Detection method, system, equipment and medium for oil-water two-phase relative permeability curve

Abstract

The invention discloses a method, a system, equipment and a medium for detecting an oil-water two-phase relative permeability curve, and belongs to the technical field of oil-gas field development technologies. The detection method of the oil-water two-phase relative permeability curve comprises the following steps: washing oil and drying a rock core sample, vacuumizing the rock core sample, and injecting formation water into the rock core sample, so that the rock core sample reaches a saturated water state; injecting crude oil into the core sample at a preset oil reservoir temperature to enable the core sample to reach a saturated oil state; performing water-displacing oil operation on the rock core sample at a preset flow rate, and scanning the rock core sample at a plurality of scanning nodes by using a CT (Computed Tomography) scanning device; oil saturation and water saturation are calculated according to an actually measured rock core CT value, and parameter fitting is performed on the Corey model according to the oil saturation and the water saturation to obtain an oil-water two-phase relative permeability curve. The method can accurately detect the oil-water two-phase relative permeability curve of the rock core.

Description

Technical Field

[0001] This application relates to the field of oil and gas field development technology, and in particular to a method, system, equipment and medium for detecting the relative permeability curve of oil and water two phases. Background Technology

[0002] The relative permeability curves of oil and water phases are the core foundation for characterizing multiphase flow patterns in reservoir engineering. Their accuracy directly determines the success or failure of oilfield development dynamic prediction, development scheme optimization, and the formulation of enhanced oil recovery strategies.

[0003] In the oil and gas industry, the determination of relative permeability mainly relies on laboratory core displacement experiments, especially unsteady-state and steady-state methods. However, these methods indirectly obtain relative permeability curves, requiring analysis or numerical interpretation techniques to deduce the curves from the produced fluid volume and pressure difference data at both ends of the core. The indirect nature of these methods leads to inherent uncertainties and non-uniqueness in the obtained curves. Furthermore, traditional steady-state and unsteady-state methods require calculations based on pressure and flow data at the core end face, and the results are susceptible to the effects of core end effect and saturation averaging.

[0004] Therefore, how to accurately detect the relative permeability curves of the oil and water phases in the core is a technical problem that needs to be solved by those skilled in the art. Summary of the Invention

[0005] The purpose of this application is to provide a method, system, equipment and medium for detecting the relative permeability curves of oil and water phases, which can accurately detect the relative permeability curves of oil and water phases in core samples.

[0006] To solve the above-mentioned technical problems, this application provides a method for detecting the relative permeability curve of an oil-water two-phase system, comprising: The core sample was washed with oil and dried. The core sample was then vacuumed and injected with formation water to bring it to a water-saturated state. At a preset reservoir temperature, crude oil is injected into the core sample to saturate the core sample with oil. The core sample is subjected to water flooding at a preset flow rate, and the core sample is scanned at multiple scanning nodes using a CT scanning device to obtain the measured core CT value corresponding to each scanning node; wherein, the scanning node is a time node related to the displacement void volume. The oil saturation and water saturation corresponding to each scanning node are calculated based on the measured core CT values. The Corey model is then fitted with parameters based on the oil saturation and water saturation to obtain the relative permeability curves of the oil and water phases.

[0007] Optionally, the oil saturation and water saturation corresponding to each scanning node are calculated based on the measured core CT values, including: Substitute the measured core CT value corresponding to each scanning node into the first preset formula to obtain the oil saturation. Substituting the oil saturation into the second preset formula, we obtain the water saturation; The first preset formula is: The second preset formula is: ; Indicates oil saturation. This indicates the CT value of a core sample containing saturated formation water. This represents the measured core CT value. Indicates the formation water CT value. This indicates the CT value of crude oil. Indicates the air CT value, Indicates the CT value of dry core. Indicates water saturation.

[0008] Optionally, the Corey model is fitted with parameters based on the oil saturation and water saturation to obtain the relative permeability curves of the oil and water phases, including: The oil yield is determined based on the oil saturation, and the water yield is determined based on the water saturation. The water content corresponding to each scanning node is determined based on the oil production and the water production. The Corey model was fitted with parameters using the water content and water saturation corresponding to all the scanning nodes to obtain the relative permeability curves of the oil phase and the relative permeability curves of the water phase.

[0009] Optionally, the Corey model is fitted with parameters using the water content and water saturation corresponding to all the scan nodes to obtain the relative permeability curves of the oil phase and the water phase, including: Determine the formulas for calculating the relative permeability of the oil phase and the relative permeability of the water phase corresponding to the Corey model; wherein, the formula for calculating the relative permeability of the oil phase is as follows: The formula for calculating the relative permeability of the aqueous phase is as follows: , Indicates the relative permeability of the oil phase. This represents the relative permeability of the oil phase at the bound water saturation level. Indicates residual oil saturation. Indicates water saturation. Indicates the degree of bound water saturation. Indicates the first unknown coefficient. Indicates the relative permeability of the water phase. This represents the relative permeability of the aqueous phase at residual oil saturation. Indicates the second unknown coefficient; A third preset formula is constructed; wherein, the third preset formula is a formula used to describe the relationship between water content, relative permeability of the oil phase and relative permeability of the water phase; Substitute the water content and water saturation corresponding to all the scanning nodes into the oil phase relative permeability calculation formula, the water phase relative permeability calculation formula and the third preset formula, and fit and calculate the values ​​of the first unknown coefficient and the second unknown coefficient; The relative permeability curve of the oil phase is determined based on the first unknown coefficient and the calculation formula for the relative permeability of the oil phase. The relative permeability curve of the water phase is determined based on the second unknown coefficient and the formula for calculating the relative permeability of the water phase.

[0010] Optionally, the expression of the third preset formula is: ; in, Indicates moisture content, Indicates the viscosity of formation water. This indicates the viscosity of crude oil.

[0011] Optionally, before performing waterflooding on the core sample at a preset flow rate, and after injecting crude oil into the core sample to saturate it with oil, the process further includes: The core samples were subjected to aging treatment; After the aging process was completed, the relative permeability of the oil phase under the bound water saturation of the core sample was measured.

[0012] Optionally, after washing and drying the core samples, the following steps may also be taken: The porosity and permeability of the core sample are obtained, and multiple scanning nodes are determined based on the porosity and permeability.

[0013] This application also provides a system for detecting the relative permeability curves of an oil-water two-phase system, the system comprising: The pretreatment module is used to wash and dry the core sample, vacuum the core sample and inject formation water to make the core sample saturated with water; it is also used to inject crude oil into the core sample at a preset reservoir temperature to make the core sample saturated with oil. The testing module is used to perform water flooding operation on the core sample at a preset flow rate, and to scan the core sample at multiple scanning nodes using a CT scanning device to obtain the measured core CT value corresponding to each scanning node; wherein, the scanning node is a time node related to the displacement void volume. The calculation module is used to calculate the oil saturation and water saturation corresponding to each scanning node based on the measured core CT value, and to perform parameter fitting on the Corey model based on the oil saturation and water saturation to obtain the relative permeability curve of the oil and water phases.

[0014] This application also provides a storage medium storing a computer program thereon, which, when executed, performs the steps of the above-described method for detecting the relative permeability curves of oil and water phases.

[0015] This application also provides an electronic device, including a memory and a processor, wherein the memory stores a computer program, and the processor, when calling the computer program in the memory, implements the steps of the above-described method for detecting the relative permeability curve of oil and water phases.

[0016] This application provides a method for detecting the relative permeability curve of oil-water two-phase flow, comprising: washing and drying a core sample; evacuating the core sample and injecting formation water to saturate the core sample with water; injecting crude oil into the core sample at a preset reservoir temperature to saturate the core sample with oil; performing water-drive oil operation on the core sample at a preset flow rate; and scanning the core sample at multiple scanning nodes using a CT scanning device to obtain the measured core CT value corresponding to each scanning node; wherein the scanning node is a time node related to the displacement void volume; calculating the oil saturation and water saturation corresponding to each scanning node based on the measured core CT value; and fitting the parameters of the Corey model based on the oil saturation and water saturation to obtain the relative permeability curve of oil-water two-phase flow.

