Stratum damage assessment method, controller and storage medium

Abstract

The invention discloses a stratum damage assessment method, a controller and a storage medium, and the method comprises the steps: firstly, obtaining a plurality of rock core sample sets and a plurality of soaking samples, each rock core sample set comprises a plurality of rock core samples, the plurality of soaking samples are obtained by soaking the plurality of rock core samples in different fracturing fluids for different preset durations, and the plurality of soaking samples are stored in a storage medium; the fracturing fluid types and the preset durations corresponding to the multiple core samples in the same core sample set are different; then, scanning each rock core sample based on micro-CT to determine a corresponding first porosity, and scanning each soaked sample based on micro-CT to determine a corresponding second porosity; and finally, determining the stratum damage degree according to the first porosity and the second porosity. Therefore, the formation damage degree is determined through the first porosity and the second porosity, the formation damage degree of each rock core sample in different fracturing fluid types and different preset duration soaking can be obtained, and the accuracy of evaluating the formation damage degree is improved.

Description

Technical Field

[0001] The invention relates to the technical field of oil extraction, and in particular to a formation damage assessment method, a controller and a storage medium. Background Art

[0002] In related technologies, formation damage refers to the phenomenon that the physical and chemical properties of reservoir rocks change, resulting in a decrease in reservoir permeability, thereby reducing oil and gas production capacity. Traditional formation damage assessment methods are usually based on macro-scale physical simulation experiments and numerical simulations, which have the disadvantages of high cost, low efficiency, and difficulty in obtaining pore-scale information, making it difficult to accurately assess the extent of formation damage. Summary of the invention

[0003] The present application aims to solve at least one of the technical problems existing in the prior art. To this end, the present application proposes a formation damage assessment method, a controller and a storage medium, aiming to improve the accuracy of assessing the degree of formation damage.

[0004] In a first aspect, an embodiment of the present application provides a method for assessing formation damage, comprising: Acquire multiple groups of core sample sets and multiple soaking samples, wherein each group of the core sample sets includes multiple core samples, and the multiple soaking samples are obtained by soaking the multiple core samples in different fracturing fluids for different preset time periods, and the fracturing fluid types and preset time periods corresponding to the multiple core samples in the same group of the core sample sets are different; determining a corresponding first porosity of each of the core samples based on a micro-CT scan, and determining a corresponding second porosity of each of the soaked samples based on a micro-CT scan; The degree of formation damage is determined based on the first porosity and the second porosity.

[0005] According to some embodiments of the present application, the determining the corresponding first porosity of each of the core samples based on micro CT scanning includes: Scan each of the core samples based on micro-CT to obtain a corresponding first image; A first porosity of each of the core samples is determined based on each of the first images.

[0006] According to some embodiments of the present application, determining the first porosity of each of the core samples according to each of the first images includes: determining the pore volume and the total volume of a plurality of the core samples based on each of the first images; The corresponding first porosity is obtained according to the quotient of each pore volume and the total volume.

[0007] According to some embodiments of the present application, the second porosity determined based on micro CT scanning of each of the immersion samples comprises: Scan each of the soaked samples based on micro-CT to obtain a corresponding second image; A second porosity of each of the soaked samples is determined based on each of the second images.

[0008] According to some embodiments of the present application, determining the second porosity of each of the immersion samples according to each of the second images includes: determining the pore volume and the total volume of the plurality of soaked samples according to the respective second images; The second porosity is obtained according to the quotient of each of the pore volumes and the total volume.

[0009] According to some embodiments of the present application, after determining the formation damage degree according to the first porosity and the second porosity, the method includes: The type of the fracturing fluid is determined according to the degree of formation damage.

[0010] According to some embodiments of the present application, the method further includes: Acquiring simulation parameters, parameters of the fracturing fluid and boundary conditions; constructing a first three-dimensional model based on the first image; constructing a second three-dimensional model based on the second image; constructing a simulation model according to the first three-dimensional model, the second three-dimensional model, the parameters of the fracturing fluid and the boundary conditions; Simulating the flowback process by using the simulation model and the simulation parameters to obtain simulation results; The well shut-in time is determined according to the simulation results.

