the wellbore by the fluid compressibility coefficient), and Δp is the transient pressure drop data. The rate of change is obtained by differentiating the transient pressure drop data over time.

[0078] Alternatively, the closed cavity dynamics model treats the wellbore space near the perforation section as a closed cavity, assuming that the outflow rate of the fluid in the cavity is proportional to the rate of pressure change, and the equivalent instantaneous flow rate can also be obtained.

[0079] Optionally, the equivalent instantaneous flow rate is denoted as q(t), with the unit being cubic meters per second. Its value decays over time because the wellbore pressure is high and the driving force is large in the early stage of perforation, and the flow rate gradually decreases as the pressure drops.

[0080] Optionally, the transient voltage drop data can be smoothed, such as by filtering, center difference, or three-point difference methods, to reduce the impact of noise.

[0081] Understandably, since the flow rate into the formation cannot be directly measured when the well is shut in, this step calculates the flow rate by using known wellbore storage parameters and measurable pressure change rate, thus converting the pressure signal into a flow rate signal.

[0082] Step S23: Calculate the ratio of the transient pressure drop data to the equivalent instantaneous flow rate, and use the ratio as the normalized pressure.

[0083] It should be noted that after obtaining the transient pressure drop data and the equivalent instantaneous flow rate at the same moment, the ratio calculated by dividing the transient pressure drop data by the equivalent instantaneous flow rate is called the normalized pressure.

[0084] Optionally, normalized pressure is denoted as Its physical meaning is the pressure response per unit flow rate, with units of Pascals per cubic meter per second. Specifically, it can be calculated as follows: , This is transient voltage drop data. This is the equivalent instantaneous flow rate.

[0085] Optionally, the calculation is performed point-in-time, that is, for each sampling time t, the transient pressure drop data at that time is divided by the equivalent instantaneous flow rate at that time to obtain the normalized pressure value at that time.

[0086] Optionally, normalized pressure can eliminate the distortion effect of variable flow rate on the amplitude of the pressure signal, making the pressure response at different times and under different flow conditions comparable.

[0087] Understandably, since the instantaneous flow rate continuously decays over time after perforation, directly using the original transient pressure drop data cannot distinguish the influence of formation seepage characteristics and flow rate changes. This step corrects the pressure response under variable flow conditions to an equivalent constant flow response by calculating the ratio of transient pressure drop to equivalent instantaneous flow rate.

[0088] In one feasible implementation, step S2 further includes: Step S24: Take the derivative of the normalized pressure with respect to the natural logarithm of time to obtain the pressure derivative of the normalized pressure; wherein, the time of the natural logarithm of time is the time after the perforation has penetrated.

[0089] It should be noted that after calculating the normalized pressure, a mathematical transformation of the normalized pressure is required to identify the horizontal plateau corresponding to the microscopic radial flow stage. Specifically, the natural logarithm of the time (in seconds) after the perforation penetration is used as the independent variable, and then the natural logarithm of that time (i.e., lnt) is calculated. Then, the normalized pressure is differentiated with respect to this natural logarithm using this natural logarithm as the abscissa variable.

[0090] Optionally, the pressure derivative It is the rate of change of the normalized pressure over the natural logarithm of time. ,in For normalized pressure, ln t is the natural logarithm of the time after the perforation penetrates, and t is the actual time starting from the moment of perforation penetration.

[0091] Alternatively, the pressure derivative can also be written as .

[0092] Alternatively, Bourdet (one) can be used. The derivative method (also known as the pressure derivative) is used to perform numerical derivative calculation. By selecting one point before and after the current point and assigning different weights, the influence of high-frequency noise on the derivative calculation can be effectively suppressed.

[0093] Optionally, the result of the differentiation operation is the pressure derivative of the normalized pressure, denoted as . Its unit is Pascal per cubic meter per second (with the same dimensions as normalized pressure), and its physical meaning is the change in normalized pressure caused by the natural logarithmic change per unit time in a logarithmic time coordinate.