[0017] This application discloses a method for detecting the relative permeability curve of oil and water phases. The method involves washing, drying, vacuuming, and injecting formation water into core samples to obtain core samples in a water-saturated state. Furthermore, crude oil is injected into the core samples at a preset reservoir temperature to restore wettability, resulting in core samples in an oil-saturated state. The method also incorporates a CT scanning device to scan the core samples at multiple displacement nodes, obtaining the measured CT value for each scanning node. Based on the measured CT values, the oil saturation and water saturation corresponding to each scanning node are calculated. Then, the Corey model is fitted with parameters based on the oil saturation and water saturation to obtain the relative permeability curve of the oil and water phases. The measured core CT values ​​reflect the true internal structure of the core sample. The above process anchors the parameters of the Corey model to the intuitive measured core CT values, realizing the generation of the relative permeability curve of the oil and water phases based on the true internal structure of the core sample. Compared to the indirect calculation method in conventional schemes, this application can accurately detect the relative permeability curve of the oil and water phases in the core. This application also provides a detection system for the relative permeability curve of oil and water phases, a storage medium, and an electronic device, which have the above-mentioned beneficial effects, and will not be elaborated here. Attached Figure Description

[0018] To more clearly illustrate the embodiments of this application, the accompanying drawings used in the embodiments will be briefly introduced below. Obviously, the drawings described below are only some embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0019] Figure 1 A flowchart illustrating a method for detecting the relative permeability curve of an oil-water two-phase system provided in an embodiment of this application; Figure 2 This is a schematic diagram of the structure of an in-situ CT scanning core displacement experimental device provided in an embodiment of this application; Figure 3 This is a schematic diagram of a CT core slice provided in an embodiment of this application; Figure 4 This is a profile of water saturation at different displacement stages of the core sample. Figure 5 This is a schematic diagram of the relative permeability curve of an oil-water two-phase system provided in an embodiment of this application; Figure 6 This is a comparison chart of the relative permeability curves of oil and water between this embodiment and a conventional solution, provided as an example of this application. Detailed Implementation

[0020] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this application, not all embodiments. Based on the embodiments of this application, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this application.

[0021] CT scanning technology, as a non-destructive testing and visualization tool, leverages the principles of X-ray computed tomography (CT) imaging to perform high-resolution three-dimensional scanning and imaging of core samples and near-wellbore formations. This advances traditionally opaque rock physics and seepage research into a new stage of transparency, quantification, and mechanistic understanding. A major application of CT technology is the direct quantification of saturation profiles in core displacement experiments. Unlike traditional methods that only provide average or outlet saturation, CT scanning can obtain continuous, spatially resolved saturation distribution maps along the core length. This allows researchers to directly observe the saturation front, identify heterogeneous flow paths, and accurately calculate in-situ saturation at any time and location. Because CT scanning technology can non-destructively, in-situ, and in real-time acquire the spatial distribution of three-dimensional saturation within the core during displacement, it makes it possible to directly calculate more accurate relative permeability curves, greatly deepening the understanding of the dynamics and heterogeneous effects of the displacement front.

[0022] In the oil and gas industry, researchers follow the standard "Method for Determining Relative Permeability of Two-Phase Fluids in Rocks" (GB / T 28912-2012) to measure oil-water relative permeability curves. This standard primarily employs steady-state and unsteady-state methods to obtain these curves. However, this method has specific limitations and problems both practically and theoretically. From an experimental principle perspective, the unsteady-state method obtains data by injecting one fluid to displace another, its biggest advantage being its speed. However, this method typically ignores the influence of capillary pressure during data processing. This simplification may have little impact on rock samples with good homogeneity and high permeability, but for reservoirs with low permeability or strong heterogeneity, capillary forces are significant. Ignoring this effect can lead to abnormal shapes in the calculated relative permeability curves, especially the water phase curve, such as humps that do not conform to physical laws. Furthermore, the effective data points obtained by the unsteady-state method are mainly concentrated in the post-breakthrough stage, with relatively limited coverage of the saturation range. The calculation results are also heavily dependent on subsequent mathematical processing models, and the assumptions and limitations of the models themselves are directly transmitted to the results. In contrast, the steady-state method, which injects oil and water simultaneously at a fixed ratio until the system reaches equilibrium, is most notably time-consuming. This method requires achieving a stable pressure and saturation profile at each set saturation point, a process that can take days or even longer. However, with proper experimental design, the steady-state method can systematically cover a wider range of water saturation levels, obtaining more data points. Nevertheless, the quality of the steady-state method's experimental results is highly dependent on the precision of the experimental design and the accuracy of the equilibrium determination; deviations in any step can cause the obtained curves to deviate from reality. For special reservoir conditions (such as tight, shale, strongly hydrophilic, or highly heterogeneous reservoirs), both standard methods face even greater challenges. Besides the aforementioned anomalies caused by capillary end effects in the unsteady-state method, the heterogeneity of the core leads to an uneven displacement front and premature water exposure at the outlet. Furthermore, improper selection of the displacement rate, failure to overcome capillary forces, or triggering fingering can all distort the experimental results, making it impossible to obtain reliable relative permeability curves by directly applying standard methods.

[0023] To address the shortcomings of the aforementioned related technologies, this embodiment provides a method for detecting the relative permeability curve of oil and water phases, which can accurately detect the relative permeability curve of oil and water phases in core samples.

[0024] Please see below. Figure 1 , Figure 1 This is a flowchart illustrating a method for detecting the relative permeability curve of an oil-water two-phase system, as provided in an embodiment of this application.

[0025] Specific steps may include: S101: Wash and dry the core sample, vacuum the core sample and inject formation water to make the core sample saturated with water.

[0026] This embodiment can be applied to electronic devices (such as in-situ CT scanning core displacement experimental devices) that possess core pretreatment, CT scanning, and data calculation functions. These electronic devices include related equipment for implementing the aforementioned functions. The core pretreatment functions include operations such as oil washing, drying, vacuuming, injection of formation water, and injection of crude oil.

[0027] This step involves washing away the original oil in the core sample, followed by drying to remove moisture and volatiles. After the core sample is dried, a vacuum can be created to remove air from the pores, and formation water can be injected to fully fill the pores of the core sample, thus saturating it with water.

[0028] Saturated water state refers to a fluid saturation state in which all interconnected pore spaces in the core are completely filled with water, without any oil or gas phases.

[0029] S102: At a preset reservoir temperature, crude oil is injected into the core sample to saturate the core sample with oil.

[0030] In this step, after the core sample reaches a water-saturated state, the temperature of the area where the core sample is located can be set to a preset reservoir temperature. The preset reservoir temperature can be the ambient temperature of the fluids in the reservoir formation.

[0031] At a preset reservoir temperature, this step can inject crude oil into a water-saturated core to displace formation water, thereby bringing the core sample to a state of oil saturation.

[0032] The saturated oil state refers to the state where the oil saturation in the core reaches its maximum value (the maximum amount of crude oil the core can hold), and no operation will increase the oil saturation. In other words, the saturated oil state is the state where the oil saturation in the core reaches the maximum amount of crude oil that the core can hold under experimental conditions. It is the state formed after oil displacement of some water on a pre-saturated water basis, where the oil saturation cannot be further increased by conventional displacement methods.

[0033] After the core sample reaches a saturated oil state, it can be aged to restore its wettability, so that subsequent operations can simulate the water-driven oil flow process under actual reservoir conditions.

[0034] S103: Perform water-drive oil operation on the core sample at a preset flow rate, and use a CT scanning device to scan the core sample at multiple scanning nodes to obtain the measured core CT value corresponding to each scanning node.

[0035] Waterflooding, also known as water injection flooding, is an artificial oil recovery method that uses water injected into the reservoir to maintain formation pressure and displace crude oil to production wells. The waterflooding operation described in this step refers to injecting formation water into a core sample treated with S102 at a constant injection rate to simulate the process of water displacing crude oil in the pores of an oil reservoir. During the waterflooding operation, this embodiment can record the current displacement pore volume in real time and determine whether the current moment is a time node related to the displacement pore volume.