[0011] According to some embodiments of the present application, the simulation parameters include simulation time and grid size; the simulation time corresponds to a preset soaking time of each of the soaking samples.

[0012] In a second aspect, an embodiment of the present application provides a controller comprising: a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes a formation damage assessment method according to the first aspect when running the computer program.

[0013] In a third aspect, an embodiment of the present application provides a computer-readable storage medium storing computer-executable instructions, wherein the computer-executable instructions are used to execute a formation damage assessment method as described in the first aspect above.

[0014] According to some embodiments of the present application, according to the technical scheme of the embodiments of the present application, at least the following beneficial effects are achieved: the present application discloses a method, a controller and a storage medium for assessing formation damage, the method comprising: first, acquiring multiple groups of core sample sets and multiple immersion samples, wherein each group of core sample sets comprises multiple core samples, the multiple immersion samples are obtained by immersing multiple core samples in different fracturing fluids for different preset time periods, and the multiple core samples in the same group of core sample sets correspond to different fracturing fluid types and preset time periods; then, determining the corresponding first porosity of each core sample based on microCT scanning, and determining the corresponding second porosity of each immersion sample based on microCT scanning; finally, determining the degree of formation damage based on the first porosity and the second porosity; therefore, the embodiment of the present application determines the degree of formation damage by the first porosity of each core sample and the second porosity of each immersion sample, and can obtain the degree of formation damage of each core sample under different fracturing fluid types and different preset immersion time periods, thereby improving the accuracy of assessing the degree of formation damage.

[0015] Additional aspects and advantages of the present application will be given in part in the description below, and in part will become apparent from the description below, or will be learned through the practice of the present application. BRIEF DESCRIPTION OF THE DRAWINGS

[0016] The accompanying drawings are used to provide further understanding of the technical solution of the present application and constitute a part of the specification. Together with the embodiments of the present application, they are used to explain the technical solution of the present application and do not constitute a limitation on the technical solution of the present application.

[0017] Figure 1 is a flow chart of a formation damage assessment method provided by an embodiment of the present application; Figure 2 is a flow chart of a formation damage assessment method provided by another embodiment of the present application; Figure 3 is a flow chart of a formation damage assessment method provided by another embodiment of the present application; Figure 4 is a flow chart of a formation damage assessment method provided by another embodiment of the present application; Figure 5 is a flow chart of a formation damage assessment method provided by another embodiment of the present application; Figure 6 is a flow chart of a formation damage assessment method provided by another embodiment of the present application; Figure 7 It is a schematic diagram of the structure of a controller for executing a formation damage assessment method provided in one embodiment of the present application. DETAILED DESCRIPTION

[0018] The embodiments of the present application are described in detail below, and examples of the embodiments are shown in the accompanying drawings, wherein the same or similar reference numerals throughout represent the same or similar elements or elements having the same or similar functions. The embodiments described below with reference to the accompanying drawings are exemplary and are only used to explain the present application, and cannot be understood as limiting the present application.

[0019] In the description of the present application, it should be understood that descriptions involving orientation, such as up, down, front, back, left, right, etc., indicating orientations or positional relationships, are based on the orientations or positional relationships shown in the accompanying drawings, and are only for the convenience of describing the present application and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, be constructed and operated in a specific orientation, and therefore should not be understood as a limitation on the present application.

[0020] In the description of this application, "several" means one or more, "more" means more than two, "greater than", "less than", "exceed", etc. are understood to exclude the number itself, and "above", "below", "within", etc. are understood to include the number itself. If there is a description of "first" or "second", it is only used for the purpose of distinguishing technical features, and cannot be understood as indicating or implying relative importance or implicitly indicating the number of the indicated technical features or implicitly indicating the order of the indicated technical features.

[0021] In the description of this application, unless otherwise clearly defined, terms such as setting, installing, connecting, etc. should be understood in a broad sense, and technicians in the relevant technical field can reasonably determine the specific meanings of the above terms in this application based on the specific content of the technical solution.