[0094] Optionally, the time of the natural logarithm of time is the time after the perforation has penetrated, that is, the actual elapsed time from the moment the perforation projectile detonates and the metal jet penetrates the casing and cement sheath into the formation.

[0095] Understandably, due to the different forms of pressure derivatives corresponding to different seepage stages (the derivative in the independent radial flow stage presents a horizontal plateau), it is difficult to accurately identify the horizontal plateau segment by directly observing the normalized pressure curve. This step converts the pressure response into a derivative by taking the logarithmic derivative, which can highlight the characteristics of the seepage stage, thereby avoiding misjudgment of the horizontal plateau segment caused by flow rate changes or noise interference, and improving the accuracy of subsequent parameter inversion.

[0096] In one feasible implementation, after step S2, the method further includes: Step S25: Draw a double logarithmic diagnostic chart based on the pressure derivative; It should be noted that after obtaining the pressure derivative, it can be presented graphically to identify the characteristics of the seepage stage. The horizontal axis is the time after perforation penetration, but the horizontal axis uses a logarithmic scale (i.e., the scale value is the common logarithm or natural logarithm of the actual time), and the vertical axis also uses a logarithmic scale.

[0097] Optionally, the curves of normalized pressure versus logarithmic time and pressure derivative versus logarithmic time can be plotted separately, with the two curves plotted in the same coordinate system to form a double logarithmic diagnostic chart.

[0098] Alternatively, normalized pressure can be represented in the graph as scatter points or lines, and the pressure derivative can be distinguished by another symbol or color.

[0099] Optionally, the horizontal axis of the double logarithmic diagnostic chart is time (in seconds), which is then logarithmized; the vertical axis is the normalized pressure and its pressure derivative, which is then logarithmized.

[0100] Optionally, the normalized pressure values ​​and the calculated pressure derivative values ​​at each time point are mapped onto a logarithmic coordinate axis in chronological order to generate an interactive or static diagnostic graph.

[0101] Understandably, in conventional well test analysis, different seepage stages (such as wellbore reservoir stage, radial flow stage, and boundary influence stage) exhibit different curve morphology characteristics on the logarithmic graph (the pressure derivative in the independent radial flow stage presents a horizontal plateau). This step plots the normalized pressure and pressure derivative in the same logarithmic coordinate system, which allows for a direct comparison of the relative positions and trends of the two curves. This avoids the problem of difficulty in identifying horizontal plateau segments based solely on numerical values ​​and tables, and improves the reliability of feature identification.

[0102] Step S26: Identify the horizontal plateau presented by the pressure derivative in the target time period on the double logarithmic diagnostic chart, and read the constant value corresponding to the horizontal plateau, and use the constant value as the target pressure derivative.

[0103] It should be noted that after obtaining the double logarithmic diagnostic chart, one can intuitively look for an approximately horizontal straight line segment on the pressure derivative curve within the target time period (i.e., the time window in which no seepage interference occurs between adjacent perforations). This horizontal line segment corresponds to the characteristics of the independent radial flow stage.

[0104] Optionally, the interval in the pressure derivative curve where the vertical axis value does not change significantly with the horizontal axis (logarithmic time) can be located through image analysis or manual interaction. This interval is called the horizontal plateau.

[0105] Optionally, the identification of a horizontal platform can be implemented as follows: starting from the very early stage after perforation, data segments of different lengths are selected sequentially, and the mean and standard deviation of the pressure derivative values ​​in each data segment are calculated. When the standard deviation is less than a preset threshold (e.g., five percent of the mean) and multiple consecutive data points remain stable, the segment is determined to be a horizontal platform. If the derivative curve is not completely horizontal due to the small gap between the perforations, the characteristic value is taken at the middle position where the curve becomes gentler.

[0106] Optionally, the constant value corresponding to the horizontal platform is read by taking the average value of all pressure derivative values ​​within the horizontal platform segment, and the average value is recorded as the target pressure derivative.

