Method, device and equipment for determining multiphase relative permeability of reservoir

Abstract

The application discloses a method, device and equipment for determining multiphase relative permeability of a reservoir. The method comprises the following steps: obtaining preset experimental parameters of a gas-assisted gravity drainage experiment of a target reservoir; the preset experimental parameters at least include gas phase control parameters for assisting gravity drainage and liquid phase control parameters for assisting gravity drainage; building a gas-assisted gravity drainage system based on a core sample of the target reservoir, and performing the gas-assisted gravity drainage experiment based on the gas-assisted gravity drainage system and the preset experimental parameters; obtaining saturation distribution data collected by the gas-assisted gravity drainage system; and determining relative permeability of multiphase fluid in the core sample as target relative permeability corresponding to the target reservoir based on the saturation distribution data and the preset experimental parameters. Through the above method, the multiphase relative permeability can be determined more directly, accurately and efficiently. Moreover, the method can be applied to determination of multiphase relative permeability of various types of reservoirs.

Description

Technical Field

[0001] This application relates to the field of oil and gas field development technology, and in particular to a method, apparatus and equipment for determining the relative permeability of multiphase reservoirs. Background Technology

[0002] In fields involving multiphase flow, such as oil and gas field development, carbon dioxide geological storage, and groundwater remediation, relative permeability is a core parameter characterizing the flow capacity of multiphase fluids in porous media. For complex flow scenarios involving the coexistence of water, oil, and gas phases, obtaining accurate multiphase relative permeability data is crucial.

[0003] Currently, the mainstream experimental methods for obtaining the relative permeability of multiphase systems are mainly divided into two categories.

[0004] One type is the direct measurement method based on imaging technology. This method involves free gravity displacement in a vertically placed long sand column, combined with CT scans to obtain a saturation profile, and then directly calculating the relative permeability using a simplified Darcy's law. This method allows for rapid and continuous measurements, but its technical approach is only suitable for unconsolidated sand columns with high permeability and extremely weak capillary forces. For consolidated cores with low permeability (such as sandstone and carbonate rocks), the capillary force is significantly enhanced, and the gravity of the liquid column alone cannot overcome the capillary inlet pressure, resulting in the inability to initiate displacement. Furthermore, this method cannot actively control the saturation change path.

[0005] Another type is the traditional steady-state method, which involves simultaneously injecting three-phase fluids into the core and measuring the pressure difference and flow rate after the system reaches steady state, thereby calculating the relative permeability. Although this method is applicable to consolidated cores, it has an extremely long experimental cycle, is very costly, and the measurement method based on discrete steady-state points cannot reflect the actual unsteady seepage process in the reservoir.

[0006] There is currently no effective solution to the problem that the method cannot be applied to various types of core samples and that it is impossible to directly, accurately, and efficiently determine the relative permeability of multiple phases in unsteady-state processes. Summary of the Invention

[0007] The purpose of this application is to provide a method, apparatus, and equipment for determining the relative permeability of multiphase reservoirs, in order to solve the problem that existing methods cannot be applied to various core samples and cannot directly, accurately, and efficiently determine the relative permeability of multiphase reservoirs in unsteady-state processes.

[0008] To address the aforementioned technical problems, this specification provides a method for determining the relative permeability of multiphase reservoirs, comprising: Obtain preset experimental parameters for the gas-assisted gravity displacement experiment of the target reservoir; the preset experimental parameters include at least gas phase control parameters and liquid phase control parameters for assisting gravity displacement. A gas-assisted gravity displacement system was built based on core samples from the target reservoir, and gas-assisted gravity displacement experiments were conducted using the preset experimental parameters based on the gas-assisted gravity displacement system. Acquire saturation distribution data collected by the air-assisted gravity exhaust system; Based on the saturation distribution data and the preset experimental parameters, the relative permeability of the multiphase fluid in the core sample is determined as the target relative permeability corresponding to the target reservoir.

[0009] In some embodiments of this specification, the gas phase control parameters include the injected gas pressure at the top of the core sample and the gas back pressure at the bottom of the core sample in the gas-assisted gravity displacement system. The liquid phase control parameters include the fluid type and injection rate of the liquid fluid injected into the top of the core in the gas-assisted gravity displacement system.

[0010] In some embodiments of this specification, air-assisted gravity displacement experiments are conducted using the preset experimental parameters based on the air-assisted gravity displacement system, including: While applying the injection gas pressure to the top of the core sample, a fluid of the corresponding fluid type is injected into the core sample at the fluid injection rate; Maintain the bottom of the core sample under the gas back pressure, start the gas-assisted gravity displacement experiment, and continue until the change in fluid saturation in the core sample tends to stop, thus completing the gas-assisted gravity displacement experiment.

[0011] In some embodiments of this specification, acquiring the saturation distribution data collected by the gas-assisted gravity exhaust system includes: During the gas-assisted gravity displacement experiment, the CT scanner in the gas-assisted gravity displacement system is used to control the displacement platform of the gas-assisted gravity displacement system to move the core sample point by point at preset time intervals, and the CT data of the core sample at different times is recorded to complete the axial scanning of the core sample. Based on the CT data obtained from the scan and the CT reference values ​​corresponding to each phase fluid under the preset saturation state, the saturation distribution data is obtained.

[0012] In some embodiments of this specification, the relative permeability of the multiphase fluid in the core sample is determined based on the saturation distribution data and the preset experimental parameters, including: Based on the saturation distribution data and the preset experimental parameters, the fluid flux of each phase fluid in the target section of the core sample is determined. Based on the property parameters of the core sample and the preset experimental parameters, the effective gas pressure gradient of the target section is determined; The relative permeability of the multiphase fluids in the core sample is determined based on the fluid flux of each phase and the effective gas pressure gradient.

[0013] In some embodiments of this specification, the fluid flux of each phase fluid is determined by the following formula: ; in, u i ( z K , t j+1 / 2 ) indicates at time step t j+1 / 2 Points z K First i Fluid flux of the phase fluid; u i,inj This indicates the injection rate of fluid at the top of the core sample; The porosity of the core sample is represented by K; K represents the number of points in a single CT scan during the gas-assisted gravity displacement experiment. S i ( z k , t j+1 )and S i ( z k , t j ) represent the points respectively z k At time step i, the fluid of phase i t j and time step t j+1 Saturation data; Δ z This indicates the spacing of the CT scan during the air-assisted gravity displacement experiment.

[0014] In some embodiments of this specification, the effective gas pressure gradient is determined by the following formula: ; Where |G| represents the effective gas pressure gradient, Δ P total This represents the difference between the injected gas pressure at the top of the core sample and the gas back pressure at the bottom of the core sample. P c,entry To represent the inlet capillary pressure at the top of the core sample, L represents the length of the core sample, and α and β represent preset coefficients.

[0015] In some embodiments of this specification, the relative permeability of the multiphase fluid is determined by the following formula: ; in, k ri ( z K , t j+1 / 2 ) indicates at time step t j+1 / 2 Points z K First r Phase fluid and i The relative permeability of the phase fluid; u i ( z K , t j+1 / 2 ) indicates at time step t j+1 / 2 Points z K In the middle i Fluid flux of the phase fluid; μ i and ρ i Indicates the fluid viscosity and fluid density of the core sample; k 0 represents the absolute permeability of the core sample; |G| represents the effective gas pressure gradient.

[0016] The second aspect of this specification provides an apparatus for determining the relative permeability of multiphase reservoirs, comprising: The first acquisition module is used to acquire preset experimental parameters for the gas-assisted gravity displacement experiment of the target reservoir; the preset experimental parameters include at least gas phase control parameters and liquid phase control parameters for assisting gravity displacement. The experimental module is used to build a gas-assisted gravity displacement system based on core samples of the target reservoir, and to conduct gas-assisted gravity displacement experiments based on the gas-assisted gravity displacement system using the preset experimental parameters. The second acquisition module is used to acquire saturation distribution data collected by the air-assisted gravity exhaust system; The determination module is used to determine the relative permeability of the multiphase fluid in the core sample as the target relative permeability corresponding to the target reservoir based on the saturation distribution data and the preset experimental parameters.

[0017] A third aspect of this specification provides an electronic device, comprising: a memory and a processor, wherein the processor and the memory are communicatively connected to each other, the memory stores computer instructions, and the processor executes the computer instructions to implement the steps of the method described in any of the first aspects.