[0036] This embodiment can set multiple scanning nodes according to preset displacement pore volumes (such as 0.2 PV, 0.5 PV, 1.0 PV, etc.), where each scanning node is a time node related to the displacement pore volume. Scanning is performed when the current displacement pore volume reaches the displacement pore volume corresponding to the scanning node, obtaining the measured core CT value corresponding to each scanning node. The aforementioned CT scanning device can be an in-situ CT scanning device. PV (Pore Volume) represents the total volume of all connected pores inside the core, also known as the effective pore volume.

[0037] After washing and drying the core sample, this embodiment can obtain the porosity and permeability of the core sample, and determine multiple scanning nodes based on the porosity and permeability.

[0038] S104: Calculate the oil saturation and water saturation corresponding to each scanning node based on the measured core CT values, and perform parameter fitting on the Corey model based on the oil saturation and water saturation to obtain the relative permeability curves of the oil and water phases.

[0039] After obtaining the measured core CT value corresponding to each scanning node, the volume ratio of oil phase and water phase in the core pores under each scanning node can be inverted based on the measured core CT value, thereby calculating the corresponding oil saturation and water saturation.

[0040] Each scan node has its corresponding oil saturation and water saturation. This step can use the corresponding oil saturation and water saturation of all scan nodes to perform parameter fitting on the Corey model.

[0041] Specifically, this step calculates the relative permeability of the oil phase and water phase at each scanning node based on the oil and water saturation obtained from each scanning node, combined with parameters such as pressure and flow rate during the displacement process. The parameters in the Corey model are then fitted using these oil and water phase relative permeability values ​​to generate oil-water two-phase relative permeability curves that reflect the true characteristics of the core sample. The Corey model, or relative permeability model, is a model used to describe the relationship between the relative permeability of the oil and water phases and water saturation in a core sample.

[0042] After obtaining the relative permeability curves of the oil and water phases, the oil and water phase relative permeability curves can be used for reservoir numerical simulation or to evaluate oil displacement efficiency.

[0043] This embodiment involves washing, drying, vacuuming, and injecting formation water into the core sample to obtain a core sample in a water-saturated state. Furthermore, crude oil is injected into the core sample at a preset reservoir temperature to restore its wettability, resulting in a core sample in an oil-saturated state. This embodiment also introduces a CT scanning device to scan the core sample at multiple displacement nodes, obtaining the measured CT value for each scanning node. Based on the measured CT values, the oil saturation and water saturation corresponding to each scanning node are calculated. Then, the Corey model is fitted with parameters based on the oil saturation and water saturation to obtain the relative permeability curve of the oil and water phases. The measured core CT values ​​reflect the true internal structure of the core sample. The above process anchors the parameters of the Corey model to the intuitive measured core CT values, realizing the generation of the relative permeability curve of the oil and water phases based on the true internal structure of the core sample. Compared to the indirect calculation scheme in conventional methods, this embodiment can accurately detect the relative permeability curve of the oil and water phases in the core.

[0044] As for Figure 1 In a further description of the corresponding embodiment, the process of calculating the oil saturation and water saturation corresponding to each scanning node based on the measured core CT value includes: substituting the measured core CT value corresponding to each scanning node into a first preset formula to obtain the oil saturation; and substituting the oil saturation into a second preset formula to obtain the water saturation.

[0045] The first preset formula is: The second preset formula is: ; Indicates oil saturation. This indicates the CT value of a core sample containing saturated formation water. This represents the measured core CT value. Indicates the formation water CT value. This indicates the CT value of crude oil. Indicates the air CT value, Indicates the CT value of dry core. Indicates water saturation.

[0046] In this embodiment, a CT scan is first performed on the dry core to obtain the CT value of the dry core, and then a CT scan is performed on the core saturated with water to obtain the CT value of the core saturated with formation water. Specifically, the CT value of the dry core is the CT value of the core after drying; the CT value of the core saturated with formation water is the CT value of the core measured after the dry core is vacuum-saturated with water.

[0047] As for Figure 1 A further description of the corresponding embodiment: the process of obtaining the relative permeability curves of the oil and water phases by fitting the parameters of the Corey model based on the oil saturation and the water saturation includes: determining the oil production based on the oil saturation and the water production based on the water saturation; determining the water content corresponding to each scanning node based on the oil production and the water production; and fitting the parameters of the Corey model using the water content and water saturation corresponding to all scanning nodes to obtain the relative permeability curves of the oil phase and the water phase.

[0048] Specifically, this embodiment can obtain the volume and porosity of the core sample. Multiplying the volume, porosity, and oil saturation yields the oil-bearing volume of the core, and multiplying the volume, porosity, and water saturation yields the water-bearing volume of the core. This embodiment performs water flooding on the core sample at a preset flow rate (i.e., constant flow). Based on the currently injected formation water volume, the oil-bearing volume, and the water-bearing volume of the core, the oil production and water production corresponding to each scanning node can be determined. Water cut describes the proportion of water in the produced fluid (i.e., oil production + water production) of the water flooding operation. After obtaining the oil production and water production, the water cut corresponding to each scanning node can be calculated based on these values. This embodiment can use the water cut and water saturation of each scanning node as known data points. Based on these known data points, the parameters in the Corey model are fitted to obtain the relative permeability curves of the oil phase and the water phase. The relative permeability curves of the oil and water phases include the oil phase relative permeability curve and the water phase relative permeability curve mentioned above.

[0049] The Corey model includes formulas for calculating the relative permeability of the oil phase and the relative permeability of the water phase. Based on these formulas, the process of fitting the Corey model with parameters using the water content and water saturation corresponding to all the scanned nodes to obtain the relative permeability curves of the oil phase and the water phase includes: The formulas for calculating the relative permeability of the oil phase and the relative permeability of the water phase corresponding to the Corey model are determined; a third preset formula is constructed; wherein, the third preset formula is a formula used to describe the relationship between water content, relative permeability of the oil phase, and relative permeability of the water phase; the water content and water saturation corresponding to all the scanning nodes are substituted into the formulas for calculating the relative permeability of the oil phase, the relative permeability of the water phase, and the third preset formula, and the values ​​of the first unknown coefficient and the second unknown coefficient are fitted and calculated; the relative permeability curve of the oil phase is determined based on the first unknown coefficient and the formula for calculating the relative permeability of the oil phase; the relative permeability curve of the water phase is determined based on the second unknown coefficient and the formula for calculating the relative permeability of the water phase.

[0050] The formula for calculating the relative permeability of the oil phase is as follows: The formula for calculating the relative permeability of the aqueous phase is as follows: , Indicates the relative permeability of the oil phase. This represents the relative permeability of the oil phase at the bound water saturation level. Indicates residual oil saturation. Indicates water saturation. Indicates the degree of bound water saturation. Indicates the first unknown coefficient. Indicates the relative permeability of the water phase. This represents the relative permeability of the aqueous phase at residual oil saturation. This represents the second unknown coefficient. The relative permeability of the oil phase under bound water saturation and the relative permeability of the water phase under residual oil saturation can be calculated using Darcy's formula.

[0051] The expression for the third preset formula mentioned above is: ; in, Indicates moisture content, This indicates the viscosity of formation water (also known as viscosity). This indicates the viscosity of crude oil.

[0052] This embodiment utilizes the water saturation and water content obtained from CT inversion to solve for unknown parameters in the Corey model, thereby establishing a high-precision oil-water two-phase flow relationship. Specifically, this embodiment substitutes the water content and water saturation of each scanning node into the aforementioned oil phase relative permeability calculation formula, water phase relative permeability calculation formula, and the third preset formula to construct a nonlinear equation set. Through optimization algorithms (such as the least squares method), the first and second unknown coefficients are adjusted to minimize the error between the theoretically calculated water content and the measured water content, thereby obtaining the values ​​of the first and second unknown coefficients.