[0107] Optionally, the target pressure derivative is a constant that does not change with time. Its physical meaning is that in the independent radial flow stage, the rate of change of normalized pressure with logarithmic time is constant. This constant is related to the permeability of the original formation and the total length of the effective inlet orifice (i.e., the sum of the rock penetration lengths of all effective perforations).

[0108] Understandably, since the pressure derivative horizontal plateau is the only characteristic value that can be used to solve permeability in the very early independent radial flow stage, and the horizontal plateau segment may not be completely horizontal due to noise or orifice spacing, this step can reliably extract the characteristic constant value by using statistical methods or the strategy of taking the value at the position where the curve becomes gentler, thereby avoiding parameter inversion failure due to data fluctuations or incomplete plateau.

[0109] In this embodiment, by drawing a double logarithmic diagnostic chart and identifying the horizontal platform on it, the problem of not being able to extract microscopic radial flow characteristic values ​​from the variable flow pressure data in the very early microscopic independent radial flow window in conventional well testing due to neglecting the very early microscopic independent radial flow window is solved.

[0110] Based on the above embodiments of this application, in another embodiment of this application, the same or similar content as the above embodiments can be referred to the above description, and will not be repeated hereafter. Based on this, step S3 includes: Step S31: Obtain the effective number of perforations in the wellbore, the effective rock penetration length of a single perforation, the fluid volume coefficient, and the fluid viscosity. It should be noted that before performing permeability inversion, other completion parameters should be obtained, such as the number of effective perforations, the effective rock penetration length of a single perforation, the fluid volume coefficient, and the fluid viscosity.

[0111] Optionally, the effective number of perforations is the actual number of perforations that can be filled with liquid within the perforation section. It can be directly read from the perforation construction record and is a correction value for invalid perforations such as those where the perforating projectile did not detonate or the channel was blocked.

[0112] Optionally, the effective rock penetration length of a single perforation refers to the effective depth of the hole formed by the explosion of a single perforating projectile from the casing wall into the formation. The effective rock penetration length of a single perforation is determined based on the type of perforating projectile (e.g., the charge amount and shaped charge structure of a shaped charge perforating projectile) and test range data, and is usually taken as tens of centimeters, such as 40 centimeters.

[0113] Optionally, the fluid volume factor is the coefficient of volume change of formation fluid from formation pressure and temperature conditions to standard surface conditions, and can be obtained experimentally.

[0114] Optionally, fluid viscosity is the dynamic viscosity of formation fluid under reservoir conditions, measured in millipascals per second, and can be obtained experimentally.

[0115] Understandably, since the permeability inversion formula includes both the measured target pressure derivative and the aforementioned well completion and fluid parameters, it can avoid deviations in the inversion results caused by missing or incorrectly estimated parameters, thereby improving the reliability of permeability calculations.

[0116] Step S32: The permeability of the original formation is calculated according to the microscopic radial seepage law using the target pressure derivative, the effective number of perforations, the effective rock penetration length of a single perforation, the fluid volume coefficient, the fluid viscosity, and a preset coefficient.

[0117] It should be noted that after obtaining the various parameters and identifying the derivative of the target pressure, these values ​​are substituted into the analytical formula derived based on the microscopic radial seepage law for calculation.

[0118] Optionally, the micro-radial seepage law is a seepage model in which the fluid diverges radially in the original formation outside the compaction zone with a single perforation channel as the center. This model replaces the formation thickness in the macro-well test with the total length of the effective inlet holes (equal to the number of effective perforations multiplied by the effective rock penetration length of a single hole).

[0119] Optionally, the preset coefficient is a conversion constant, and its value can be 17.84.

[0120] Alternatively, the calculation formula can be: ;in, The permeability of the original strata. The fluid volume coefficient, For fluid viscosity, The effective number of perforations, The effective rock penetration length of a single borehole. The derivative of the target pressure.

[0121] Optionally, the permeability of the original formation is the permeability of the original reservoir rock that is immediately adjacent to the outside of the perforation compaction zone and has not been disturbed by perforation explosions or drilling fluid contamination, and is measured in millidarcy.