[0018] Based on the method, apparatus, and equipment for determining the multiphase relative permeability of reservoirs provided in the embodiments of this specification, preset experimental parameters for gas-assisted gravity displacement experiments of the target reservoir are obtained. These preset experimental parameters include at least gas-phase control parameters and liquid-phase control parameters for assisting gravity displacement. A gas-assisted gravity displacement system is constructed based on core samples of the target reservoir, and gas-assisted gravity displacement experiments are conducted using the preset experimental parameters. Saturation distribution data collected by the gas-assisted gravity displacement system is obtained. Based on the saturation distribution data and the preset experimental parameters, the relative permeability of the multiphase fluids in the core sample is determined as the target relative permeability corresponding to the target reservoir. Through this method, during gas-assisted gravity displacement experiments, the seepage process of three-phase fluids in oil and gas reservoirs can be simulated more accurately and realistically using gas-phase control parameters and liquid-phase control parameters, controlling the saturation change path. Based on this, by collecting saturation distribution data and combining it with the preset experimental parameters, the multiphase relative permeability can be determined more directly, accurately, and efficiently. Furthermore, precise control of gas-assisted gravity displacement experiments can be achieved through gas-phase control parameters and liquid-phase control parameters. These parameters can be flexibly adjusted based on the physical properties of different reservoirs, exhibiting strong universality and scalability. They can be applied to the determination of multiphase relative permeability in various types of reservoirs. Attached Figure Description

[0019] To more clearly illustrate the technical solutions in the embodiments of this application or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments recorded in this application. For those skilled in the art, other drawings can be obtained from these drawings without creative effort.

[0020] Figure 1 The diagram shown is a schematic representation of a method for determining the relative permeability of multiphase reservoirs provided in an embodiment of this specification. Figure 2 The diagram shown is a schematic of the gas-assisted gravity displacement experimental method provided in the embodiments of this specification; Figure 3 The diagram shown is a schematic of a pneumatic gravity exhaust system provided in an embodiment of this specification. Figure 4 The diagram shown is a schematic representation of a method for obtaining saturation distribution data provided in an embodiment of this specification. Figure 5 The diagram shown is a schematic representation of a method for determining relative permeability provided in an embodiment of this specification. Figure 6 The figure shown is a schematic diagram of the relative permeability curve of the three-phase oil phase in Test 1 provided in the embodiment of this specification; Figure 7 The figure shown is a schematic diagram of the relative permeability curve of the three-phase oil phase in Test 2 provided in the embodiment of this specification; Figure 8 The figure shown is a schematic diagram of the relative permeability curve of the three-phase oil phase in Test 3 provided in the embodiment of this specification; Figure 9 The diagram shown is a schematic of a reservoir multiphase relative permeability determination device provided in an embodiment of this specification; Figure 10 The diagram shown is a schematic of an electronic device provided in an embodiment of this specification. Detailed Implementation

[0021] To enable those skilled in the art to better understand the technical solutions in this application, the technical solutions in the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only a part of the embodiments of this application, and not all of the embodiments. Based on the embodiments in this application, all other embodiments obtained by those skilled in the art without creative effort should fall within the scope of protection of this application.

[0022] It should be noted that the information and data related to users involved in the embodiments of this specification are all information and data authorized by the user or fully authorized by the relevant parties. Furthermore, the collection, storage, use, processing, transmission, provision, disclosure, and application of the relevant data all comply with relevant laws, regulations, and standards, and necessary confidentiality measures have been taken. They do not violate public order and good morals, and corresponding operation entry points are provided for users or relevant parties to choose to authorize or refuse.

[0023] It should also be noted that in the embodiments of this specification, certain software, components, models and other existing solutions in the industry may be mentioned. These should be regarded as exemplary and are only intended to illustrate the feasibility of implementing the technical solution of this application. However, it does not mean that the applicant has used or necessarily used the solution.

[0024] In oil and gas field development, geological engineering, and multiphase flow seepage mechanism research, relative permeability is a core parameter characterizing the flow capacity of multiphase fluids in porous media. For scenarios involving three-phase flow of water-oil-gas, such as tertiary oil recovery processes (e.g., gas injection drive, water-gas alternating drive), carbon dioxide geological sequestration, and migration of non-aqueous contaminants, obtaining accurate multiphase relative permeability data is crucial.

[0025] In some implementation scenarios, the main methods for obtaining multiphase relative permeability fall into two categories: experimental measurement and theoretical model prediction. Experimental measurement methods can be further divided into steady-state and unsteady-state methods. The steady-state method calculates relative permeability by simultaneously injecting three-phase fluids until the system reaches steady state, then measuring pressure drop and saturation. This method provides reliable data points but is extremely time-consuming and costly, and cannot reflect the unsteady-state process of dynamic saturation changes in the reservoir. The unsteady-state method performs inversion calculations based on production data (flow rate, pressure difference) at the outlet during the displacement process. It is highly efficient, but its accuracy heavily relies on the fundamental assumptions of the split theory and is significantly affected by capillary end effects, leading to large errors and multiple solutions in the results.

[0026] For example, taking the steady-state method for measuring the multiphase relative permeability of rock cores as an example, this method mainly includes: (1) Place the cylindrical core (usually horizontal or vertical) in the holder and initially saturate it to a certain oil and water saturation.

[0027] (2) A three-phase fluid of water, oil and gas is simultaneously injected into the core using multiple precision injection pumps at a preset flow rate ratio, and the injection ratio is maintained until the pressure difference between the core inlet and outlet and the flow rate of each phase outlet remain constant (i.e., steady state is reached).

[0028] (3) Under steady state, the pressure difference ΔP at both ends of the core and the outlet flow rate Qi of each phase are measured, and the average saturation Si in the core is determined by material balance or offline / online scanning technology.

[0029] (4) Calculate the effective permeability ki=(QiμiL) / (AΔP) of each phase according to Darcy's law, and then divide it by the absolute permeability k of the core to obtain the relative permeability kri at the steady-state saturation point.

[0030] (5) By changing the three-phase injection ratio, repeat steps 2 to 4 to obtain relative permeability data points under different saturation combinations, and then draw the relative permeability curve.

[0031] Although the above method is considered a reliable standard method, it has the following problems: The experiment has a very long cycle and consumes a lot of resources: because after each change in the injection ratio, it takes a very long time (usually several days to several weeks) to wait for the system to reach a new steady state, and a sufficient number of steady state points are needed to plot the relative permeability curve. It usually takes several months to complete a set of multiphase relative permeability measurements and consumes a large amount of experimental fluid, which is very costly. Unable to simulate the unsteady seepage process in actual oil reservoirs: Fluid flow in oil reservoirs is essentially an unsteady process with continuously changing saturation. The steady-state method forcibly maintains the system at a certain static saturation point by fixing the injection ratio, which does not match the actual dynamic process of oil reservoirs. Therefore, the measured data may not truly reflect the dynamically changing seepage characteristics under oil reservoir conditions. The data points are sparse and affected by the end effect: Each steady-state point only provides a discrete relative permeability data point. To obtain a complete curve, a large number of points need to be measured. However, due to time and cost constraints, only a limited number of points can usually be obtained, resulting in significant uncertainty in curve fitting. In addition, the steady-state method also faces the capillary end effect problem, that is, the saturation gradient generated by the discontinuity of capillary pressure at the outlet end will affect the accurate determination of the average saturation inside the core and interfere with the interpretation of the pressure gradient, thus introducing systematic errors.

[0032] In some implementation scenarios, imaging-based techniques are used to directly observe the fluid distribution within porous media. By performing free gravity displacement in a vertically placed long sand column, saturation profiles are obtained in real-time using CT scans, and relative permeability is directly calculated using Darcy's law. This method avoids the uncertainties of traditional inversion algorithms and can obtain continuous, dense data points. However, existing CT-based direct gravity displacement measurement methods have only been successfully applied to unconsolidated sand columns. The core premise is that sand columns have high permeability and extremely weak capillary forces, thus the capillary pressure gradient can be ignored, and the gas pressure gradient is assumed to be zero, with gravity being the only driving force, significantly simplifying the calculation formula. For consolidated cores (such as sandstone and carbonate rocks), their permeability is typically on the millidarcy scale, and capillary forces are significantly enhanced. With limited core lengths in the laboratory (usually less than 1 meter), the gravity of the liquid column often cannot overcome the capillary inlet pressure, preventing spontaneous fluid displacement and hindering the experiment's initiation. Therefore, existing technologies lack an experimental method that can be applied to consolidated cores and can directly, accurately, and efficiently measure the relative permeability of multiple phases in unsteady-state processes.

[0033] For example, a CT-based direct measurement method for gravity displacement may include the following steps: (1) A long cylindrical unconsolidated sand column (usually longer than 1 meter) is placed vertically, initially saturated with oil and water phases.

[0034] (2) Open the top and bottom of the sand column to allow gas to enter freely, and allow the liquid to be freely discharged downwards under its own gravity. (3) During the displacement process, a CT scanner was used to scan along the sand column axis at fixed time intervals to obtain the spatial distribution profile data of the saturation of the three phases of water, oil, and gas, S. w (z,t), S o (z,t), S g (z,t).

[0035] (4) Based on the saturation profile data, the flux u of each phase fluid is calculated using the principle of mass conservation. i (z,t).

[0036] (5) In the sand column, simplified calculations are performed based on the following two key assumptions: The capillary pressure gradient is negligible, i.e., dPc / dz≈0; The gas pressure gradient is zero, i.e., dP / dz≈0.