[0053] In this embodiment, the relative permeability of the water and oil phases is a function of saturation. Changes in core saturation will cause changes in the value of the relative permeability of the water and oil phases, which is a time-varying variable. However, the relative permeability of the water phase under residual oil saturation and the relative permeability of the oil phase under bound water saturation are constant values, which are directly measured experimentally and do not change with saturation.

[0054] Furthermore, before performing water flooding on the core sample at a preset flow rate, after injecting crude oil into the core sample to saturate it with oil, this embodiment can also perform an aging treatment on the core sample; after the aging treatment is completed, the relative permeability of the oil phase under bound water saturation is detected.

[0055] The process described in the above embodiments is illustrated below through examples in practical applications.

[0056] To address the problems existing in traditional steady-state and unsteady-state methods for obtaining relative permeability curves of oil and water phases, this embodiment provides a more accurate method for fitting relative permeability curves of oil and water phases, based on in-situ CT scanning technology. In-situ CT scanning technology can track and quantitatively characterize water saturation profiles in real time, and can also accurately characterize the overall and local two-phase flow characteristic parameters (water saturation, residual oil saturation, bound water saturation, etc.) of the core. Furthermore, in-situ CT scanning technology can accurately obtain water saturation and produced fluid water cut data at the core outlet face, significantly improving data accuracy compared to traditional methods. This embodiment applies the water saturation profile to the improved relative permeability calculation method by fitting the water saturation and produced fluid water cut at the core outlet face. Compared with commonly used oil-water relative permeability fitting methods, the oil-water two-phase relative permeability curve fitting method proposed in this embodiment has advantages such as fewer fitting parameters, higher accuracy, and ease of operation, while also broadening the application of CT scanning technology in the field of oil and gas field development.

[0057] The above method for fitting the relative permeability curves of oil and water phases includes the following steps: Step A1: Prepare suitable core samples and perform oil washing and drying.

[0058] The core samples mentioned above can be artificial or natural cores, with a length of 5 cm and a diameter of 2.5 cm or 3.8 cm. The core samples can be washed and dried according to the requirements of the relevant standard "Core Analysis Methods". In this implementation plan, the core samples after washing and drying are analyzed for core porosity and permeability according to the petroleum and natural gas industry standard "Methods for Determining Porosity and Permeability of Rocks Under Overburden".

[0059] Step A2: Place the processed core sample into an in-situ CT scanning device (also known as an in-situ CT scanning equipment) to perform relevant experimental operations, obtain core CT scanning data, and perform oil saturation inversion.

[0060] The aforementioned core CT scan data includes core CT values ​​from various stages of displacement, as well as crude oil CT values. ), formation water CT value ( ), air CT value ( ), dry core CT values ​​( ), CT values ​​of saturated formation water cores ( ) and the core CT value at a certain moment ( ).

[0061] This step can use CT data to invert the oil saturation at different locations in the core. The principle is as follows: When using CT scanning technology to determine fluid saturation, the core porosity must first be calculated. Due to the complex composition of the core, calculating the CT value requires knowledge of the mineral composition and structure of each cross-section of the core, which is difficult to achieve. This problem can be solved by using a dual-scan method, that is, scanning both dry and fluid-saturated cores separately, obtaining the following results: Equation (1); Equation (2); Subtracting equation (1) from equation (2) yields the result of calculating porosity using the saturation difference method. The formula is as follows: Equation (3); Indicates the CT value of dry core. This indicates the CT value of the core skeleton. The CT value represents the air quality. This indicates the CT value of a core sample containing saturated formation water. Indicates the formation water CT value. This indicates the CT value of crude oil.

[0062] Core CT value at a certain moment during the displacement process (i.e., measured core CT value). The calculation formula is as follows: Equation (4); The saturation of oil and water satisfies the following relationship: Equation (5); Indicates oil saturation. Indicates water saturation.

[0063] Substituting equation (5) into equation (4) yields the oil saturation of the core at a given moment: Equation (6).

[0064] In the above implementation scheme, equation (6) is the key to inverting the oil saturation of the core from CT data. CT scanning requires obtaining the CT value of the crude oil. ), formation water CT value ( ), air CT value ( ), dry core CT values ​​( ), CT values ​​of saturated formation water cores ( ) and the core CT value at a certain moment ( Of the parameters mentioned above, besides... These are parameters acquired in real time during the experiment, while other parameters are acquired before the formal core experiment. Equation (6) above converts CT data into core oil saturation. With the core oil saturation, subsequent fitting operations of the oil-water relative permeability curve can be performed.

[0065] In the above implementation scheme, in-situ CT scanning is required at different displacement stages (different displacement pore volumes, PV) of the core to obtain CT scan data for different displacement stages. The number of CT scan nodes needs to be determined based on the core's fundamental data (porosity and permeability) and in conjunction with preliminary experiments, requiring at least eight scan nodes. Specifically, in this embodiment, a waterflooding pre-experiment can be conducted on the core based on porosity and permeability to monitor the change in water cut at the outlet end with PV. The inflection point where the water saturation tends to stabilize (i.e., the core water cut reaches 99%) is then used as the last scan node. Based on determining the last scan node, a corresponding number of other scan nodes are selected.

[0066] In the above implementation scheme, the oil saturation of the core at a certain moment can be obtained according to Equation (6). By setting the layer thickness of the CT scan (dividing the core into n parts), the water saturation at different locations of the core can be obtained by processing the CT scan data of each slice of the core using Equation (6). Then, by summarizing the water saturation of different core slices according to the scan position, a water saturation profile of a certain displacement stage of the core can be obtained.

[0067] In the above implementation scheme, the selection of CT scan slice thickness needs to be changed according to specific experimental conditions. The thinner the core CT scan slice thickness, the more accurate the characterization of the core water saturation profile, but the longer the overall experiment time is required. The specific scan slice thickness needs to be selected according to the specific experiment.

[0068] Step A3: Use CT scan data to fit the parameters of the Corey model, obtain the unknown parameters in the Corey model, and finally plot the relative permeability curves of the oil and water phases.

[0069] In the above implementation plan, the Corey model, commonly used in the oil and gas industry, is used to quantitatively describe the relationship between the relative permeability of the oil-water two-phase system and water saturation. The specific relationship is as follows: Equation (7); Equation (8); The relative permeability of the oil phase. The relative permeability of the aqueous phase. To restrict water saturation, The relative permeability of the oil phase under bound water saturation is given. The relative permeability of the aqueous phase at residual oil saturation. Residual oil saturation, This represents the water saturation level. To bind water saturation.

[0070] The relationship between moisture content and relative permeability is as follows: Equation (9); Moisture content; , These are water production and oil production, respectively, in cubic centimeters. , The values ​​are the viscosity of oil and water, respectively, in mPa·s (millipards per second). The parameters required in step A3 can be determined through step A2 or other known detection methods.

[0071] In the above implementation scheme, CT scanning technology can be used to obtain the water saturation distribution of each scanned layer of the core at any given time. Meanwhile, equations (7) to (9) establish the relationship between water content and water saturation, but the formulas contain unknowns. and It is necessary to calculate the water cut using water and oil production data at different displacement times, and then fit the parameters of the relative permeability of oil and water. and Finally, the relative permeability curves of oil and water are obtained. This step uses a series of data obtained in step A2 to fit two unknown parameters using equations (7) to (9) to obtain the relative permeability curves of oil and water.

[0072] and With two different unknown coefficients, the oil-water relative permeability curve is essentially composed of two curves: one is the oil phase relative permeability curve corresponding to equation (8), and the other is the water phase relative permeability curve corresponding to equation (7). The unknown parameter representing the relative permeability curve of the aqueous phase. The unknown parameter represents the relative permeability curve of the oil phase.

[0073] In this embodiment, equations (7) and (8) are the expressions corresponding to the Corey model, and equation (9) serves as a bridge to connect the experimental data. The unknown parameters are solved by fitting, and finally the oil-water relative permeability curve is plotted. The experimental data are: equation (6) and equations (7) and (8) corresponding to the Corey model.