[0122] Understandably, since the macroscopic well testing method treats the entire perforated section as a cylindrical surface and is limited by physical biases that prevent the separation of the compaction zone, this step utilizes the target pressure derivative of the very early independent radial flow stage and substitutes it into the microscopic radial seepage formula to directly calculate the true permeability of the original formation, thereby avoiding the interference of macroscopic wellbore effects and formation bedding on permeability inversion.

[0123] In this embodiment, by substituting the measured characteristic values, well completion parameters, fluid parameters, and preset coefficients into the analytical formula, the problem that conventional well testing cannot decouple the original permeability and the micro-skin coefficient in the very early stage is solved.

[0124] In one possible implementation, after step S3, the following is included: Step S33: Select at least one characteristic time point within the target time period, and obtain the transient pressure drop data and instantaneous flow data corresponding to the characteristic time point; It should be noted that, after obtaining the permeability of the original formation, in order to further quantify the additional seepage resistance caused by the perforated compaction zone, effective feature points for calculating the micro-skin coefficient can be extracted from the target time period. Where i can be a natural number such as 1, 2, etc., representing different times, and t represents the selected feature time point. This refers to the transient voltage drop data obtained at the corresponding characteristic time points.

[0125] Optionally, one or more time points can be arbitrarily selected as characteristic time points within the time interval corresponding to the pressure derivative level plateau on the double logarithmic diagnostic chart; then, the transient pressure drop value corresponding to the characteristic time point is obtained; and the instantaneous flow rate value corresponding to the same characteristic time point is obtained at the same time.

[0126] Optionally, the characteristic time point can be selected from the moment when the signal-to-noise ratio is high within the horizontal plateau segment, for example, avoiding the point where the pressure data shows obvious oscillations or jumps.

[0127] Optionally, if multiple feature time points are selected, the average value of multiple micro-epidermal coefficients can be taken in subsequent calculations to improve accuracy.

[0128] Understandably, since the permeability inversion formula only uses the constant value of the ordinate of the pressure derivative horizontal platform and does not use the pressure information at specific moments within the horizontal platform, while the calculation of the micro-skin coefficient requires pressure drop data and instantaneous flow rate at a certain moment, this step provides the necessary data for solving the micro-skin coefficient by selecting characteristic time points and simultaneously acquiring the corresponding transient pressure drop and instantaneous flow rate, thereby avoiding the use of data outside the horizontal platform segment that has been affected by pore interference and improving the accuracy of the micro-skin coefficient.

[0129] Step S34: Based on the permeability of the original formation, the transient pressure drop data, and the instantaneous flow rate data, the micro-skin coefficient of the single pore is calculated.

[0130] It should be noted that the transient pressure drop data and instantaneous flow rate data corresponding to the acquired characteristic time points, together with the calculated permeability of the original formation, are substituted into the approximate pressure drop equation of the microscopic radial flow stage to solve for the single-pore micro-skin coefficient that characterizes the additional resistance of the compaction zone.

[0131] Optionally, the specific calculation method is as follows:

[0132] in, The transient voltage drop data corresponding to the characteristic time point can also be denoted as... , For instantaneous flow data at the same moment, Here, μ is the fluid volume coefficient, μ is the fluid viscosity, and k is the calculated permeability of the original formation. The effective rock penetration length of a single borehole is given, and t is the selected characteristic time point. This refers to the porosity of the formation. The overall compression coefficient is... Where is the radius of the perforation hole. denoted as the microscopic epidermal coefficient of a single pore.

[0133] Optionally, the micro-skin coefficient of a single pore is a dimensionless number, with positive values ​​indicating additional resistance (the compaction zone leads to a decrease in permeability) and negative values ​​indicating that the pore connects to a high-permeability region.