[0022] In some cases, formation damage refers to changes in the physical and chemical properties of reservoir rocks, which lead to reduced reservoir permeability and thus reduced oil and gas production capacity. Traditional formation damage assessment methods are usually based on macro-scale physical simulation experiments and numerical simulations, which have the disadvantages of high cost, low efficiency, and difficulty in obtaining pore-scale information, making it difficult to accurately assess the extent of formation damage.

[0023] Based on this, the present application proposes a formation damage assessment method, a controller and a storage medium, aiming to improve the accuracy of assessing the degree of formation damage.

[0024] The following further describes various embodiments of the formation damage assessment method of the present application in conjunction with the accompanying drawings.

[0025] like Figure 1 As shown, Figure 1 It is a flow chart of a formation damage assessment method provided by an embodiment of the present application; the control method includes but is not limited to step S110, step S120 and step S130.

[0026] Step S110, obtaining multiple groups of core sample sets and multiple soaking samples, wherein each group of core sample sets includes multiple core samples, and the multiple soaking samples are obtained by soaking the multiple core samples in different fracturing fluids for different preset time periods, and the fracturing fluid types and preset time periods corresponding to the multiple core samples in the same group of core sample sets are different; Step S120, determining the corresponding first porosity of each core sample based on micro CT scanning, and determining the corresponding second porosity of each immersed sample based on micro CT scanning; Step S130: determine the formation damage degree according to the first porosity and the second porosity.

[0027] In one embodiment, first, the embodiment of the present application obtains multiple groups of core sample sets and multiple immersion samples, wherein each group of core sample sets includes multiple core samples, and the multiple immersion samples are obtained by immersing the multiple core samples in different fracturing fluids for different preset time periods, and the fracturing fluid types and preset time periods corresponding to the multiple core samples in the same group of core sample sets are different; then, the embodiment of the present application scans each core sample based on microCT to obtain the corresponding first porosity, and scans each immersion sample based on microCT to obtain the corresponding second porosity; finally, the embodiment of the present application determines the degree of formation damage according to the first porosity and the second porosity; therefore, the embodiment of the present application determines the degree of formation damage by the first porosity of each core sample and the second porosity of each immersion sample, and can obtain the degree of formation damage of each core sample under different fracturing fluid types and different preset immersion time periods, thereby improving the accuracy of assessing the degree of formation damage.

[0028] Exemplarily, two groups of core sample sets are obtained, each group of core sample sets includes 3 core samples, and the corresponding first porosity of each core sample is obtained based on micro-CT scanning; then, the 3 core samples in each group of core sample sets are respectively immersed in 3 types of fracturing fluids and immersed for different preset time periods, and the corresponding second porosity of each immersed core sample is obtained based on micro-CT scanning; finally, the formation damage layer degree is determined based on the first porosity and the second porosity, so that the formation damage degree of each core sample under different fracturing fluid types and different preset immersion time conditions can be obtained, thereby improving the accuracy of assessing the formation damage degree.

[0029] It is understandable that the above core sample sets may be 2 or 3, and may be set according to actual conditions, and the embodiments of the present application do not specifically limit them.

[0030] It is understandable that the number of core samples included in each group of core sample sets mentioned above may be 3 or 4, which can be set according to actual conditions, and the embodiments of the present application do not make any specific limitation thereto.

[0031] It is understandable that the above-mentioned fracturing fluid types may include surfactants, polymers and guar gum, which can be set according to actual conditions and are not specifically limited in the embodiments of the present application.

[0032] It can be understood that the above-mentioned preset time can be 2 hours, 6 hours, 12 hours, 1 day, 2 days, 3 days, 7 days, or 15 days, and can be set according to actual conditions. The embodiments of the present application do not specifically limit it.

[0033] Specifically, Figure 2 As shown, Figure 2 It is a flow chart of a formation damage assessment method provided by another embodiment of the present application; regarding the determination of the corresponding first porosity of each core sample based on micro-CT scanning in the above-mentioned step S120, it includes but is not limited to step S210 and step S220.