[0074] In the above implementation scheme, it is necessary to obtain water and oil production data at different displacement stages to calculate the water cut. Equations (5) and (6) can be used to accurately obtain the changes in water saturation and oil saturation within the core. Combined with the injection data from the injection pump, water and oil production data at different displacement stages can be calculated, thereby calculating the water cut at the core outlet. Compared with the traditional method of manually measuring the water cut of the produced fluid from the core, this method is simpler to conduct and yields more accurate and reliable experimental results.

[0075] In the above implementation scheme, in order to obtain the oil-water relative permeability curve, it is necessary to use in-situ CT scan displacement experiment data to analyze the unknown parameters in equations (7) and (8). and The fitting solution is performed. Some parameters in equations (7) and (8) are relatively easy to obtain, such as residual oil saturation and bound water saturation. Equation (9) establishes the relationship between the water content of the produced fluid and the water saturation of the core. At the same time, equation (9) is also the link to solve the unknown parameters in equations (7) and (8).

[0076] In equation (9), It is a known data that changes over time and can be calculated from the water production and oil production of the core, i.e., the middle part of equation (9). The water saturation and oil saturation of the core before formal displacement (in saturated oil state) can be calculated from CT scan data, while the porosity and core volume of the core are known parameters in step one. Porosity Oil (water) saturation = core oil (water) volume. This is equivalent to the known oil and water volumes in a core at oil saturation. When the formal experiment begins, the core saturation change can be inverted by recording the core's CT values ​​at different times. Simultaneously, a constant-rate displacement pump is used; the volume of water pumped in at different times is considered known. Combined with the core's water saturation at different times, the water production at those times can be calculated. and oil production Then calculate the water separation rate. The conventional method in this field is to manually measure the oil and water volumes in a graduated cylinder and then calculate the water separation rate. This embodiment uses CT scan data to invert saturation and calculate the water separation rate, which is more accurate and efficient than the traditional method.

[0077] After obtaining the data for different PV numbers in equation (7), in equation (9) besides and All other parameters are known; based on the above formula, it is equivalent to knowing... and The ratio between them. Equation (8) / Equation (7) can also be obtained. and The ratio between them establishes a correlation between equations (7) to (9). In equations (7) and (8), there are only two fitting parameters. and It is unknown. The purpose of this scheme is to test different PV numbers (0.1PV…5PV). Defit and There are many fitting methods that can be used in this embodiment, which are mathematical solutions. From the form of equations (7) and (8), the unknown parameters... and Analyzing the exponents of the formula, exponential fitting in mathematics can be employed. The exponential fitting methods described here include, but are not limited to, the least squares method.

[0078] Step A4: Using the fitted parameters, plot the relative permeability curves of the oil and water phases in conjunction with the Corey model.

[0079] This embodiment provides an improved method for fitting the relative permeability curve of oil and water phases. Compared with traditional steady-state and non-steady-state methods for obtaining oil-water relative permeability curves, this embodiment uses in-situ CT technology to achieve oil-water relative permeability curve fitting, demonstrating significant advantages in solving core challenges such as characterizing core heterogeneity, handling capillary end effects, and ensuring the objectivity of data interpretation. The main advantages are as follows: Advantage 1: This embodiment achieves three-dimensional, real-time quantitative characterization of the spatial distribution of water saturation within the core through in-situ CT scanning. This fundamentally solves the key limitation of traditional unsteady-state methods, which can only obtain the average saturation at the outlet and cannot characterize the uneven saturation distribution within heterogeneous cores. Traditional unsteady-state methods assume homogeneous displacement within the core during calculation, an assumption that leads to significant errors when dealing with actual heterogeneous cores. This embodiment, however, clearly captures the morphology of the displacement front, fingering phenomena, and details of saturation distribution. This ensures that the saturation data used for subsequent fitting with the Corey model is accurate and spatially distributed, thereby greatly improving the accuracy and reliability of the relative permeability curve calculation for heterogeneous reservoirs.

[0080] Advantage 2: This embodiment provides the possibility for direct observation and quantification of capillary end effects, and can effectively correct for their influence during the fitting process. Traditional unsteady-state methods (such as the JBN method) often ignore capillary pressure in data processing, resulting in distorted "humps" in the relative permeability curves of the water phase calculated in low-permeability or highly hydrophilic cores. Using CT technology, this embodiment can intuitively obtain the saturation distribution of each section of the core (including the inlet and outlet ends), accurately assessing the impact of capillary end effects on the stability of the saturation profile. Using this high-precision saturation data as the parameters for fitting the Corey model for the bridge essentially internalizes the influence of capillary force into the saturation distribution data, making the fitted curve more consistent with the actual seepage physics at the rock pore scale.

[0081] Advantage 3: This embodiment establishes a more objective and robust bridge from direct experimental observation data to theoretical model parameters, reducing reliance on idealized mathematical assumptions. Traditional methods heavily depend on assumptions such as homogeneity, one-dimensional displacement, and neglect of capillary forces, leading to multiple interpretations of model parameters. This embodiment, based on the quantitatively obtained, full-field, true water saturation distribution from CT scans, directly correlates it with the produced fluid water cut, and then inversely retrieves and fits the characteristic parameters (such as endpoint values ​​and exponents) in the Corey model. This process anchors model parameters to intuitive experimental observations, significantly improving the physicality of parameter determination and the interpretability of results, providing a more reliable new technical approach for evaluating the relative permeability of complex reservoirs such as low-permeability and fractured reservoirs.

[0082] This embodiment quantitatively characterizes the water saturation distribution at different displacement stages using CT scan quantitative calculation formulas. Based on the water saturation distribution, the characteristics of multiphase flow in the core can be accurately analyzed. Utilizing the two-phase relative permeability equation proposed by Corey, and using the correlation between core water saturation and produced fluid water content as a bridge, the unknown parameters in the Corey model are fitted, and two-phase relative permeability curves are plotted. Compared with the currently commonly used unsteady-state relative permeability calculation methods, the method proposed in this embodiment has fewer fitting parameters, higher accuracy, and a wider range of applications, including but not limited to oil-water two-phase flow. Therefore, this invention not only expands the application scope of CT technology in multiphase flow but also provides more feasibility for calculating relative permeability curves.

[0083] To facilitate understanding and use of this embodiment by those skilled in the art, the specific implementation method of the oil-water two-phase relative permeability curve measurement experiment is described below, which specifically includes the following steps: Step B1: Process the core to obtain a cylindrical core with a length of 5cm and a diameter of 2.5cm.

[0084] Step B2: The core samples are washed with oil and dried according to the requirements of the relevant standard "Core Analysis Methods". After washing with oil and drying, the porosity and permeability of the core are measured by gas.

[0085] Step B3: Measure the CT values ​​of the experimental fluids (crude oil, formation water, air) and the dry core CT values. The in-situ CT scanning core displacement experimental setup is as follows: Figure 2 As shown. Figure 2 This is a schematic diagram of an in-situ CT scanning core displacement experimental device provided in an embodiment of this application. The diagram shows distilled water, a pump, a pressure sensing system, crude oil, formation water, a CT scanning system, a slide rail, a metering device, a temperature control box, and a back pressure controller. P represents a pressure gauge.

[0086] Step B4: Place the core into the in-situ CT scanning core displacement experimental device, evacuate the saturated formation water, and scan the CT value of the saturated formation water rock.

[0087] Specifically, this step involves placing the core sample into a beaker filled with formation water, and then placing this beaker into a vacuum container to create a vacuum. The negative pressure inside the vacuum container allows formation water to easily enter and fill the pores of the core sample, completing the water saturation process.

[0088] Step B5: At reservoir temperature (100 degrees Celsius), the core was saturated with simulated oil at a rate of 0.01 ml / min for 72 hours, then aged for 14 days to restore the core wettability. The relative permeability of the oil phase under the bound water saturation after aging was then used. And core CT values.