[0134] Understandably, since the permeability and thickness of the perforated compaction zone cannot be directly measured, but its influence on seepage is represented by the microscopic skin coefficient in the microscopic radial flow pressure drop equation, this step uses the permeability of the original formation obtained by inversion to separate the additional pressure drop caused by the compaction zone in the very early pressure response, thereby achieving the decoupling of the original formation permeability and the microscopic skin coefficient, solving the problem that conventional well testing cannot distinguish between the two.

[0135] In this embodiment, by substituting the measured pressure drop data and instantaneous variable flow rate of the characteristic points into the pressure drop equation, the problem of forward calculation of the micro-skin coefficient is solved, providing a basis for evaluating the effectiveness of perforating projectiles and guiding production increase measures.

[0136] In one embodiment, after accurately calculating the original formation permeability and skin factor, the following direct values ​​can be provided for engineering practice: Based on the true original formation permeability, the production capacity of the formation after perforation can be predicted more accurately, avoiding deviations in development plans caused by underestimating permeability during macro-well testing; Based on the size of the skin factor, the additional flow resistance caused by the perforation compaction zone and channel fracturing can be quantitatively evaluated, thereby determining whether the current perforation process has caused serious reservoir damage; Furthermore, when the skin factor is higher than the design threshold, it can guide subsequent production enhancement measures such as acidizing and hydraulic fracturing, and optimize the scale of the enhancement and construction parameters based on the decoupling results of permeability and skin factor; Finally, by comparing the inversion results under different perforation cartridges and different perforation processes, a basis can be provided for the selection of perforation equipment and the design of perforation parameters, realizing engineering feedback and continuous improvement of perforation completion quality.

[0137] For example, to help understand the implementation process of the perforation test parameter inversion method obtained by combining the above embodiments, please refer to... Figure 3 , Figure 3 A schematic diagram of a perforation test parameter inversion method is provided, specifically: Figure 3 This is a pressure drop curve showing the change of measured bottom hole pressure data over time in the very early stages. Figure 3 The horizontal axis represents time (in seconds), and the vertical axis represents bottom hole pressure data (in MPa). The measured curve (solid line) shows the dynamic response characteristics of the bottom hole pressure after perforation penetration: the pressure drops rapidly in the initial stage, then the rate of decrease gradually slows down, and finally tends to stabilize. Figure 3 The vertical line indicates the pressure change (increase or decrease) after perforation penetration. Key sampling points can be selected from the time period when the rate of decrease gradually slows down and eventually stabilizes to obtain the true permeability of the original formation.

[0138] For example, to help understand the implementation process of the perforation test parameter inversion method obtained by combining the above embodiments, please refer to... Figure 4 , Figure 4 A schematic diagram of a perforation test parameter inversion method is provided, specifically: Figure 4 The horizontal axis represents the logarithmic time (Δt) after perforation, in hours (h), and the vertical axis represents the normalized pressure and its pressure derivative. ). Figure 4 It contains two curves: one is a smooth blue curve, representing the calculated normalized pressure (…). The other line is a red scatter plot, representing the pressure derivative (); Based on the above, a double logarithmic diagnostic chart is constructed.

[0139] Identify the horizontal plateau of the pressure derivative within the target time period on a double logarithmic diagnostic plot. Observe. Figure 4 The red scatter plot (pressure derivative) curve in the figure shows approximately [value missing] over logarithmic time (Δt). to Within the interval, its ordinate value ( The change in the horizontal axis is minimal, forming an approximately horizontal plateau. This horizontal plateau is a characteristic feature of the very early stage of independent radial flow. Within this horizontal interval, the average of the vertical coordinate values ​​of all the red scatter points is taken; this average value is the target pressure derivative required for subsequent inversion calculations.

[0140] It should be noted that the above examples are only for understanding this application and do not constitute a limitation on the perforation test parameter inversion method of this application. Any simple transformations based on this technical concept, such as the interaction and combination of various embodiments, are all within the protection scope of this application.