[0037] Therefore, the driving force on the liquid phase is only gravity, and the relative permeability can be directly calculated using the following simplified formula: k ri =u i μ i / ( kρ i g ), where k ri The absolute permeability of the sand column is μ. i ρ is the fluid viscosity. i Let g be the fluid density and g be the acceleration due to gravity.

[0038] While the above method enables direct and rapid measurement of the relative permeability of multiphase materials, it suffers from the following limitations, preventing its application to consolidated core samples: This method is only applicable to unconsolidated media with high permeability and weak capillary forces. The core simplifying assumptions (negligible capillary pressure gradient and zero gas pressure gradient) hold only if the medium is a coarse-grained sand column with high permeability (Darcy level), large pore radius, and extremely weak capillary forces. For consolidated cores, permeability is typically on the millidarcy level, and capillary forces are significant. In laboratory-scale cores, capillary forces are on the same order of magnitude as or even greater than gravity, therefore the capillary pressure gradient cannot be ignored. More importantly, due to the high capillary inlet pressure in the core, gravity alone cannot overcome this pressure, preventing the displacement from starting and rendering the experiment impossible. The saturation change path is uncontrollable: This technical solution relies on free gravity displacement, and the saturation change trajectory is completely determined by the properties of the medium and the fluid, which cannot be actively intervened or controlled by the experimenter. Therefore, it is impossible to use this method to systematically study the impact of different saturation paths (such as the discharge process of the oil phase under different constant water saturation) on relative permeability, which is the key to understanding the three-phase flow hysteresis effect and optimizing reservoir simulation.

[0039] It can be seen that although the CT-based gravity displacement direct measurement method can achieve direct and rapid measurement, its technical solution based on free gravity displacement and simplified force balance makes it unsuitable for consolidated cores and lacks the ability to control the saturation path. Although the steady-state method can be used for core measurement, its technical solution based on steady-state approximation and discrete point sampling results in low efficiency, high cost, and inability to reflect non-steady-state processes.

[0040] Therefore, there is an urgent need in this field for a nonsteady-state experimental method and system that can rapidly, directly, and accurately measure the relative permeability of multiple phases in consolidated rock cores and has the ability to control the saturation path.

[0041] To address the aforementioned issues, this specification provides a method for determining the relative permeability of multiphase reservoirs. Through gas-assisted gravity displacement experiments, it overcomes the challenge of gravity displacement in consolidated cores due to strong capillary forces and insufficient gravity drive, enabling direct measurement techniques based on CT imaging to be applied to real reservoir cores such as sandstone and carbonate rocks. Furthermore, during unsteady-state processes, it eliminates reliance on outlet data and empirical inversion models, directly utilizing the saturation field information within the core to quickly and accurately obtain continuous multiphase relative permeability curves. In addition, by using preset experimental parameters, including gas-phase and liquid-phase control parameters, the method allows for active control and pre-setting of the saturation change trajectory (path) during the experiment, facilitating the systematic study of the path dependence (hysteresis effect) of relative permeability and providing more reliable constitutive relationships for reservoir numerical simulation.

[0042] The method for determining the relative permeability of reservoir multiphases provided in this specification will be described below with reference to the accompanying drawings. The relative permeability of multiphases can be understood as the ratio of the effective permeability of a certain phase fluid to the absolute permeability of the core in a porous medium in which multiple phases (e.g., including at least two phases such as oil, water, gas, and liquid hydrocarbons) coexist. It is a core parameter characterizing the seepage capacity of multiphase fluids. The following embodiments use the determination process of three-phase relative permeability as an example. In other embodiments, the relative permeability of reservoir multiphases may also include the relative permeability of more or fewer phases, which is not limited in this specification.

[0043] Figure 1The diagram illustrates a method for determining the relative permeability of multiphase reservoirs provided in an embodiment of this specification. While this specification provides method operation steps or apparatus structures as shown in the following embodiments or figures, the method or apparatus may include more or fewer operation steps or module units, either combined or without inventive effort, based on conventional methods or without inventive effort. In steps or structures where there is no logically necessary causal relationship, the execution order of these steps or the module structure of the apparatus is not limited to the execution order or module structure shown in the embodiments or figures of this specification. When the method or module structure is applied in actual devices, servers, or terminal products, it can be executed sequentially or in parallel according to the method or module structure shown in the embodiments or figures (e.g., in a parallel processor or multi-threaded processing environment, or even in a distributed processing or server cluster implementation environment). Figure 1 As shown, it may include: S101: Obtain the preset experimental parameters for the gas-assisted gravity displacement experiment of the target reservoir; the preset experimental parameters include at least gas phase control parameters and liquid phase control parameters for assisting gravity displacement.

[0044] Gas-assisted gravity displacement experiments involve applying a constant gas pressure to the top of a vertically placed core sample, using the fluid's own gravity to jointly drive the downward seepage and displacement of liquid fluid within the sample. The control parameters used to apply the constant gas pressure are the gas-phase control parameters used to assist gravity displacement, which can overcome the capillary resistance of the consolidated core and initiate and maintain the gravity displacement process. Furthermore, during this process, the liquid-phase control parameters used to assist gravity displacement can be used to control the saturation trajectory of the liquid fluid. The saturation of the liquid fluid is maintained at a preset level. The liquid fluid can include, for example, water or oil, and corresponding control parameters can be preset for at least one phase. The saturation trajectory can be understood as the trajectory of the saturation of the multiphase fluid within the core during the displacement process. Different saturation paths lead to a significant hysteresis effect in relative permeability, making it a key input parameter for reservoir numerical simulation.

[0045] For example, the control parameters for the liquid phase fluid may include the injection rate of the fluid, which can be any non-negative velocity value. If the injection rate of the liquid phase fluid is zero, it indicates that the control phase used to assist gravity displacement is the gas phase, and the saturation trajectory of the gas-assisted gravity displacement experiment shows gas increase while other phases remain unchanged. If the injection rate of the liquid phase fluid is any other value, it indicates that the control phase used to assist gravity displacement includes both the gas phase and the corresponding liquid phase, and the saturation trajectory of the gas-assisted gravity displacement experiment shows gas increase and corresponding liquid phase increase while other phases remain unchanged. Furthermore, the saturation distribution data collected from gas-assisted gravity displacement experiments based on different saturation paths are different.

[0046] In some embodiments of this specification, the gas phase control parameters may include the injected gas pressure at the top of the core sample and the gas back pressure at the bottom of the core sample in the gas-assisted gravity displacement system; the liquid phase control parameters may include the fluid type and fluid injection rate of the liquid fluid injected at the top of the core in the gas-assisted gravity displacement system.

[0047] The injected gas pressure at the top of the core sample can be used to overcome the capillary inlet pressure of the core and assist gravity in driving the liquid fluid downwards. This injected gas pressure must be greater than the gas-liquid capillary inlet pressure of the core sample. The injected gas pressure can be determined by methods such as gas-drive testing and mercury intrusion porosimetry.

[0048] For example, the gas-driven testing method may include: loading the pretreated core into a holder, saturating it to the initial oil-water state of the experiment, slowly increasing the pressure from the top of the core at a preset rate, monitoring the pressure change at the core outlet end through a high-precision pressure sensor, and recording the top pressure at this time when gas pressure is first detected at the outlet end and there is a continuous gas phase outflow, which is the capillary inlet pressure of the core; multiplying this by a safety factor greater than 1, such as 1.2-2.0, as the injection gas pressure for the experiment.

[0049] For example, the mercury intrusion conversion method may include: measuring the pore throat distribution of the core through mercury intrusion experiments, the mercury ingress pressure of the mercury intrusion curve corresponds to the minimum pressure required for the non-wetting phase to enter the largest pore, and converting it into the capillary ingress pressure under the gas-water / gas-oil system through correction of interfacial tension and contact angle, and then multiplying it by a safety factor greater than 1, such as 1.2-2.0, as the injection gas pressure for the experiment.

[0050] The gas back pressure at the bottom of the core sample can be a constant back pressure applied at the bottom outlet of the core sample to simulate the formation pressure environment of the target reservoir. Simultaneously, the total pressure difference between the two ends of the core can be controlled to adapt to different experimental scenarios. There are two main experimental scenarios: atmospheric pressure and high-pressure formation simulation. The atmospheric pressure scenario is suitable for basic mechanism experiments in conventional dead oil systems. The bottom outlet of the core is directly vented to the atmosphere, and the back pressure is set to 0 kPa, which facilitates the free flow of fluid under gravity. The high-pressure formation simulation scenario is suitable for experiments requiring simulated formation conditions, such as deep reservoirs, active oil systems, and CO2 miscible flooding. A high-precision back pressure valve sets the bottom back pressure to the formation pressure of the target reservoir, ensuring that the physical properties of the experimental fluid are consistent with the actual working conditions of the reservoir.