[0089] Step B6: Set the CT scanner slice thickness to 1mm, such as... Figure 3 As shown. Water was injected at a flow rate of 2 ml / min for water flooding. The inlet pressure, outlet pressure, cumulative oil production, and cumulative water production were recorded during the experiment. The permeability of the aqueous phase under the residual oil after displacement was also measured. CT scans were performed at displacement pore volumes of 0.1PV, 0.2PV, 0.3PV, 0.4PV, 0.6PV, 1.5PV, and 5PV (displacement ended). The water saturation at different sections of the core was inverted using equation (6) in combination with the CT scan images of different displacement stages, and a water saturation profile was drawn. Figure 4 This is a profile of water saturation at different displacement stages of the core.

[0090] Specifically, the process of inverting the water saturation of different core slices using Equation (6) in combination with CT scan images of different displacement stages is as follows: use Equation (6) to calculate the oil saturation, and use the property that the sum of oil saturation and water saturation equals 1 to calculate the water saturation.

[0091] Figure 3This is a schematic diagram of a CT core section provided in an embodiment of this application. The diagram shows section 1, section 2, section 3, ..., section n. Each section is 1 mm thick and the core length is 50 mm. The displacement direction is also shown in the diagram.

[0092] Figure 4 This application provides a water saturation profile of a core at different displacement stages. The horizontal axis represents the core length (unit: mm), and the vertical axis represents the water saturation (%). The figure shows the relationship between core length and water saturation at eight scanning nodes: 0PV, 0.1PV, 0.2PV, 0.3PV, 0.4PV, 0.6PV, 1.5PV, and 5PV.

[0093] Step B7: Use in-situ CT scan displacement experiment data to evaluate the unknown parameters in equations (7) and (8). and The fitting solution is performed. Some parameters in equations (7) and (8) are relatively easy to obtain, such as residual oil saturation and bound water saturation. Table 1 shows the relevant parameter values ​​obtained from the core displacement experiment. Equation (9) establishes the relationship between the produced fluid water content and the core water saturation. At the same time, equation (9) is also an important link in solving the unknown parameters in equations (7) and (8). The unknown parameters can be solved by substituting the water saturation and produced fluid water content data of different displacement stages into equations (7) to (9). and Table 2 shows the experimental data of core water saturation and produced fluid water content at different displacement stages, as well as the unknown parameters fitted by the experimental data. and The value of . In this embodiment, the unknown parameter and Fitting accuracy ( The fitting parameter is 98.5%. Substituting the fitting parameters into equations (7) and (8), we can plot the results as follows: Figure 5 The relative permeability curves of the oil and water phases are shown.

[0094] Table 1. Parameters of Core Displacement Experiment

[0095] Table 2 CT Data Inversion Experimental Parameters

[0096] After obtaining the fit and Then, by directly substituting these two fitting parameters into equations (7) and (8), a continuous oil-water relative permeability curve can be obtained. During the experiment, a series of scatter points are obtained instead of a curve. It is necessary to fit the scatter points with equations (7) and (8) to obtain two unknown parameters. Then, by substituting these two parameters into equations (7) and (8), a complete (continuous) oil-water relative permeability curve can be plotted. After obtaining the fitting parameters, the left side of equations (7) and (8) is equivalent to the unknown parameters (…). and The right side of the formula only has These are unknown parameters, obtained by giving an infinite number of... The value can be obtained in countless ways and , will countless and These two curves converge to form the oil-water relative permeability curves.

[0097] Please see Figure 5 , Figure 5 This is a schematic diagram of the relative permeability curve of an oil-water two-phase system provided in an embodiment of this application. The horizontal axis represents water saturation, and the vertical axis represents relative permeability. The diagram shows the relative permeability curve of the oil phase. Relative permeability curves of water phase .

[0098] To verify the accuracy of the improved method for fitting the oil-water two-phase relative permeability curve proposed in this experiment, the relative permeability curve of oil and water was measured using the same rock core according to the unsteady-state method in the relevant standard "Method for Determination of Relative Permeability of Two-Phase Fluids in Rock". The following conditions must be met for the unsteady-state method to measure the relative permeability of oil and water: Equation (10); Core length (in cm) The viscosity of water at the experimental temperature (in mPa·s). The seepage velocity is expressed in cm / min.

[0099] The fluid viscosity and injection rate used in this embodiment meet the requirements of equation (10), and the oil-water relative permeability can be calculated and the oil-water relative permeability curve can be plotted using the calculation formula of oil-water relative permeability and water saturation in the unsteady state method. The specific calculation formula is as follows: , Equation (11); Equation (12); Equation (13); , Equation (14); Equation (15); d represents the oil content; d represents the derivative. This represents dimensionless cumulative oil recovery. This represents the dimensionless cumulative liquid collection volume. This refers to relative injection capacity (flow capacity ratio). The initial oil production flow rate at the core outlet face is expressed in cubic meters per second. The flow rate of the produced fluid at the core outlet face at time t is expressed in cubic meters per second. Initial driving pressure differential, in megapascals; The displacement pressure difference at time t, in megapascals; The water saturation at the core outlet face; This represents the core bound water saturation. The viscosity of the oil is given at the experimental temperature.

[0100] To verify the rationality of the improved fitting method for oil-water relative permeability curves proposed in this embodiment, the same core sample was selected for the experiment using the unsteady-state oil-water relative permeability measurement method. The experimental results were processed according to equations (11) to (15) and a relative permeability curve was plotted. This relative permeability curve was compared with the improved relative permeability curve proposed in this paper. The comparison results are as follows: Figure 6 As shown. Figure 6 This application provides a comparison chart of oil-water relative permeability curves between this embodiment and a conventional solution. The horizontal axis represents water saturation, and the vertical axis represents relative permeability. The chart shows the oil phase relative permeability curve. (CT fitting), relative permeability curve of aqueous phase (CT fitting), oil phase relative permeability curve (Unsteady-state method) and relative permeability curves of the aqueous phase (Unsteady-state method).

[0101] oil phase relative permeability curve (CT fitting) and relative permeability curves of the aqueous phase (CT fitting) shows the oil phase relative permeability curve obtained using this method. (Unsteady-state method) and relative permeability curves of the aqueous phase (Unsteady-state method) is the result obtained based on the unsteady-state method in the conventional scheme.

[0102] Through the Figure 6A comparative analysis of the oil-water relative permeability curves obtained by the conventional unsteady-state method and the CT in-situ scanning combined with the Corey model fitting method proposed in this invention clearly shows significant differences between the two methods in terms of curve morphology, key parameters, and accuracy of physical characterization. These differences fully reveal the superiority of the new method proposed in this embodiment in characterizing the multiphase seepage mechanism in complex porous media. The curves obtained by the conventional unsteady-state method exhibit a typical characteristic of a significant dip in the relative permeability of the water phase in the medium water saturation range. That is, the relative permeability curve of the water phase rises very slowly and remains at a low value until it begins to rise rapidly after a higher water saturation. At the same time, the relative permeability of the oil phase decreases relatively quickly. This may lead to an overly narrow calculated range of the two-phase co-permeability zone and an overly high saturation at the intersection point. This morphology is often caused by the failure to consider the average effect of the microscopic heterogeneity inside the core and the instability of the displacement front on the overall flow when inverting macroscopic core end face data. The inversion process forces the use of an idealized homogeneous model to fit the macroscopic response of the heterogeneous system, which may distort the true phase permeability relationship. In contrast, the curves obtained by the in-situ CT scanning and Corey model fitting method used in this embodiment are more reasonable and smoother: the relative permeability curve of the water phase shows a more continuous and stable upward trend after the bound water saturation, and the decline of the relative permeability curve of the water phase is also relatively gentler. Together, they constitute a wider two-phase co-permeability zone. This shape is directly due to the fact that CT scanning technology can obtain the three-dimensional spatial distribution of water saturation at different locations inside the core at different displacement times in situ, in real time, and quantitatively. This allows the Corey model fitting to be based on real, spatially resolved saturation change data, rather than relying solely on macroscopic inlet and outlet pressure and flow data. Therefore, the new method can more realistically reflect the actual physical process in waterflooding where the water phase gradually occupies and connects the complex pore network as saturation increases, avoiding the systematic bias introduced by conventional inversion methods due to the discrepancy between theoretical assumptions (such as one-dimensional homogeneity and piston-like displacement) and physical reality. More importantly, the curves obtained by the new method can more accurately characterize the endpoint values ​​of bound water saturation and residual oil saturation, because CT data can directly observe the areas in the core that cannot be displaced, rather than relying on extrapolation. Therefore, the method proposed in this embodiment significantly reduces the reliance on idealized theoretical models by directly integrating in-situ observation data at the microscale. It provides more reliable oil-water relative permeability curves that better reflect the real complex pore structure and wettability effects of reservoir rocks. This has significant theoretical and applied value for improving the accuracy of reservoir numerical simulation predictions and developing more effective high-recovery strategies. It is evident that the improved oil-water two-phase relative permeability curve fitting method proposed in this embodiment overcomes the shortcomings and deficiencies of existing technologies to a certain extent and is of great significance to oilfield production.