[0034] Step S210, scanning each core sample based on micro-CT to obtain a corresponding first image; Step S220: determining the first porosity of each core sample according to each first image.

[0035] In one embodiment, the embodiment of the present application obtains the corresponding first image by scanning each core sample through micro CT, and thus obtains the first porosity corresponding to each core sample by calculation according to each first image.

[0036] Specifically, Figure 3 As shown, Figure 3 It is a flow chart of a formation damage assessment method provided by another embodiment of the present application; regarding the above-mentioned step S220, it includes but is not limited to step S310 and step S320.

[0037] Step S310, determining the pore volume and total volume of multiple core samples according to each first image; Step S320: Obtain a corresponding first porosity according to the quotient of each pore volume and the total volume.

[0038] In one embodiment, the embodiment of the present application can obtain the pore volume and total volume corresponding to multiple core samples through each first image, so as to obtain the corresponding first porosity through the quotient of each pore volume and the total volume.

[0039] It is understandable that the first image of each core sample has corresponding pore volume and total volume, so that the corresponding pore volume and total volume can be obtained through the first image of the core sample, and then the corresponding first porosity can be obtained according to the quotient of the pore volume and the total volume.

[0040] Specifically, Figure 4 As shown, Figure 4 It is a flow chart of a formation damage assessment method provided by another embodiment of the present application; regarding the determination of the corresponding second porosity of each immersion sample based on micro-CT scanning in the above-mentioned step S120, it includes but is not limited to step S410 and step S420.

[0041] Step S410, scanning each immersed sample based on micro CT to obtain a corresponding second image; Step S420: determining the second porosity of each soaked sample according to each second image.

[0042] In one embodiment, the embodiment of the present application obtains the corresponding second image by scanning each soaked sample through micro CT, and then calculates the second porosity corresponding to each soaked sample according to each second image.

[0043] Specifically, Figure 5 As shown, Figure 5 It is a flow chart of a formation damage assessment method provided by another embodiment of the present application; regarding the above-mentioned step S420, it includes but is not limited to step S510 and step S520.

[0044] Step S510, determining the pore volume and total volume of a plurality of immersed samples according to each second image; Step S520: Obtain a second porosity according to the quotient of each pore volume and the total volume.

[0045] In one embodiment, the embodiment of the present application can obtain the pore volumes and total volumes corresponding to the multiple soaked samples through each second image, and thus obtain the corresponding second porosity through the quotient of each pore volume and the total volume.

[0046] It is understandable that each second image of the soaked sample has a corresponding pore volume and total volume, so that the corresponding pore volume and total volume can be obtained through the second image of the soaked sample, and then the corresponding second porosity can be obtained according to the quotient of the pore volume and the total volume.

[0047] Specifically, after the above step S130, the formation damage assessment method further includes but is not limited to the following steps: determining the type of fracturing fluid according to the degree of formation damage.

[0048] It is understandable that the degree of damage to different core sample sets in different fracturing fluids can be determined based on the degree of formation damage, so that the fracturing fluid with the least damage to the core sample set can be determined, and then the fracturing fluid is determined as the type of fracturing fluid for the core sample set.

[0049] Specifically, Figure 6 As shown, Figure 6It is a flow chart of a formation damage assessment method provided by another embodiment of the present application; the formation damage assessment method also includes but is not limited to step S610, step S620, step S630, step S640, step S650 and step S660.

[0050] Step S610, obtaining simulation parameters, fracturing fluid parameters and boundary conditions; Step S620: constructing a first three-dimensional model according to the first image; Step S630: constructing a second three-dimensional model according to the second image; Step S640, constructing a simulation model according to the first three-dimensional model, the second three-dimensional model, the parameters of the fracturing fluid and the boundary conditions; Step S650, simulating the flowback process by using the simulation model and simulation parameters to obtain simulation results; Step S660: Determine the well shut-in time according to the simulation results.