[0051] The injected fluid type refers to the liquid phase fluid synchronously injected from the top of the core sample during gas-assisted gravity displacement, including aqueous, oil, or water-oil mixtures, which can control the saturation change path. The fluid injection rate is the injection volumetric flow rate of the liquid phase fluid, which can be used to regulate the rate of saturation change of the corresponding phase within the core, allowing for precise control of the saturation path. The fluid injection rate can be determined based on the pore volume of the core sample, displacement time, and target saturation change rate. It is crucial to ensure a sufficiently low injection rate to prevent viscous forces from dominating and disrupting the dominant gravity displacement mode, ensuring that gravity and the gas phase pressure gradient remain the core driving forces throughout the experiment.

[0052] In the embodiments described in this specification, by precisely controlling the top injection pressure and bottom back pressure, it is possible to adapt to consolidated cores with different permeabilities and capillary forces, ensuring the smooth start-up and stable operation of gas-assisted gravity displacement. By flexibly adjusting the type and rate of the injected fluid, active control of the saturation change trajectory can be achieved, enabling systematic study of the relative permeability hysteresis effect under different saturation paths, providing a more realistic constitutive relationship for reservoir numerical simulation. Through the coordinated control of gas phase and liquid phase control parameters, the actual seepage process of reservoirs with different burial depths and development methods can be accurately simulated, making the experimental results more consistent with the field conditions and improving the engineering application value of the experimental data.

[0053] S102: Construct a gas-assisted gravity displacement system based on core samples from the target reservoir, and conduct gas-assisted gravity displacement experiments using the preset experimental parameters based on the gas-assisted gravity displacement system.

[0054] Before conducting gas-assisted gravity displacement experiments, a gas-assisted gravity displacement system can be built based on core samples, and the core samples can be initialized. Core sample initialization can include, for example, establishing the initial saturated liquid phase state of the core, completing the dry core required for CT scanning, calibration scanning under 100% saturated water, and 100% saturated oil conditions, etc.

[0055] refer to Figure 2 As shown, in some embodiments of this specification, step S102 above, which involves conducting an air-assisted gravity displacement experiment based on the preset experimental parameters using the air-assisted gravity displacement system, may include: S201: While applying the injection gas pressure to the top of the core sample, inject a fluid of the corresponding fluid type into the core sample at the fluid injection rate.

[0056] S202: Maintain the bottom of the core sample under the gas back pressure, start the gas-assisted gravity displacement experiment, and continue until the change in fluid saturation in the core sample tends to stop, thus completing the gas-assisted gravity displacement experiment.

[0057] In practice, a gas-assisted gravity displacement system can be constructed based on core samples from the target reservoir to conduct the experiment. A cleaned and dried cylindrical core can be placed in a vertical holder, and confining pressure can be applied to simulate formation stress conditions. After vacuuming the core, it is sequentially saturated with brine and then with the oil phase to establish a specific initial oil-water two-phase saturation state. Calibration scans are performed under conditions of dry core, 100% water saturation, and 100% oil saturation required for CT scanning to establish a quantitative relationship between CT values ​​and fluid saturation. Subsequently, the gas-assisted gravity displacement experiment is initiated using preset experimental parameters: a preset injection gas pressure is applied to the top of the core, and simultaneously, the corresponding type of fluid (water phase, oil phase, or water-oil mixture, etc.) is injected into the top of the core at a preset fluid injection rate, while the bottom of the core is maintained at a preset gas back pressure. The experiment continues until the fluid saturation change within the core tends to stop, i.e., the system reaches a quasi-steady state.

[0058] For example, a well-constructed air-assisted gravity exhaust system can be referenced. Figure 3 As shown, the system may include a core clamping and precision displacement module, an in-situ dynamic monitoring module, a data synchronous acquisition and control module, and a data processing and inversion calculation module.

[0059] The core holding and precision displacement module may include a vertically placed pressure-resistant core holder (for loading cylindrical core samples, such as...) Figure 3 PEEK clamps), high-precision constant speed and constant pressure injection pumps (used to control water / oil injection, for example) Figure 3 ISCO pumps), high-precision gas pressure regulation and metering units (e.g., Figure 3 (including a precision pressure regulating valve), and a bottom back pressure controller and fluid collection device (e.g., including...) Figure 3 The components include an outlet switch, pressure sensor, vacuum pump, and backpressure valve. The core holder ensures the core is sealed under confining pressure, while the injection pump and pressure system are used to achieve "air-assisted gravity exhaust" and path control.

[0060] The in-situ dynamic monitoring module can be a medical CT or microfocus CT scanner, and can be configured with a corresponding high-precision electric displacement platform. The CT scanner is used to penetrate the core holder to obtain the attenuation signal of the internal fluid distribution, and the displacement platform is used for precise positioning during the experiment, so that the CT scanning plane can move point by point along the core axis, thereby obtaining a two-dimensional or three-dimensional saturation distribution image of the entire core.

[0061] The data synchronization acquisition and control module can include a computer, a data acquisition card, and control software. It can synchronously record sensor data such as injection pressure, flow rate, and back pressure, and control the triggering of CT scans, the movement of the displacement platform, and the start, stop, and switching of the injection pump, ensuring that the experimental process and data acquisition are strictly synchronized in time.

[0062] The data processing and inversion calculation module may include a computer running dedicated algorithm software. This module can receive raw CT data, perform image reconstruction, calibration, and phase saturation calculation to obtain S. w (z,t), S o (z,t), S g (z,t). Then, the method for determining the multiphase relative permeability of the reservoir as described in the embodiments of this specification is executed, and finally the multiphase relative permeability curve and its relationship with saturation are output.

[0063] In the above embodiments, the saturation path can be controlled by injecting a fluid of the corresponding fluid type into the core sample at the fluid injection rate. To further illustrate the relationship between controlling the flow rate and controlling the saturation path, the above control process will be described below in conjunction with specific implementations.

[0064] To measure relative permeability along different paths, experiments require the design of multi-round or multi-stage control schemes. (1) Stage 1: Initialization: Establish the core to a uniform initial state (e.g., bound water + residual oil + gas, or bound water + oil).

[0065] (2) Stage Two: Setting the "Main Control Phase" and "Auxiliary Control Phase" Main Control Phase (Gas Phase): Set the top gas injection pressure Pgas to a constant value (e.g., 60 kPa) and keep it always on. Auxiliary Control Phase (Water Phase / Oil Phase): This is the key to the control path.

[0066] (3) Phase 3: Differentiated Injection

[0067] Path A (pure gravity oil drain): Set water injection rate Qw = 0. The fluid is driven only by gravity and air pressure. Saturation trajectory: water remains constant, oil decreases, and gas increases.

[0068] Path B (Water Injection Assisted Oil Drainage): Set water injection rate Qw = 0.05 ml / min. Saturation trajectory: Water increases slowly, oil decreases, gas increases.

[0069] Path C (Forced Water Injection and Oil Drainage): Set water injection rate Qw = 0.1 ml / min. Saturation trajectory: Water increases rapidly, oil decreases, and gas increases.

[0070] (4) Stage 4: Steady-state determination and data acquisition

[0071] Under each injection ratio, scanning continued until oil ceased to flow from the core outlet or the saturation distribution reached a new dynamic equilibrium.

[0072] Furthermore, the collected S(z,t) and the calculated k can be... roThe data is categorized according to experimental batches (paths A, B, and C). For the data from path A, a set of Corey parameters (S) is fitted. or A , k ro,max A , n o A For the data in path B, fit another set of parameters (S). or B , k ro,max B , n o B The same applies to path C. S or A Not equal to S or B This is path dependency.

[0073] S103: Obtain the saturation distribution data collected by the air-assisted gravity exhaust system.

[0074] Saturation distribution data can be a dataset of the spatiotemporal distribution of multiphase saturation at different times and axial positions within a core sample. It forms the basis for the direct calculation of relative permeability. This saturation distribution data can be obtained by further processing CT data scanned by a CT scanner in a gas-assisted gravity displacement system. For example, since the embodiments in this specification require solving for multiphase relative permeability data, it is necessary to obtain the saturation distribution data of each phase. Therefore, a dual-energy CT scanner can be used, that is, a tomographic scan of the core sample is performed using two different X-ray tube voltages. The difference in X-ray attenuation coefficients for different fluids at the two energies is used to establish an equation system to solve for the saturation of the three-phase fluid. Dual-energy CT scanning can distinguish the three-phase saturation data.

[0075] In practice, CT scanners can perform two scans by rapidly switching voltages at each point, or by using dual-source CT, where different sources correspond to different X-rays, to achieve dual-energy CT scanning.

[0076] refer to Figure 4 As shown, in some embodiments of this specification, obtaining the saturation distribution data collected by the gas-assisted gravity exhaust system may include: S401: During the gas-assisted gravity displacement experiment, the CT scanner in the gas-assisted gravity displacement system is used to control the displacement platform of the gas-assisted gravity displacement system to move the core sample point by point at preset time intervals, and the CT data of the core sample at different times is recorded to complete the axial scanning of the core sample.