[0103] The relative permeability curves of oil and water phases reveal the capacity allocation and competition mechanisms between the two phases during mutual interference and co-flow. These curves are an indispensable foundation and key element in reservoir engineering, particularly in reservoir numerical simulation and oil displacement efficiency assessment, playing a crucial role throughout the entire process from reservoir understanding and development design to dynamic adjustments. In reservoir numerical simulation, a core decision-making tool for reservoir development, the relative permeability curve, as a parameter characterizing the multiphase flow pattern, is directly input into the simulator's flow equations, fundamentally determining whether the model can accurately reproduce the underground oil-water movement patterns. Numerical simulation, by solving equations such as mass conservation and Darcy's law, predicts the pressure field, saturation field, and production dynamics at different development stages. The accuracy of all these calculations highly depends on the phase permeability relationship provided by the relative permeability curve. If the curve is distorted, the simulation results will deviate significantly from reality, leading to flawed development strategies. Specifically, the curve shape controls the water breakthrough time, water cut rise pattern, oil production changes, and the prediction of ultimate recovery rate. For example, the location and shape of the intersection of the bound water saturation, residual oil saturation, and the two curves (the relative permeability curves of the oil phase and the aquatic phase) (such as the convexity of the curves) together define the flowable saturation range of the oil and water phases, the range of the two-phase flow region, and their respective flow capabilities, thereby determining the stability of the water injection propulsion front, the water drive sweep efficiency, and the micro-displacement characteristics in the simulation.

[0104] Furthermore, this curve serves as the fundamental basis for quantitatively evaluating various oil displacement efficiencies. First, the curve endpoint—residual oil saturation—is directly related to the upper limit of the theoretical oil displacement efficiency, while the overall shape of the curve reveals the ease with which this efficiency can be achieved. By analyzing the relative permeability ratio of oil to water at different water saturations, the amount of water required to drive each unit volume of crude oil (i.e., the mobility ratio and water-oil ratio) can be calculated, thereby assessing the economic benefits of the current development stage. Second, by comparing the relative permeability curve obtained from core experiments with actual oilfield production dynamics data (such as the relationship between water cut and recovery rate), reservoir seepage characteristics can be verified, the effectiveness of waterflooding development can be diagnosed, and the existence of high-permeability channels or untapped residual oil can be identified. In enhanced oil recovery (EOR) research, by comparing the changes in relative permeability curves under different displacement methods such as waterflooding, chemical flooding, and gas flooding (usually due to changes in interfacial tension and wettability leading to an overall rightward shift of the curve, a decrease in residual oil saturation, or an expansion of the two-phase flow zone), the additional recovery potential brought about by new displacement mechanisms can be scientifically quantified, providing quantitative support for technology optimization. Furthermore, in optimizing development plans, relative permeability curves can accurately calculate reasonable injection-production rates, optimal water injection timing, and infill well pattern adjustment strategies to control unfavorable mobility ratios and expand effective displacement volume. In short, oil-water two-phase relative permeability curves not only bridge the gap between seepage mechanisms and development dynamics from the microscopic pore scale to the macroscopic reservoir scale, but also serve as fundamental data for historical data fitting, future dynamic prediction, displacement process optimization, and ultimate recovery rate assessment through reservoir numerical simulation—a "virtual laboratory." The accuracy and depth of their acquisition and application directly determine the scientific level of reservoir management and the economic benefits of oil and gas resource extraction.

[0105] The oil-water two-phase relative permeability curve detection system provided in this application includes: The pretreatment module is used to wash and dry the core sample, vacuum the core sample and inject formation water to make the core sample saturated with water; it is also used to inject crude oil into the core sample at a preset reservoir temperature to make the core sample saturated with oil. The testing module is used to perform water flooding operation on the core sample at a preset flow rate, and to scan the core sample at multiple scanning nodes using a CT scanning device to obtain the measured core CT value corresponding to each scanning node; wherein, the scanning node is a time node related to the displacement void volume. The calculation module is used to calculate the oil saturation and water saturation corresponding to each scanning node based on the measured core CT value, and to perform parameter fitting on the Corey model based on the oil saturation and water saturation to obtain the relative permeability curve of the oil and water phases.

[0106] This embodiment involves washing, drying, vacuuming, and injecting formation water into the core sample to obtain a core sample in a water-saturated state. Furthermore, crude oil is injected into the core sample at a preset reservoir temperature to restore its wettability, resulting in a core sample in an oil-saturated state. This embodiment also introduces a CT scanning device to scan the core sample at multiple displacement nodes, obtaining the measured CT value for each scanning node. Based on the measured CT values, the oil saturation and water saturation corresponding to each scanning node are calculated. Then, the Corey model is fitted with parameters based on the oil saturation and water saturation to obtain the relative permeability curve of the oil and water phases. The measured core CT values ​​reflect the true internal structure of the core sample. The above process anchors the parameters of the Corey model to the intuitive measured core CT values, realizing the generation of the relative permeability curve of the oil and water phases based on the true internal structure of the core sample. Compared to the indirect calculation scheme in conventional methods, this embodiment can accurately detect the relative permeability curve of the oil and water phases in the core.

[0107] Optionally, the calculation module calculates the oil saturation and water saturation corresponding to each scanning node based on the measured core CT values, including: Substitute the measured core CT value corresponding to each scanning node into the first preset formula to obtain the oil saturation. Substituting the oil saturation into the second preset formula, we obtain the water saturation; The first preset formula is: The second preset formula is: ; Indicates oil saturation. This indicates the CT value of a core sample containing saturated formation water. This represents the measured core CT value. Indicates the formation water CT value. This indicates the CT value of crude oil. Indicates the air CT value, Indicates the CT value of dry core. Indicates water saturation.

[0108] Furthermore, the calculation module performs parameter fitting on the Corey model based on the oil saturation and water saturation to obtain the relative permeability curves of the oil and water phases, including: The oil yield is determined based on the oil saturation, and the water yield is determined based on the water saturation. The water content corresponding to each scanning node is determined based on the oil production and the water production. The Corey model was fitted with parameters using the water content and water saturation corresponding to all the scanning nodes to obtain the relative permeability curves of the oil phase and the relative permeability curves of the water phase.

[0109] Furthermore, the calculation module uses the water content and water saturation corresponding to all the scan nodes to perform parameter fitting on the Corey model, and the process of obtaining the oil phase relative permeability curve and the water phase relative permeability curve includes: Determine the formulas for calculating the relative permeability of the oil phase and the relative permeability of the water phase corresponding to the Corey model; wherein, the formula for calculating the relative permeability of the oil phase is as follows: The formula for calculating the relative permeability of the aqueous phase is as follows: , Indicates the relative permeability of the oil phase. This represents the relative permeability of the oil phase at the bound water saturation level. Indicates residual oil saturation. Indicates water saturation. Indicates the degree of bound water saturation. Indicates the first unknown coefficient. Indicates the relative permeability of the water phase. This represents the relative permeability of the aqueous phase at residual oil saturation. Indicates the second unknown coefficient; A third preset formula is constructed; wherein, the third preset formula is a formula used to describe the relationship between water content, relative permeability of the oil phase and relative permeability of the water phase; Substitute the water content and water saturation corresponding to all the scanning nodes into the oil phase relative permeability calculation formula, the water phase relative permeability calculation formula and the third preset formula, and fit and calculate the values ​​of the first unknown coefficient and the second unknown coefficient; The relative permeability curve of the oil phase is determined based on the first unknown coefficient and the calculation formula for the relative permeability of the oil phase. The relative permeability curve of the water phase is determined based on the second unknown coefficient and the formula for calculating the relative permeability of the water phase.