[0051] In one embodiment, the embodiment of the present application acquires simulation parameters, parameters of the fracturing fluid and boundary conditions; then, a corresponding first three-dimensional model is constructed according to the first image corresponding to each core sample, and a corresponding second three-dimensional model is constructed according to the second image corresponding to each immersed sample; then, a simulation model is constructed according to the first three-dimensional model corresponding to the core sample, the second three-dimensional model corresponding to the immersed sample, the parameters of the fracturing fluid and boundary conditions, so as to simulate the flowback process according to the simulation model and the simulation parameters to obtain a simulation result, and then determine the corresponding shut-in time according to the residual oil saturation and / or fluid distribution of the simulation result.

[0052] It can be understood that in a simulation model, the immersion sample corresponding to the second three-dimensional model is obtained by immersing the core sample corresponding to the first three-dimensional model in the fracturing fluid for a preset time, wherein the parameters of the fracturing fluid are the parameters corresponding to the fracturing fluid in which the core sample corresponding to the first three-dimensional model is immersed.

[0053] It can be understood that by determining the shut-in time according to the simulation results, the shut-in time can be shortened while minimizing the damage to the formation.

[0054] It is understandable that the parameters of the above-mentioned fracturing fluid may be density, viscosity, or density and viscosity, and may be selected according to actual conditions. The embodiments of the present application do not make specific settings for them.

[0055] It can be understood that the above-mentioned simulation parameters can be simulation time, grid size, or simulation time and grid size, which can be selected according to actual conditions. The embodiments of the present application do not make specific settings for them.

[0056] It can be understood that the simulation time corresponds to the preset soaking time of each soaking sample.

[0057] Based on the formation damage assessment methods of the above-mentioned various embodiments, an overall embodiment of the formation damage assessment method of the present application is proposed below.

[0058] (1) Core sample preparation Six microcore samples with physical dimensions of 10-20 mm³ were drilled from the study area.

[0059] The core samples were scanned using a micro-CT scanning device with a resolution set to 0.5 μm.

[0060] Image processing software was used to preprocess CT images, including noise removal and contrast enhancement.

[0061] An independently developed trainable segmentation software was used to perform threshold segmentation on the CT images, segment the images into pores and rock skeletons, and construct a 3D model.

[0062] The porosity and permeability of the core samples were calculated and compared with laboratory measurements to verify the accuracy of the segmentation results.

[0063] (2) Immersion test The core samples were divided into two groups, corresponding to the core samples from the two wells.

[0064] Three different types of fracturing fluids were prepared: surfactant, polymer, and guar.

[0065] The three core samples in each group were immersed in three different fracturing fluids for 2 h, 6 h, 12 h, 1 day, 2 days and 3 days, respectively.

[0066] During the soaking process, the temperature and pressure were kept stable to simulate reservoir conditions.

[0067] (3) Image analysis The core samples after immersion were subjected to micro-CT scanning with a resolution set to 0.5 μm.

[0068] The immersion CT images were processed using the same image processing software and segmentation software, and the 3D model was constructed.

[0069] The 3D model after immersion was compared with the original model to observe the changes in the pore structure.

[0070] The porosity of the core samples after immersion was calculated and compared with the original porosity to quantify the extent of formation damage.

[0071] (4) Porosity calculation Use image processing software or segmentation software to calculate the porosity of the core sample, which is the ratio of the pore volume to the total volume.

[0072] Calculation formula: Porosity = pore volume / total volume.

[0073] (5) Fracturing fluid optimization Based on the porosity change results, the type of fracturing fluid that causes the least damage to the core sample is selected.

[0074] For example, for the core sample of Well A, guar gum has the least damage, so guar gum is selected as the fracturing fluid of Well A.

[0075] For the core sample of Well B, the surfactant caused the least damage, so the surfactant was selected as the fracturing fluid for Well B.

[0076] (6) Fluid simulation The Lattice Boltzmann method was used to simulate the flowback process and evaluate the residual oil saturation.

[0077] A simulation model is established, including a 3D model of the core sample, fluid property parameters (e.g., density, viscosity, etc.) and boundary conditions.