[0141] This application also provides a perforation test parameter inversion device, please refer to... Figure 5 The perforation test parameter inversion device includes: The acquisition module 10 is used to acquire pressure data generated by fluid in the wellbore after perforation penetration during the target period when there is no seepage interference between adjacent perforations in the shut-in state. The determination module 20 is used to determine the normalized pressure of the pressure data and the pressure derivative of the normalized pressure; The inversion module 30 is used to invert the permeability of the original formation outside the wellbore based on the microscopic radial seepage law, according to the target pressure derivative which is a constant value during the target time period.

[0142] The perforation test parameter inversion device provided in this application, employing the perforation test parameter inversion method described in the above embodiments, can solve the technical problem of the inability to accurately obtain the true permeability of the original formation. Compared with the prior art, the beneficial effects of the perforation test parameter inversion device provided in this application are the same as those of the perforation test parameter inversion method provided in the above embodiments, and other technical features in the perforation test parameter inversion device are the same as those disclosed in the methods of the above embodiments, and will not be repeated here.

[0143] This application provides a perforation test parameter inversion device, which includes: at least one processor; and a memory communicatively connected to the at least one processor; wherein the memory stores instructions executable by the at least one processor, and the instructions are executed by the at least one processor to enable the at least one processor to execute the perforation test parameter inversion method in the first embodiment described above.

[0144] The following is for reference. Figure 6 The diagram illustrates a structural schematic of a perforation test parameter inversion device suitable for implementing embodiments of this application. The perforation test parameter inversion device in embodiments of this application may include, but is not limited to, mobile terminals such as mobile phones, laptops, digital radio receivers, PDAs (Personal Digital Assistants), PADs (Portable Application Description), etc., and fixed terminals such as digital TVs, desktop computers, etc. Figure 6 The perforation test parameter inversion device shown is merely an example and should not impose any limitations on the functionality and scope of use of the embodiments of this application.

[0145] like Figure 6As shown, the perforation test parameter inversion device may include a processing unit 1001 (e.g., a central processing unit, a graphics processing unit, etc.), which can perform various appropriate actions and processes according to a program stored in a read-only memory 1002 or a program loaded from a storage device 1003 into a random access memory 1004. The random access memory 1004 also stores various programs and data required for the operation of the perforation test parameter inversion device. The processing unit 1001, the read-only memory 1002, and the random access memory 1004 are interconnected via a bus 1005. An input / output interface 1006 is also connected to the bus. Typically, the following systems can be connected to the input / output interface 1006: input devices 1007 including, for example, a touch screen, touchpad, keyboard, mouse, image sensor, microphone, accelerometer, gyroscope, etc.; output devices 1008 including, for example, a liquid crystal display (LCD), speaker, vibrator, etc.; storage devices 1003 including, for example, magnetic tape, hard disk, etc.; and communication devices 1009. Communication device 1009 allows the perforation test parameter inversion equipment to communicate wirelessly or wiredly with other equipment to exchange data. Although the figure shows perforation test parameter inversion equipment with various systems, it should be understood that implementation or possession of all the systems shown is not required. More or fewer systems may be implemented alternatively.

[0146] Specifically, according to the embodiments disclosed in this application, the processes described above with reference to the flowcharts can be implemented as computer software programs. For example, embodiments disclosed in this application include a computer program product comprising a computer program carried on a computer-readable medium, the computer program containing program code for performing the methods shown in the flowcharts. In such embodiments, the computer program can be downloaded and installed from a network via a communication device, or installed from storage device 1003, or installed from read-only memory 1002. When the computer program is executed by processing device 1001, it performs the functions defined in the methods of the embodiments disclosed in this application.

[0147] The perforation test parameter inversion equipment provided in this application, employing the perforation test parameter inversion method described in the above embodiments, can solve the technical problem of existing methods failing to accurately obtain the true permeability of the original formation. Compared with the prior art, the beneficial effects of the perforation test parameter inversion equipment provided in this application are the same as those of the perforation test parameter inversion method provided in the above embodiments, and other technical features of this perforation test parameter inversion equipment are the same as those disclosed in the previous embodiment method, and will not be repeated here.