[0110] Furthermore, the expression for the third preset formula is: ; in, Indicates moisture content, Indicates the viscosity of formation water. This indicates the viscosity of crude oil.

[0111] Furthermore, it also includes: The detection module is used to age the core sample before performing water flooding operation on the core sample at a preset flow rate, after injecting crude oil into the core sample to saturate the core sample with oil; it is also used to detect the relative permeability of the oil phase under bound water saturation after the aging process is completed.

[0112] Furthermore, it also includes: The scanning node determination module is used to obtain the porosity and permeability of the core sample after washing and drying the core sample, and to determine multiple scanning nodes based on the porosity and permeability.

[0113] Since the embodiments of the system part correspond to the embodiments of the method part, please refer to the description of the embodiments of the method part for the embodiments of the system part, and they will not be repeated here.

[0114] This application also provides a storage medium on which a computer program is stored, which, when executed, can perform the steps provided in the above embodiments. The storage medium may include various media capable of storing program code, such as a USB flash drive, a portable hard drive, a read-only memory (ROM), a random access memory (RAM), a magnetic disk, or an optical disk.

[0115] This application also provides an electronic device that may include a memory and a processor. The memory stores a computer program, and when the processor calls the computer program in the memory, it can implement the steps provided in the above embodiments. Of course, the electronic device may also include various network interfaces, power supplies, and other components.

[0116] The various embodiments in this specification are described in a progressive manner, with each embodiment focusing on its differences from other embodiments. Similar or identical parts between embodiments can be referred to interchangeably. For the systems disclosed in the embodiments, since they correspond to the methods disclosed in the embodiments, the descriptions are relatively simple; relevant parts can be referred to the method section. It should be noted that those skilled in the art can make various improvements and modifications to this application without departing from the principles of this application, and these improvements and modifications also fall within the protection scope of this application.

[0117] It should also be noted that, in this specification, relational terms such as "first" and "second" are used only to distinguish one entity or operation from another, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Furthermore, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. Without further limitations, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes said element.

Claims

1. A method for detecting the relative permeability curve of an oil-water two-phase system, characterized in that, include: The core sample was washed with oil and dried. The core sample was then vacuumed and injected with formation water to bring it to a water-saturated state. At a preset reservoir temperature, crude oil is injected into the core sample to saturate the core sample with oil. The core sample is subjected to water flooding at a preset flow rate, and the core sample is scanned at multiple scanning nodes using a CT scanning device to obtain the measured core CT value corresponding to each scanning node; wherein, the scanning node is a time node related to the displacement void volume. The oil saturation and water saturation corresponding to each scanning node are calculated based on the measured core CT values. The Corey model is then fitted with parameters based on the oil saturation and water saturation to obtain the relative permeability curves of the oil and water phases.

2. The method for detecting the relative permeability curve of an oil-water two-phase system according to claim 1, characterized in that, Calculate the oil saturation and water saturation corresponding to each scanning node based on the measured core CT values, including: Substitute the measured core CT value corresponding to each scanning node into the first preset formula to obtain the oil saturation. Substituting the oil saturation into the second preset formula, we obtain the water saturation; The first preset formula is: The second preset formula is: ; Indicates oil saturation. This indicates the CT value of a core sample containing saturated formation water. This represents the measured core CT value. Indicates the formation water CT value. This indicates the CT value of crude oil. Indicates the air CT value, Indicates the CT value of dry core. Indicates water saturation.

3. The method of claim 1, wherein the oil-water two-phase relative permeability curve is determined by the following steps of: Based on the oil saturation and water saturation, the Corey model is fitted with parameters to obtain the relative permeability curves of the oil and water phases, including: ​ The oil yield is determined based on the oil saturation, and the water yield is determined based on the water saturation. The water content corresponding to each scanning node is determined based on the oil production and the water production. The Corey model was fitted with parameters using the water content and water saturation corresponding to all the scanning nodes to obtain the relative permeability curves of the oil phase and the relative permeability curves of the water phase.

4. The method for detecting the relative permeability curve of oil and water phases according to claim 3, characterized in that, The Corey model was fitted with parameters using the water content and water saturation corresponding to all the scan nodes to obtain the relative permeability curves of the oil phase and the water phase, including: Determine the formulas for calculating the relative permeability of the oil phase and the relative permeability of the water phase corresponding to the Corey model; wherein, the formula for calculating the relative permeability of the oil phase is as follows: The formula for calculating the relative permeability of the aqueous phase is as follows: , Indicates the relative permeability of the oil phase. This represents the relative permeability of the oil phase at the bound water saturation level. Indicates residual oil saturation. Indicates water saturation. Indicates the degree of bound water saturation. Indicates the first unknown coefficient. Indicates the relative permeability of the water phase. This represents the relative permeability of the aqueous phase at residual oil saturation. Indicates the second unknown coefficient; A third preset formula is constructed; wherein, the third preset formula is a formula used to describe the relationship between water content, relative permeability of the oil phase and relative permeability of the water phase; Substitute the water content and water saturation corresponding to all the scanning nodes into the oil phase relative permeability calculation formula, the water phase relative permeability calculation formula and the third preset formula, and fit and calculate the values ​​of the first unknown coefficient and the second unknown coefficient; The relative permeability curve of the oil phase is determined based on the first unknown coefficient and the calculation formula for the relative permeability of the oil phase. The relative permeability curve of the water phase is determined based on the second unknown coefficient and the formula for calculating the relative permeability of the water phase.

5. The method of claim 4, wherein the oil-water two-phase relative permeability curve is determined by: An expression of the third preset formula is: ; in, Indicates moisture content, Indicates the viscosity of formation water. This indicates the viscosity of crude oil.

6. The method of claim 4, wherein the oil-water two-phase relative permeability curve is determined by: Before performing waterflooding on the core sample at a preset flow rate, after injecting crude oil into the core sample to saturate it with oil, the process further includes: The core samples were subjected to aging treatment; After the aging process was completed, the relative permeability of the oil phase under the bound water saturation of the core sample was measured.

7. The method of claim 1, wherein the oil-water two-phase relative permeability curve is determined by the following steps of: After washing and drying the core samples, the process also includes: ​ The porosity and permeability of the core sample are obtained, and multiple scanning nodes are determined based on the porosity and permeability.

8. A system for detecting oil-water two-phase relative permeability curves, characterized by, include: The pretreatment module is used to wash and dry the core sample, vacuum the core sample and inject formation water to make the core sample saturated with water; it is also used to inject crude oil into the core sample at a preset reservoir temperature to make the core sample saturated with oil. The testing module is used to perform water flooding operation on the core sample at a preset flow rate, and to scan the core sample at multiple scanning nodes using a CT scanning device to obtain the measured core CT value corresponding to each scanning node; wherein, the scanning node is a time node related to the displacement void volume. The calculation module is used to calculate the oil saturation and water saturation corresponding to each scanning node based on the measured core CT value, and to perform parameter fitting on the Corey model based on the oil saturation and water saturation to obtain the relative permeability curve of the oil and water phases.

9. An electronic device, comprising: The device includes a memory and a processor, wherein the memory stores a computer program, and the processor, when calling the computer program in the memory, implements the steps of the method for detecting the relative permeability curve of an oil-water two-phase system as described in any one of claims 1 to 7.

10. A storage medium, characterized by The storage medium stores computer-executable instructions, which, when loaded and executed by a processor, implement the steps of the method for detecting the relative permeability curve of the oil-water two-phase as described in any one of claims 1 to 7.

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