[0077] The preset time interval can be, for example, 30 minutes. Point-by-point movement can be used to move the core sample according to the preset point intervals, and perform a scan at each point. The point interval can be, for example, 2 cm. That is, a tomographic scan is performed every 2 cm along the length of the core using a CT scanner. During the scanning process, the CT data corresponding to each point, the location data of each point, and the time of scanning the CT data at each point can be recorded.

[0078] In practice, the raw CT data acquired by the CT scanner may need to be further processed for subsequent calculation of saturation distribution data. The data processing workflow may include: preprocessing the raw CT data by performing image reconstruction, Gaussian denoising, geometric registration, and bad pixel removal to eliminate motion artifacts and noise interference during the scanning process.

[0079] S402: Based on the CT data obtained from the scan and the CT reference values ​​corresponding to each phase fluid under the preset saturation state, the saturation distribution data is obtained.

[0080] The CT baseline values ​​corresponding to each phase of fluid can be, for example, in a core sample at 100% oil (CT). o ), 100% water (CT) w ) and 100% gas (CT) g CT value under saturation.

[0081] Taking dual-energy CT scanning with a CT scanner as an example, the saturation distribution data can be determined as follows: First, measure the CT values ​​of the core sample under 100% oil (CTo), 100% water (CTw), and 100% gas (CTg) saturation conditions respectively; acquire CT scan data in high-energy (e.g., 140kV) and low-energy (e.g., 100kV) modes. Since dual-energy CT is used, each phase has two reference values: high-energy (H) and low-energy (L), for a total of six parameters: CT... o H (Criterion value of oil phase in high-energy mode), CT o L (Criterion value of oil phase in low-energy mode), CT w H (Water phase CT baseline value in high-energy mode), CT w L (Water phase CT baseline value in low-energy mode), CT g H (Gas phase CT baseline values ​​in high-energy mode), CT g L (Gas phase CT baseline values ​​in low-energy mode); The following solution matrix is ​​established based on six parameters: Formula (1) Among them, So S w and S g These represent oil phase saturation, water phase saturation, and gas phase saturation, respectively; CT H mix and CT L mix The numbers represent the CT data obtained by scanning at various points in high-energy mode and low-energy mode during the air-assisted gravity displacement experiment, respectively, which are also the measured CT data.

[0082] Furthermore, linear algebra methods (such as Cramer's rule or matrix inversion) can be used to solve the above formula (1) to obtain the S of the corresponding point. o S w S g .

[0083] S104: Based on the saturation distribution data and the preset experimental parameters, determine the relative permeability of the multiphase fluid in the core sample as the target relative permeability corresponding to the target reservoir.

[0084] In practice, the relative permeability of multiphase fluids can be calculated based on saturation distribution data and preset experimental parameters characterizing the experimental boundary, combined with the principles of seepage mechanics, without the need for traditional unsteady-state methods to invert the flow splitting theory assumptions and outlet data.

[0085] To improve the accuracy of the calculation results, sections with relatively gentle saturation gradients in the core sample can be selected from the saturation distribution data as the basis for relative permeability calculation. For example, a section with relatively gentle saturation in the middle of the core sample can be selected to eliminate the influence of capillary end effects at both ends of the core sample. Furthermore, based on the principle of mass conservation, the Darcy velocity (i.e., fluid flux) of each phase fluid in this section can be calculated using the difference in saturation profiles between adjacent time steps. The effective gas pressure gradient of this section can be determined through numerical simulation correction or empirical formula methods. The fluid flux, effective gas pressure gradient, and the absolute permeability of the core sample, fluid viscosity, and density are then substituted into a pre-constructed formula model to obtain the relative permeability of the multiphase fluid. The average saturation at the corresponding time is then matched, and finally, a complete three-phase relative permeability curve is plotted.

[0086] refer to Figure 5 As shown, in some embodiments of this specification, determining the relative permeability of the multiphase fluid in the core sample based on the saturation distribution data and the preset experimental parameters may include: S501: Based on the saturation distribution data and the preset experimental parameters, determine the fluid flux of each phase fluid in the target section of the core sample.

[0087] Considering the initial disturbance from gas phase entry at the top inlet of the core sample and the sudden pressure and saturation changes caused by capillary end effects at the bottom outlet, some sections of the core sample do not satisfy the basic assumption that the capillary pressure gradient is negligible, which will introduce significant systematic errors. To ensure the validity of the basic assumptions during the calculation and improve the accuracy and reliability of the calculation, a region with a gentle saturation gradient in the middle of the core sample can be selected as the target section. For example, the selection principle of the target section can include: the axial gradient dS of the saturation of each phase within the section. i / dz is less than 0.01 / cm; there is no obvious displacement front in the section, and the saturation is uniformly distributed; the section length is not less than 1 / 3 of the total core length, etc.

[0088] Furthermore, after determining the target section and selecting the saturation distribution data corresponding to the target section, the fluid flux of each phase fluid in the target section can be calculated based on the mass conservation principle of unsteady seepage and the difference in saturation profiles between adjacent time steps, without relying on the flow metering data at the outlet end.

[0089] In some embodiments of this specification, the fluid flux of each phase fluid can be determined by the following formula: Formula (2) in, u i ( z K , t j+1 / 2 ) indicates at time step t j+1 / 2 Points z K First i Fluid flux of the phase fluid; u i,inj This indicates the injection rate of fluid at the top of the core sample; The porosity of the core sample is represented by K; K represents the number of points in a single CT scan during the gas-assisted gravity displacement experiment. S i ( z k , t j+1 )and S i ( z k , t j ) represent the points respectively z k At time step i, the fluid of phase i t j and time step t j+1Saturation data; Δ z This indicates the spacing of the CT scan during the air-assisted gravity displacement experiment.

[0090] S502: Based on the property parameters of the core sample and the preset experimental parameters, determine the effective gas pressure gradient of the target section.

[0091] The gas pressure gradient is the rate of change of gas pressure along the length of the core. For high-permeability media (such as sand columns), the gas pressure gradient is extremely small and often negligible. However, in the embodiments of this specification, a relatively large auxiliary injection gas pressure P is artificially applied. top To overcome capillary forces, the gas pressure gradient is non-zero and must be considered as a driving force term in Darcy's formula. Considering the nonlinear gas pressure distribution caused by the capillary end effect in consolidated cores, the gas pressure drops sharply at the core sample outlet, making the average pressure gradient unsuitable. Instead, numerical simulation correction or empirical formulas can be used to determine the absolute value of the effective gas pressure gradient |G| (i.e., the effective gas pressure gradient) within the target section to avoid calculation errors caused by neglecting the gas pressure gradient.

[0092] In practice, a numerical simulation correction method can be used to establish a numerical model that is exactly the same as the experimental conditions. The k, Φ, Pc(S) curves of the core sample and the injection gas pressure P of the experiment can be input. top Gas back pressure P bottom After running the simulation, the absolute value of the gas pressure gradient in the linear region of the core is extracted as |G| from the results.

[0093] In practice, a numerical model with parameters consistent with the experiment can be established to simulate and calculate the pressure distribution along the path under steady state. The slope of the linear segment in the middle of the rock core can be extracted as |G|. Through a large number of simulations and calibrations, the correlation between the effective gas pressure gradient and the injected gas pressure, gas back pressure, inlet capillary pressure, and empirical parameters can be constructed to obtain the empirical formula for the effective pressure gradient.

[0094] In some embodiments of this specification, the effective gas pressure gradient can be determined by the following formula: Formula (3) Where |G| represents the effective gas pressure gradient, Δ P total This represents the difference between the injected gas pressure at the top of the core sample and the gas back pressure at the bottom of the core sample. P c,entry To represent the inlet capillary pressure at the top of the core sample, L represents the length of the core sample, and α and β represent preset coefficients, i.e. empirical coefficients obtained from simulation calibration, such as α≈0.283 and β≈0.45.

[0095] S503: Based on the fluid flux of each phase fluid and the effective gas pressure gradient, determine the relative permeability of the multiphase fluid in the core sample.

[0096] In practice, the calculated fluid flux and effective gas pressure gradient can be combined with the absolute permeability, fluid viscosity and density of the core sample, and substituted into the relative permeability calculation formula derived based on Darcy's law to obtain the relative permeability of the multiphase fluid, while recording the average saturation at the corresponding time.

[0097] In some embodiments of this specification, the relative permeability of the multiphase fluid can be determined by the following formula: Formula (4) in, k ri ( z K , t j+1 / 2 ) indicates at time step t j+1 / 2 Points z K First r Phase fluid and i The relative permeability of the phase fluid; u i ( z K , t j+1 / 2 ) indicates at time step t j+1 / 2 Points z K In the middle i Fluid flux of the phase fluid; μ i and ρ i Indicates the fluid viscosity and fluid density of the core sample; k 0 represents the absolute permeability of the core sample; |G| represents the effective gas pressure gradient.