[0078] Set simulation parameters, such as simulation time, grid size, etc.

[0079] Run the simulation program and analyze the simulation results, including residual oil saturation, fluid distribution, etc.

[0080] (7) Optimization of well shut-in time According to the simulation results, the best shut-in time is selected, that is, the shut-in time is shortened as much as possible while ensuring the minimum damage to the formation.

[0081] For example, for well A, the optimal shut-in time is 6 hours; for well B, the optimal shut-in time is 1 day.

[0082] (8) Result verification Compare the simulation results with the actual production data to verify the accuracy of the simulation results.

[0083] For example, the simulated residual oil saturation is compared with the residual oil saturation in the actual production data.

[0084] (9) Application Based on the optimized fracturing fluid and shut-in time, it guides on-site fracturing operations to improve oil and gas production capacity and recovery rate.

[0085] It can be understood that the embodiments of the present application can obtain core data at the pore scale, so as to more accurately assess the degree of formation damage; in addition, the embodiments of the present application can guide the selection of fracturing fluid and on-site fracturing operations based on the porosity changes and residual oil saturation results.

[0086] like Figure 7 As shown, Figure 7 700 is a schematic diagram of a controller for executing a formation damage assessment method provided by an embodiment of the present application. The controller 700 implemented in the present application includes: a processor 710, a memory 720, and a computer program stored in the memory 720 and executable on the processor 710, wherein: Figure 7 In the figure, a processor 710 and a memory 720 are taken as an example.

[0087] The processor 710 and the memory 720 may be connected via a bus or other means. Figure 7 The example of connecting through bus is taken in the following.

[0088] The memory 720, as a non-transitory computer-readable storage medium, can be used to store non-transitory software programs and non-transitory computer executable programs. In addition, the memory 720 may include a high-speed random access memory, and may also include a non-transitory memory, such as at least one disk storage device, a flash memory device, or other non-transitory solid-state storage device. In some embodiments, the memory 720 optionally includes a memory 720 remotely arranged relative to the processor 710, and these remote memories 720 can be connected to the controller 700 via a network. Examples of the above-mentioned network include, but are not limited to, the Internet, an intranet, a local area network, a mobile communication network, and combinations thereof.

[0089] Those skilled in the art will understand that Figure 7 The device structure shown in the figure does not constitute a limitation on the controller 700, and may include more or less components than shown in the figure, or combine certain components, or arrange the components differently.

[0090] exist Figure 7 In the controller 700 shown, the processor 710 can be used to call the control program stored in the memory 720, so as to implement the above-mentioned formation damage assessment method. Specifically, the non-transient software program and instructions required to implement the formation damage assessment method of the above-mentioned embodiment are stored in the memory 720, and when executed by the processor 710, the formation damage assessment method of the above-mentioned embodiment is executed.

[0091] It is worth noting that since the controller 700 of the embodiment of the present application can execute the formation damage assessment method of any of the above-mentioned embodiments, the specific implementation manner and technical effects of the controller 700 of the embodiment of the present application can refer to the specific implementation manner and technical effects of the formation damage assessment method of any of the above-mentioned embodiments.

[0092] In addition, an embodiment of the present application further provides a computer-readable storage medium, which stores computer-executable instructions, and the computer-executable instructions are used to execute the above-mentioned formation damage assessment method. Figures 1 to 6 The method steps in .

[0093] It is worth noting that since the computer-readable storage medium of the embodiment of the present application can execute the formation damage assessment method of any of the above-mentioned embodiments, the specific implementation methods and technical effects of the computer-readable storage medium of the embodiment of the present application can refer to the specific implementation methods and technical effects of the formation damage assessment method of any of the above-mentioned embodiments.