[0148] It should be understood that the various parts disclosed in this application can be implemented using hardware, software, firmware, or a combination thereof. In the description of the above embodiments, specific features, structures, materials, or characteristics can be combined in any suitable manner in one or more embodiments or examples.

[0149] The above description is merely a specific 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.

[0150] This application provides a computer-readable storage medium having computer-readable program instructions (i.e., a computer program) stored thereon, which are used to execute the perforation test parameter inversion method in the above embodiments.

[0151] The computer-readable storage medium provided in this application may be, for example, a USB flash drive, but is not limited to, electrical, magnetic, optical, electromagnetic, infrared, or semiconductor systems or devices, or any combination thereof. More specific examples of computer-readable storage media may include, but are not limited to: electrical connections having one or more wires, portable computer disks, hard disks, random access memory (RAM), read-only memory (ROM), erasable programmable read-only memory (EPROM or flash memory), optical fiber, portable compact disk read-only memory (CD-ROM), optical storage devices, magnetic storage devices, or any suitable combination thereof. In this embodiment, the computer-readable storage medium may be any tangible medium containing or storing a program that can be used by or in conjunction with an instruction execution system or device. The program code contained on the computer-readable storage medium may be transmitted using any suitable medium, including but not limited to: wires, optical cables, RF (Radio Frequency), etc., or any suitable combination thereof.

[0152] The aforementioned computer-readable storage medium may be included in the perforation test parameter inversion equipment; or it may exist independently and not be assembled into the perforation test parameter inversion equipment.

[0153] Computer program code for performing the operations of this application can be written in one or more programming languages ​​or a combination thereof, including object-oriented programming languages ​​such as Java, Smalltalk, and C++, and conventional procedural programming languages ​​such as the "C" language or similar programming languages. The program code can be executed entirely on the user's computer, partially on the user's computer, as a standalone software package, partially on the user's computer and partially on a remote computer, or entirely on a remote computer or server. In cases involving remote computers, the remote computer can be connected to the user's computer via any type of network—including a Local Area Network (LAN) or a Wide Area Network (WAN)—or can be connected to an external computer (e.g., via the Internet using an Internet service provider).

[0154] The flowcharts and block diagrams in the accompanying drawings illustrate the architecture, functionality, and operation of possible implementations of systems, methods, and computer program products according to various embodiments of this application. In this regard, each block in a flowchart or block diagram may represent a module, segment, or portion of code containing one or more executable instructions for implementing a specified logical function. It should also be noted that in some alternative implementations, the functions indicated in the blocks may occur in a different order than those indicated in the drawings. For example, two consecutively indicated blocks may actually be executed substantially in parallel, and they may sometimes be executed in reverse order, depending on the functions involved. It should also be noted that each block in the block diagrams and / or flowcharts, and combinations of blocks in the block diagrams and / or flowcharts, can be implemented using a dedicated hardware-based system that performs the specified function or operation, or using a combination of dedicated hardware and computer instructions.

[0155] The modules described in the embodiments of this application can be implemented in software or hardware. The names of the modules do not necessarily limit the functionality of the unit itself.

[0156] The readable storage medium provided in this application is a computer-readable storage medium, which stores computer-readable program instructions (i.e., computer programs) for executing the perforation test parameter inversion method described above, and can solve the technical problem that existing technologies cannot accurately obtain the true permeability of the original formation. Compared with the prior art, the beneficial effects of the computer-readable storage medium provided in this application are the same as the beneficial effects of the perforation test parameter inversion method provided in the above embodiments, and will not be repeated here.

[0157] This application also provides a computer program product, including a computer program that, when executed by a processor, implements the steps of the perforation test parameter inversion method described above.

[0158] The computer program product provided in this application can solve the technical problem of the inability to accurately obtain the true permeability of the original formation. Compared with the prior art, the beneficial effects of the computer program product provided in this application are the same as those of the perforation test parameter inversion method provided in the above embodiments, and will not be repeated here.