[0098] In the embodiments described in this specification, during gas-assisted gravity displacement experiments, the seepage process of three-phase fluids in oil and gas reservoirs can be simulated more accurately and realistically by using gas-phase control parameters and liquid-phase control parameters, thereby controlling the saturation change path. Based on this, by collecting saturation distribution data and combining it with preset experimental parameters, the multiphase relative permeability can be determined more directly, accurately, and efficiently. Furthermore, the gas-assisted gravity displacement experiment can be precisely controlled using gas-phase and liquid-phase control parameters, which can be flexibly adjusted based on the physical properties of different reservoirs. This approach has strong universality and scalability, and can be applied to the determination of multiphase relative permeability in various types of reservoirs.

[0099] The derivation process of formulas (2) to (4) above is as follows: For each phase of fluid (i = w, o, g) in a porous medium, the seepage follows Darcy's law. In one-dimensional vertical flow (z-axis downwards is positive): Formula (5) in: u i Indicates the first i Darcy velocity of a phase (volume flow rate per unit time through a unit cross-sectional area), m / s. k 0 represents the absolute permeability of the core sample, in m². k ri Indicates the first i The relative permeability of the phase is dimensionless. μ i Indicates the first i The fluid viscosity of the phase, Pa·s. Φ i Indicates the first i Total potential energy of a phase, J / kg. z This represents the coordinates along the axial direction of the core sample, with the origin at the top of the core sample and downwards as positive, in meters (m).

[0100] Total potential energy includes pressure potential and gravitational potential: Formula (6) in: P i Indicates the first i The fluid pressure of the phase, Pa. ρ i Indicates the first i The fluid density of the phase, kg / m³. g This represents the acceleration due to gravity, 9.81 m / s².

[0101] Calculate the spatial gradient of the total potential energy: Formula (7) Substituting Darcy's law, we get: Formula (8) Simplification by ignoring the capillary pressure gradient: In the middle section of the core sample, a region with a gradual change in saturation is selected, where the capillary pressure gradient can be ignored, i.e.: .

[0102] For a water-humidified system, the capillary pressure relationship is as follows: Gas-oil capillary pressure: P cgo =P g -P o ; Oil-water capillary pressure: P cwo =P o -P w ; Differentiate the pressure relationship: Formula (9) In the region where the saturation change is gradual, the capillary pressure gradient can be ignored: Formula (10) Substituting the simplified relationship above into Darcy's law and rearranging, we obtain the expression for relative permeability: Formula (11) For the oil phase: Formula (12) For the aqueous phase: Formula (13) Due to dP g / dz is a negative value, defining the absolute value of the effective gas pressure gradient: Formula (14) The above formula can then be written as: Formula (15) Based on the mass conservation equation: Formula (16) Integrating the spatial coordinate z from the top (0) to any position z, we get: Formula (17) Summarized as follows: Formula (18) Discretization is performed, and the time derivative is approximated using a difference method: Formula (20) Spatial integrals are approximated by summation: Formula (21) The final result is: Formula (22) in: u i,inj This indicates the injection rate (known or controllable) of this phase at the top of the core sample, in m / s. This indicates the porosity of the core sample and is dimensionless. S i ( z k ,t j ) indicates the position z k and time t j The measured number i Phase saturation. Δ z This indicates the spatial spacing in meters (m) of a CT scan. t j and t j+1 This represents the time between two consecutive CT scans, expressed in seconds.

[0103] Due to the capillary effect, the gas pressure gradient needs to be corrected. Let the actual gas pressure distribution be P. g (z), the ideal linear distribution is: Formula (23) However, due to the terminal effect, the actual distribution deviates from linearity. This invention, through numerical simulation, reveals that the actual effective gradient can be expressed as: Formula (24) Where ΔP end This is the pressure drop consumed by the terminal effect. Through numerous simulations, it was found that: Formula (25) Therefore, the empirical formula is obtained: Formula (26) Where: Δ P total = P top -P bottom Total pressure difference, Pa. P c,entry This represents the gas-liquid inlet capillary pressure of the core sample, in Pa. L This indicates the length of the core sample, in meters (m).α ≈0.283, β ≈0.45, which is an empirical coefficient (obtained through simulation calibration of standard core samples).

[0104] This specification also provides an embodiment of a method for directly measuring the relative permeability of multiphase cores using gas-assisted gravity displacement combined with in-situ CT monitoring. Figure 3 Taking the system in question as an example, this method may include the following steps: Step S1: System Preparation and Core Initialization. The cleaned and dried cylindrical core is loaded into the vertical clamp and confining pressure is applied. The core is then evacuated, followed by sequential saturated brine and oil phases to establish a specific initial oil-water two-phase saturation state (S). wi S oi Calibration scans were performed using dry cores, 100% water saturation, and 100% oil saturation conditions required for CT scans.

[0105] Step S2: Initiate gas-assisted gravity displacement and path control. Apply a stable gas pressure (P) above atmospheric pressure to the top of the core. top This pressure value needs to be greater than the gas-liquid capillary inlet pressure of the core to overcome the initial displacement resistance. Simultaneously, the bottom of the core should remain connected to the atmosphere or maintain a low back pressure (P0). bottom This operation initiates "gas-assisted gravity displacement": gas pressure gradient (gas pressure gradient = (P...) top - P bottom The oil and water phases are driven downward by gravity. To achieve a specific saturation path, the water phase (or oil phase) can be selectively injected from the top of the core at a constant low flow rate during this stage, so as to maintain the water saturation (or oil saturation) at a preset level throughout the displacement process.

[0106] Step S3: In-situ CT Scan and Data Acquisition. After the displacement process begins, the CT scan program is started. At preset time intervals (e.g., every 30 minutes), the displacement platform is controlled to move the core point by point, completing a full axial scan of the entire core section (using dual-energy mode to distinguish the three phases). Simultaneously, the data acquisition system records the injection pressure, flow rate, and back pressure at each moment. This process is repeated until the fluid saturation change within the core tends to stop, obtaining a series of spatiotemporally discrete saturation profile datasets S. i (z k ,t j The data includes the fluid injection flow rate (used to determine the inlet velocity boundary), the injection pressure at the top of the core, and the outlet back pressure at the bottom (used to determine the pressure gradient boundary along the core).

[0107] Step S4: Data Processing and Relative Penetration Calculation. This step is the core calculation process of this invention and includes three sub-steps: S4.1 Calculate the fluid flux ui: Based on the principle of mass conservation, utilize adjacent time steps (t... j , t j+1 The Darcy velocities of each phase fluid in the core section (selecting a region with a gentle saturation gradient) are calculated using the aforementioned formula (2) based on the saturation profile difference of the core section.

[0108] S4.2 Correction and Acquisition of the Effective Gas Pressure Gradient |G|: This is a key innovation for accurate core calculation. Due to the capillary end effect, the gas pressure drops sharply at the core outlet, making the average pressure gradient unusable. This invention employs a numerical simulation correction method: a numerical model identical to the experimental conditions is established, and the k, Φ, Pc(S) curves of the core and the experimental P are input. top ,P bottom After running the simulation, the absolute value of the gas pressure gradient in the linear region of the core is extracted as |G|. Preferably, an empirical formula based on a large number of simulation calibrations can be used for rapid estimation: ; where ΔP total = P top - P bottom P c,entry Where is the inlet capillary pressure, is the core length, α≈0.283, and β≈0.45 are empirical coefficients.

[0109] S4.3 Calculate the relative permeability k ri : The u calculated by S4.1 i The |G| determined in S4.2, and the known core properties k and fluid properties μ i ,ρ i Substitute into the aforementioned formula (4) to calculate the relative permeability of any two phases.

[0110] At the same time, record the average saturation S corresponding to this calculation point. i (z K ,t j+1 / 2 For all spatial locations z K and time interval [t] j ,t j+1 By repeating the above calculations, a large number of (S) can be obtained. i ,k ri The data points are plotted to create a complete relative permeability curve.

[0111] Step S5: Results Analysis and Application. Analyzing the obtained relative permeability curves allows for the study of hysteresis behavior under different saturation paths. The data obtained under different paths are plotted as dynamic saturation (S0). o -Sor The functions can be used to verify physical laws. Ultimately, this high-precision experimental data can be directly used as input for reservoir numerical simulators to optimize development plans.

[0112] To fully disclose and understand the method for determining the relative permeability of reservoir multiphases or the direct measurement method of relative permeability of core multiphases using gas-assisted gravity displacement combined with CT in-situ monitoring in the above embodiments, the above methods and their effects will be further explained below with reference to specific embodiments based on Berea sandstone cores.

[0113] Target audience and conditions: Core: Berea sandstone plunger, length L = 0.60 m, diameter 0.076 m. Gas permeability k = 3.0 × 10⁻¹³ m² (approximately 300 mD), porosity... =0.21.

[0114] fluid: Aqueous phase (W): 10 wt% sodium bromide (NaBr) brine (density 1069 kg / m3, viscosity 1.23 cp).