[0094] It will be appreciated by those skilled in the art that all or some of the steps and systems in the methods disclosed above may be implemented as software, firmware, hardware, and appropriate combinations thereof. Some or all physical components may be implemented as software executed by a processor, such as a central processing unit, a digital signal processor, or a microprocessor, or as hardware, or as an integrated circuit, such as an application-specific integrated circuit. Such software may be distributed on a computer-readable medium, which may include a computer storage medium (or non-transitory medium) and a communication medium (or transient medium). As known to those skilled in the art, the term computer storage medium includes volatile and non-volatile, removable and non-removable media implemented in any method or technology for storing information (such as computer-readable instructions, data structures, program modules, or other data). Computer storage media include, but are not limited to, RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disk (DVD) or other optical disk storage, magnetic cassettes, magnetic tapes, disk storage or other magnetic storage devices, or any other medium that can be used to store desired information and can be accessed by a computer. Furthermore, it is well known to those skilled in the art that communication media typically include computer readable instructions, data structures, program modules, or other data in a modulated data signal such as a carrier wave or other transport mechanism, and may include any information delivery media.

[0095] The above is a specific description of the preferred implementation of the present application, but the present application is not limited to the above implementation mode. Technical personnel familiar with the field can also make various equivalent modifications or substitutions under the shared conditions without violating the spirit of the present application. These equivalent modifications or substitutions are all included in the scope defined by the claims of the present application.

Claims

1. A method for assessing formation damage, characterized in that: include: Acquire multiple groups of core sample sets and multiple soaking samples, wherein each group of the core sample sets includes multiple core samples, and the multiple soaking samples are obtained by soaking the multiple core samples in different fracturing fluids for different preset time periods, and the fracturing fluid types and preset time periods corresponding to the multiple core samples in the same group of the core sample sets are different; determining a corresponding first porosity of each of the core samples based on a micro-CT scan, and determining a corresponding second porosity of each of the soaked samples based on a micro-CT scan; The degree of formation damage is determined based on the first porosity and the second porosity.

2. A formation damage assessment method according to claim 1, characterized in that: The determining the corresponding first porosity of each core sample based on micro CT scanning includes: Scan each of the core samples based on micro-CT to obtain a corresponding first image; A first porosity of each of the core samples is determined based on each of the first images.

3. A formation damage assessment method according to claim 2, characterized in that: Determining the first porosity of each of the core samples according to each of the first images comprises: determining the pore volume and the total volume of a plurality of the core samples based on each of the first images; The corresponding first porosity is obtained according to the quotient of each pore volume and the total volume.

4. A formation damage assessment method according to claim 2, characterized in that: The second porosity determined based on micro CT scanning of each of the soaked samples comprises: Scan each of the soaked samples based on micro-CT to obtain a corresponding second image; A second porosity of each of the soaked samples is determined based on each of the second images.

5. A formation damage assessment method according to claim 4, characterized in that: The determining the second porosity of each of the soaked samples according to each of the second images comprises: determining the pore volume and the total volume of the plurality of soaked samples according to the respective second images; The second porosity is obtained according to the quotient of each of the pore volumes and the total volume.

6. A formation damage assessment method according to claim 1, characterized in that: After determining the formation damage degree according to the first porosity and the second porosity, the method includes: The type of the fracturing fluid is determined according to the degree of formation damage.

7. A formation damage assessment method according to claim 4, characterized in that: The method further comprises: Acquiring simulation parameters, parameters of the fracturing fluid and boundary conditions; constructing a first three-dimensional model based on the first image; constructing a second three-dimensional model based on the second image; constructing a simulation model according to the first three-dimensional model, the second three-dimensional model, the parameters of the fracturing fluid and the boundary conditions; Simulating the flowback process by using the simulation model and the simulation parameters to obtain simulation results; The well shut-in time is determined according to the simulation results.

8. A formation damage assessment method according to claim 7, characterized in that: The simulation parameters include simulation time and grid size; the simulation time corresponds to the preset soaking time of each soaking sample.

9. A controller, characterized in that: include: A memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes a formation damage assessment method as claimed in any one of claims 1 to 8 when executing the computer program.

10. A computer-readable storage medium, characterized in that: Computer executable instructions are stored, and the computer executable instructions are used to execute a formation damage assessment method as described in any one of claims 1 to 8.

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