[0159] The above description is only a part of the embodiments of this application and does not limit the patent scope of this application. All equivalent structural transformations made under the technical concept of this application and using the contents of the specification and drawings of this application, or direct / indirect applications in other related technical fields, are included in the patent protection scope of this application.

Claims

1. A method for inverting perforation test parameters, characterized in that, The perforation test parameter inversion method includes: During the target period when there is no seepage interference between adjacent perforations while the well is shut in, acquire pressure data generated by fluid in the wellbore after perforation penetration. Determine the normalized pressure of the pressure data, and the pressure derivative of the normalized pressure; Based on the target pressure derivative, which is a constant value within the target time period, the permeability of the original formation outside the wellbore is obtained by inversion based on the microscopic radial seepage law.

2. The method as described in claim 1, characterized in that, The step of obtaining pressure data generated by the fluid inside the wellbore after perforation penetration includes: Use bottom hole pressure data as pressure data inside the wellbore after perforation penetration; Alternatively, the pressure data at the wellhead can be superimposed with the hydrostatic pressure of the fluid inside the wellbore, and the resulting superposition can be used as the pressure data inside the wellbore after perforation penetration.

3. The method as described in claim 1, characterized in that, The step of determining the normalized pressure of the pressure data includes: Determine the transient pressure drop data within the wellbore based on the pressure data; The equivalent instantaneous flow rate is determined based on the transient pressure drop data; Calculate the ratio of the transient pressure drop data to the equivalent instantaneous flow rate, and use the ratio as the normalized pressure.

4. The method as described in claim 1, characterized in that, The steps for determining the pressure derivative of the normalized pressure include: The pressure derivative of the normalized pressure is obtained by taking the derivative of the normalized pressure with respect to the natural logarithm of time; wherein the time of the natural logarithm of time is the time after the perforation has penetrated.

5. The method as described in claim 1, characterized in that, After determining the pressure derivative of the normalized pressure, the following steps are included: Based on the pressure derivative, a double logarithmic diagnostic chart is plotted; Identify the horizontal plateau of the pressure derivative during the target time period on the double logarithmic diagnostic chart, and read the constant value corresponding to the horizontal plateau, using the constant value as the target pressure derivative.

6. The method as described in claim 1, characterized in that, The step of obtaining the permeability of the original formation outside the wellbore based on the target pressure derivative, which is a constant value during the target time period, and the microscopic radial seepage law includes: Obtain the effective number of perforations in the wellbore, the effective rock penetration length of a single perforation, the fluid volume coefficient, and the fluid viscosity; The permeability of the original formation is calculated according to the microscopic radial seepage law using the target pressure derivative, the effective number of perforations, the effective rock penetration length of a single perforation, the fluid volume coefficient, the fluid viscosity, and a preset coefficient.

7. The method as described in claim 1, characterized in that, After the step of inverting the permeability of the original formation outside the wellbore based on the target pressure derivative, which is a constant value within the target time period, according to the microscopic radial seepage law, the following steps are included: Select at least one characteristic time point within the target time period, and obtain the transient pressure drop data and instantaneous flow data corresponding to the characteristic time point; Based on the permeability of the original formation, the transient pressure drop data, and the instantaneous flow rate data, the micro-skin coefficient of a single pore is calculated.

8. A perforation testing parameter inversion device, characterized in that, The device includes: a memory, a processor, and a computer program stored in the memory and executable on the processor, the computer program being configured to implement the steps of the perforation test parameter inversion method as described in any one of claims 1 to 7.

9. A storage medium, characterized in that, The storage medium is a computer-readable storage medium, and a computer program is stored on the storage medium. When the computer program is executed by a processor, it implements the steps of the perforation test parameter inversion method as described in any one of claims 1 to 7.

10. A computer program product, characterized in that, The computer program product includes a computer program that, when executed by a processor, implements the steps of the perforation test parameter inversion method as described in any one of claims 1 to 7.

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