[0115] Oil phase (O): Crude oil (density 958 kg / m3, viscosity 30 cp).

[0116] Gas phase (G): Dry air (density 1.2 kg / m3, viscosity 0.02 cp).

[0117] Equipment: Medical spiral CT scanner (130 kV / 80 kV dual-energy), precision confining pressure pump, high-precision Quizix dual plunger pump, gas pressure regulator, vertically placed core holder.

[0118] Experimental Procedure: This embodiment designed three tests with different saturation paths (Test 1, Test 2, Test 3) to verify the method's ability to control the saturation path.

[0119] Step A: Initial State Establishment

[0120] The core was vacuumed and saturated with water, followed by oil-water flooding to establish the initial oil-water distribution (bound water state).

[0121] For Test 1, it is not necessary to inject oil or water from the top simultaneously; for Tests 2 and 3, a specific steady-state initial saturation distribution is established by injecting oil and water from the top simultaneously before the experiment begins.

[0122] Step B: Gravity draining and fluid injection

[0123] Place the core vertically with the bottom outlet open to the atmosphere.

[0124] Gas injection: In all tests, air was injected from the top of the core at a constant injection pressure of 8.96 psig (approximately 61.8 kPa). This pressure was slightly higher than the capillary inlet pressure of the core to overcome the capillary end effect and allow the fluid to be smoothly discharged under gravity, unlike traditional loose sandstone experiments that rely solely on gravity.

[0125] Saturation path control: While injecting gas, water phase is injected from the top at different rates to control the saturation change trajectory within the core. Test 1: Water phase injection rate was 0 cc / min (pure gas displacement, simulating traditional gravity oil drainage).

[0126] Test 2: Water phase injection rate was 0.1 cc / min (gas drive + high-speed water injection).

[0127] Test 3: Water phase injection rate was 0.05 cc / min (air drive + low-speed water injection).

[0128] Step C: Data Acquisition

[0129] A CT scanner was used to perform tomographic scans every 2 cm along the length of the core sample. The scans continued throughout the entire experiment (Test 1 lasted approximately 8.6 days, and Test 2 lasted approximately 10.7 days), and the number of CT scans along the core sample was recorded at different times.

[0130] Step D: Data Processing

[0131] Saturation calculation: Using the principle of dual-energy CT (such as 100 kV and 140 kV), the saturation of water, oil and gas three phases S_w(z,t), S_o(z,t), and S_g(z,t) at different times and locations are calculated.

[0132] Valid region selection: The central 20-40 cm area of ​​the core was selected as the calculation zone. As the CT profile shows, this region is far from the capillary end effect zone at the top inlet and bottom outlet, and the saturation is uniformly distributed along the path (gradient dS / dz is minimal), satisfying the assumption that the capillary force gradient should be ignored.

[0133] Relative permeability calculation: Using the mass balance equation and based on the aforementioned formula (2), the Darcy velocity u of each phase is calculated by integrating the rate of change of saturation over time dS / dt. io The effective pressure gradient |G| is calculated based on the aforementioned formula (3). The Darcy velocity and the effective pressure gradient are then substituted into the aforementioned formula (4) to calculate the relative permeability.

[0134] Step E: Experimental Results

[0135] Saturation Path Differences: By varying the injection rate of top water, three completely different three-phase saturation paths were successfully achieved, resulting in three different sets of curves showing the relative permeability (kro) of the three-phase oil phase as a function of oil phase saturation (So), i.e., the relative permeability curves of the three-phase oil phase: as shown below. Figure 6 , Figure 7 , Figure 8 As shown. Figure 6 The figure shows the relative permeability curve of the three-phase oil phase in Test 1. Figure 7 To test the relative permeability curve of the three-phase oil phase in step 2, Figure 8 The relative permeability curves of the three-phase oil phase were tested. (From...) Figures 6 to 8 It can be seen that, under the same oil phase saturation (So), there are significant differences in the relative permeability (kro) of the oil phase measured by different paths (i.e., there is a hysteresis effect). It is evident that the method in the embodiments of this specification can be effectively applied to consolidated cores and can accurately measure the multiphase relative permeability under a specific saturation history by controlling the injection conditions, which can overcome the defect of traditional unsteady-state methods that cannot control the path.

[0136] Based on the method for determining the relative permeability of multiphase reservoirs described above, one or more embodiments of this specification also provide an apparatus for determining the relative permeability of multiphase reservoirs. The apparatus may include devices (including distributed systems), software (applications), modules, plug-ins, servers, clients, etc., using the methods described in the embodiments of this specification, combined with necessary implementation hardware. Based on the same innovative concept, the apparatuses in one or more embodiments provided in this specification are as described in the following embodiments. Since the implementation schemes and methods for solving the problem by the apparatus are similar, the implementation of the specific apparatus in the embodiments of this specification can refer to the implementation of the foregoing method, and repeated details will not be elaborated further. As used below, the terms "unit" or "module" can refer to a combination of software and / or hardware that performs a predetermined function. Although the apparatus described in the following embodiments is preferably implemented in software, hardware implementation, or a combination of software and hardware, is also possible and contemplated. Figure 9 The diagram shown is a schematic representation of a reservoir multiphase relative permeability determination apparatus provided in an embodiment of this specification. Figure 9 As shown, the apparatus 900 for determining the relative permeability of the multiphase reservoir may include: The first acquisition module 901 is used to acquire preset experimental parameters for the gas-assisted gravity displacement experiment of the target reservoir; the preset experimental parameters include at least gas phase control parameters and liquid phase control parameters for assisting gravity displacement. Experimental module 902 is used to build a gas-assisted gravity displacement system based on core samples of the target reservoir, and to conduct gas-assisted gravity displacement experiments based on the preset experimental parameters of the gas-assisted gravity displacement system. The second acquisition module 903 is used to acquire saturation distribution data collected by the air-assisted gravity exhaust system; The determination module 904 is used to determine the relative permeability of the multiphase fluid in the core sample as the target relative permeability corresponding to the target reservoir based on the saturation distribution data and the preset experimental parameters.

[0137] The descriptions and functions of the above modules can be understood by referring to the section on methods for determining the relative permeability of multiphase reservoirs, and will not be repeated here.

[0138] This application also provides an electronic device, such as... Figure 10 As shown, the electronic device may include a processor 1001 and a memory 1002, wherein the processor 1001 and the memory 1002 may be connected via a bus or other means. Figure 10 Taking the example of a connection between China and Israel via a bus.

[0139] Processor 1001 may be a central processing unit (CPU). Processor 1001 may also be other general-purpose processors, digital signal processors (DSPs), application-specific integrated circuits (ASICs), field-programmable gate arrays (FPGAs), or other programmable logic devices, discrete gate or transistor logic devices, discrete hardware components, or combinations thereof.

[0140] The memory 1002, as a non-transitory computer-readable storage medium, can be used to store non-transitory software programs, non-transitory computer-executable programs, and modules, such as the program instructions / modules corresponding to the method for determining the relative permeability of multiphase reservoirs in the embodiments of the present invention. The processor 1001 executes various functional applications and data processing of the processor by running the non-transitory software programs, instructions, and modules stored in the memory 1002, thereby implementing the method for determining the relative permeability of multiphase reservoirs in the above-described method embodiments.

[0141] The memory 1002 may include a program storage area and a data storage area. The program storage area may store the operating system and applications required for at least one function; the data storage area may store data created by the processor 1001, etc. Furthermore, the memory 1002 may include high-speed random access memory and may also include non-transitory memory, such as at least one disk storage device, flash memory device, or other non-transitory solid-state storage device. In some embodiments, the memory 1002 may optionally include memory remotely located relative to the processor 1001, and these remote memories may be connected to the processor 1001 via a network. Examples of such networks include, but are not limited to, the Internet, corporate intranets, local area networks, mobile communication networks, and combinations thereof.

[0142] The one or more modules are stored in the memory 1002, and when executed by the processor 1001, they perform the following method for determining the relative permeability of the reservoir multiphase: Pre-set experimental parameters for the gas-assisted gravity displacement experiment of the target reservoir are obtained; the pre-set experimental parameters include at least gas phase control parameters and liquid phase control parameters for assisting gravity displacement; a gas-assisted gravity displacement system is constructed based on the core sample of the target reservoir, and a gas-assisted gravity displacement experiment is conducted based on the gas-assisted gravity displacement system using the pre-set experimental parameters; saturation distribution data collected by the gas-assisted gravity displacement system is obtained; based on the saturation distribution data and the pre-set experimental parameters, the relative permeability of the multiphase fluid in the core sample is determined as the target relative permeability corresponding to the target reservoir.

[0143] The specific details of the aforementioned electronic device can be understood by referring to the relevant descriptions and effects in the above method embodiments, and will not be repeated here.

[0144] This specification also provides a computer storage medium storing computer program instructions, which, when executed, implement the steps of the method for determining the relative permeability of multiphase reservoirs described above.

[0145] This specification also provides a computer program product comprising a computer program that, when executed, implements the steps of the method for determining the relative permeability of multiphase reservoirs described above.

[0146] Those skilled in the art will understand that all or part of the processes in the methods of the above embodiments can be implemented by a computer program instructing related hardware. The program can be stored in a computer-readable storage medium, and when executed, it can include the processes of the embodiments of the above methods. The storage medium can be a magnetic disk, optical disk, read-only memory (ROM), random access memory (RAM), flash memory, hard disk drive (HDD), or solid-state drive (SSD), etc.; the storage medium can also include combinations of the above types of memory.

[0147] The various embodiments in this specification are described in a progressive manner. For the same or similar parts between the various embodiments, please refer to each other. The focus of each embodiment is to describe the differences from other embodiments.

[0148] The systems, devices, modules, or units described in the above embodiments can be implemented by computer chips or entities, or by products with certain functions.

[0149] For ease of description, the above devices are described separately by function as various units. Of course, in implementing this application, the functions of each unit can be implemented in one or more software and / or hardware.

[0150] As can be seen from the above description of the embodiments, those skilled in the art can clearly understand that this application can be implemented by means of software plus necessary general-purpose hardware platforms. Based on this understanding, the technical solution of this application, in essence, or the part that contributes to the prior art, can be embodied in the form of a software product. This computer software product can be stored in a storage medium, such as ROM / RAM, magnetic disk, optical disk, etc., and includes several instructions to cause a computer device (which may be a personal computer, server, or network device, etc.) to execute certain parts of the methods of various embodiments of this application.

[0151] This application can be used in a wide variety of general-purpose or special-purpose computer system environments or configurations. For example: personal computers, server computers, handheld or portable devices, tablet devices, multiprocessor systems, microprocessor-based systems, set-top boxes, programmable consumer electronics devices, network PCs, minicomputers, mainframe computers, distributed computing environments including any of the above systems or devices, etc.

[0152] This application can be described in the general context of computer-executable instructions, such as program modules, that are executed by a computer. Generally, program modules include routines, programs, objects, components, data structures, etc., that perform a specific task or implement a specific abstract data type. This application can also be practiced in distributed computing environments where tasks are performed by remote processing devices connected via a communication network. In distributed computing environments, program modules can reside in local and remote computer storage media, including storage devices.

[0153] Although this application has been described through embodiments, those skilled in the art will know that this application has many modifications and variations without departing from the spirit of this application, and it is intended that the appended claims cover such modifications and variations without departing from the spirit of this application.

Claims

1. A method for determining the relative permeability of multiphase reservoirs, characterized in that, include: Obtain the preset experimental parameters for the gas-assisted gravity displacement experiment of the target reservoir; The preset experimental parameters include at least gas phase control parameters for assisting gravity displacement and liquid phase control parameters for assisting gravity displacement. A gas-assisted gravity displacement system was built based on core samples from the target reservoir, and gas-assisted gravity displacement experiments were conducted using the preset experimental parameters based on the gas-assisted gravity displacement system. Acquire saturation distribution data collected by the air-assisted gravity exhaust system; Based on the saturation distribution data and the preset experimental parameters, the relative permeability of the multiphase fluid in the core sample is determined as the target relative permeability corresponding to the target reservoir. Based on the saturation distribution data and the preset experimental parameters, the relative permeability of the multiphase fluid in the core sample is determined, including: Based on the saturation distribution data and the preset experimental parameters, the fluid flux of each phase fluid in the target section of the core sample is determined. Based on the property parameters of the core sample and the preset experimental parameters, the effective gas pressure gradient of the target section is determined; The relative permeability of the multiphase fluids in the core sample is determined based on the fluid flux of each phase and the effective gas pressure gradient. The relative permeability of a multiphase fluid is determined by the following formula: ； in, k ri ( z K , t j+1 / 2 ) indicates at time step t j+1 / 2 Points z K First r Phase fluid and i The relative permeability of the phase fluid; u i ( z K , t j+1 / 2 ) indicates at time step t j+1 / 2 Points z K In the middle i Fluid flux of the phase fluid; μ i and ρ i Indicates the fluid viscosity and fluid density of the core sample; k 0 represents the absolute permeability of the core sample; |G| represents the effective gas pressure gradient.

2. The method for determining the relative permeability of multiphase reservoirs according to claim 1, characterized in that, The gas phase control parameters include the injected gas pressure at the top of the core sample and the gas back pressure at the bottom of the core sample in the gas-assisted gravity displacement system. The liquid phase control parameters include the fluid type and injection rate of the liquid fluid injected into the top of the core in the gas-assisted gravity displacement system.

3. The method for determining the relative permeability of multiphase reservoirs according to claim 2, characterized in that, Based on the gas-assisted gravity displacement system, an experiment was conducted using the preset experimental parameters, including: While applying the injection gas pressure to the top of the core sample, a fluid of the corresponding fluid type is injected into the core sample at the fluid injection rate; Maintain the bottom of the core sample under the gas back pressure, start the gas-assisted gravity displacement experiment, and continue until the change in fluid saturation in the core sample tends to stop, thus completing the gas-assisted gravity displacement experiment.

4. The method for determining the relative permeability of multiphase reservoirs according to claim 1, characterized in that, Acquiring the saturation distribution data collected by the gas-assisted gravity exhaust system includes: During the gas-assisted gravity displacement experiment, the CT scanner in the gas-assisted gravity displacement system is used to control the displacement platform of the gas-assisted gravity displacement system to move the core sample point by point at preset time intervals, and the CT data of the core sample at different times is recorded to complete the axial scanning of the core sample. Based on the CT data obtained from the scan and the CT reference values ​​corresponding to each phase fluid under the preset saturation state, the saturation distribution data is obtained.

5. The method for determining the relative permeability of multiphase reservoirs according to claim 1, characterized in that, The fluid flux of each phase is determined by the following formula: ； in, u i ( z K , t j+1 / 2 ) indicates at time step t j+1 / 2 Points z K First i Fluid flux of the phase fluid; u i,inj This indicates the injection rate of fluid at the top of the core sample; The porosity of the core sample is represented by K; K represents the number of points in a single CT scan during the gas-assisted gravity displacement experiment. S i ( z k , t j+1 )and S i ( z k , t j ) represent the points respectively z k At time step i, the fluid of phase i t j and time step t j+1 Saturation data; Δ z This indicates the spacing of the CT scan during the air-assisted gravity displacement experiment.

6. The method for determining the relative permeability of multiphase reservoirs according to claim 1, characterized in that, The effective gas pressure gradient is determined by the following formula: ； Where |G| represents the effective gas pressure gradient, Δ P total This represents the difference between the injected gas pressure at the top of the core sample and the gas back pressure at the bottom of the core sample. P c,entry To represent the inlet capillary pressure at the top of the core sample, L represents the length of the core sample, and α and β represent preset coefficients.

7. A device for determining the relative permeability of multiphase reservoirs, characterized in that, include: The first acquisition module is used to acquire the preset experimental parameters of the gas-assisted gravity displacement experiment of the target reservoir; The preset experimental parameters include at least gas phase control parameters for assisting gravity displacement and liquid phase control parameters for assisting gravity displacement. The experimental module is used to build a gas-assisted gravity displacement system based on core samples of the target reservoir, and to conduct gas-assisted gravity displacement experiments based on the gas-assisted gravity displacement system using the preset experimental parameters. The second acquisition module is used to acquire saturation distribution data collected by the air-assisted gravity exhaust system; The determination module is used to determine the relative permeability of the multiphase fluid in the core sample as the target relative permeability corresponding to the target reservoir based on the saturation distribution data and the preset experimental parameters. Based on the saturation distribution data and the preset experimental parameters, the relative permeability of the multiphase fluid in the core sample is determined, including: Based on the saturation distribution data and the preset experimental parameters, the fluid flux of each phase fluid in the target section of the core sample is determined. Based on the property parameters of the core sample and the preset experimental parameters, the effective gas pressure gradient of the target section is determined; The relative permeability of the multiphase fluids in the core sample is determined based on the fluid flux of each phase and the effective gas pressure gradient. The relative permeability of a multiphase fluid is determined by the following formula: ； in, k ri ( z K , t j+1 / 2 ) indicates at time step t j+1 / 2 Points z K First r Phase fluid and i The relative permeability of the phase fluid; u i ( z K , t j+1 / 2 ) indicates at time step t j+1 / 2 Points z K In the middle i Fluid flux of the phase fluid; μ i and ρ i Indicates the fluid viscosity and fluid density of the core sample; k 0 represents the absolute permeability of the core sample; |G| represents the effective gas pressure gradient.

8. An electronic device, characterized in that, include: A memory and a processor, the processor and the memory being communicatively connected to each other, the memory storing computer instructions, the processor executing the computer instructions to implement the steps of the method according to any one of claims 1 to 6.

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