Method for measuring gas-water-oil three-phase contact angle distribution and evolution characteristics in reservoir porous media

Abstract

The method for measuring the distribution and evolution characteristics of gas-water-oil three-phase contact angle in oil reservoir porous media belongs to the technical field of oil and gas exploitation and wettability measurement. The method is based on micro-nano CT imaging technology, through three-phase fluid seepage experiment, micro-nano CT scanning, CT image processing and analysis, and finally the statistical distribution characteristics of gas-water-oil three-phase contact angle in oil reservoir porous media under different flow states are obtained. By real-time acquisition of the interface state in the seepage process, in-situ, real and efficient measurement of three-phase contact angle is realized, which can reveal the seepage-induced wettability transition and local wettability reversal phenomenon. The fine division of water-wet, oil-wet and gas-wet pore space in oil reservoir porous media can be realized; the measurement results can provide reliable wettability data for pore-scale multiphase seepage simulation. Since the measurement results are the statistical characteristics of a large number of local contact angles, the authenticity and statistical accuracy of the contact angle measurement are significantly improved.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas extraction and wettability measurement technology. It is used to study the distribution and evolution of wettability at the pore scale among multiphase fluids in complex oil reservoir cores. It relates to a method for measuring the distribution and evolution characteristics of the contact angle at the pore scale of the gas-water-oil three-phase system in oil reservoir cores. Technical Background

[0002] The significance of studying the contact angle of the gas-water-oil three-phase system in porous media lies in its crucial role in predicting and optimizing multiphase flow behavior at the pore scale for engineering applications. The contact angle directly affects the fluid distribution in the pore space, interfacial tension balance, and capillary pressure, thus determining the dynamics of actual processes such as oil recovery and carbon dioxide sequestration efficiency. In a three-phase system, changes in the contact angle (such as from water-wet to oil-wet) alter the wetting sequence of the gas, causing water to become the unwetted phase and gas to become the intermediate wetted phase. This reversal of wettability affects the fluid configuration and multiphase flow stability within porous media. Accurate measurement of the contact angle provides reliable parameters for modeling multiphase flow at the pore scale, avoiding errors in traditional theoretical assumptions, thereby improving model prediction accuracy and guiding the optimized design for applications such as enhanced oil recovery.

[0003] Compared to measuring the contact angle of the gas-water two-phase phases in porous media, the main challenge in measuring the three-phase contact angle lies in the difficulty of identifying the multiphase interfaces involved, the numerous influencing factors, and the difficulty in completely controlling them. Currently, the mainstream methods for experimentally measuring the three-phase contact angle fall into two main categories: one is to measure the contact angle of the three-phase fluids on the rock surface using an industrial camera or in-situ scanning electron microscope, or to further measure the internal pores using a transparent porous medium; the other is to qualitatively determine the relative wettability of the three phases by utilizing capillary effects (such as the capillary rise method). However, the drawback of these methods is that they cannot accurately measure the detailed information of the contact angle distribution of the three-phase fluids in porous media in situ, and cannot characterize the spatial distribution characteristics of the contact angle of porous media in oil reservoirs under mixed wetting conditions. Summary of the Invention

[0004] To overcome the aforementioned measurement deficiencies, this invention proposes a method for measuring the distribution and evolution characteristics of the gas-water-oil three-phase contact angle within porous reservoir media based on micro-nano CT imaging technology. The aim is to accurately, conveniently, and realistically measure the spatial distribution characteristics of the gas-water-oil three-phase contact angle within porous reservoir media and reveal the local wetting reversal caused by fluid infiltration. The measurement method involves three-phase fluid seepage experiments, micro-nano CT scanning, and CT image processing and analysis. Finally, the statistical distribution characteristics of the gas-water-oil three-phase contact angle within porous reservoir media under different flow states are obtained.

[0005] The technical solution of this invention is: a method for measuring the contact angle distribution and evolution characteristics of the gas-water-oil three-phase system in a porous reservoir, mainly including the following steps:

[0006] (1) Sample preparation and percolation test

[0007] Core saturation: After evacuating the entire experimental pipeline of the seepage system to remove impurities and gases from the core, a 13% potassium iodide solution is prepared as brine. Then, a brine injection pump is used to inject brine at a constant rate to initially saturate the porous media (such as limestone and sandstone) of the reservoir with brine.

[0008] Oil phase injection: After the core is saturated, an oil phase injection pump is used to inject oil phase into the core, so that the continuous water phase is transformed into the residual water phase.

[0009] Gas-water co-injection: Gas-phase and water-phase injection pumps are used to inject fluids into the core at different ratios and flow rates, and pressure sensors are used to record the pressure difference data at both ends of the core.

[0010] (2) Micro-nano CT scanning imaging: Adjust the CT scanning parameters to enable the scanning resolution to clearly analyze the core pores. Scan the core after vacuuming to obtain a vacuum scanning image. Scan the core again after the pressure difference stabilizes during the gas-water co-injection process to obtain a steady-state seepage scanning image.

[0011] (3) Image processing and three-phase contact angle measurement

[0012] CT image binarization segmentation: Machine learning algorithms are used to perform binarization segmentation on CT images. Based on vacuum scan image segmentation, the distribution of core pores and skeleton (phase 0) is obtained. Based on steady-state seepage scan image segmentation, the distribution of gas phase (phase 1) and oil phase (phase 2) is obtained. By performing Boolean operations on the vacuum scan binarized image and the steady-state seepage scan image, the distribution of water phase (phase 3) in the pores is obtained. Finally, a multiphase binarized CT image for contact angle measurement is obtained.

[0013] Three-phase contact line identification: In order to measure the gas-water contact angle, the oil phase in the multiphase binarized CT image needs to be marked and assigned the value as invalid pixels. Then, the connected region edge detection method is used to obtain the three-phase contact line between gas, water and skeleton.

[0014] Gas-water contact angle measurement: For each node on the contact line, the normal plane of the contact line at the node location is obtained through image reconstruction. The two-dimensional contact angle is measured on the normal plane image, and this contact angle value is the local gas-water contact angle value at the node location. By measuring the local contact angle values ​​at different nodes, the statistical characteristics of the gas-water contact angle in the porous media of the reservoir can be obtained.

[0015] Gas-oil contact angle and oil-water contact angle measurement: Similarly, by marking the water phase and gas phase in the multiphase binarized CT image and assigning them as invalid pixels, the three-phase contact lines of gas-oil-skeleton and oil-water-skeleton can be obtained. By repeating the gas-water contact angle measurement steps, the distribution characteristics of gas-oil contact angle and oil-water contact angle in the porous media of the reservoir can be obtained.

[0016] Preferably, in order to accurately measure the local contact angle value, it is necessary to ensure that the number of pixels of the selected three-phase contact line is greater than the number of pixels of the equivalent diameter of the aperture.

[0017] Preferably, since the pore distribution space of gas-water-oil is closely related to the fluid composition and flow rate, in order to obtain the distribution characteristics of the three-phase contact angle in different pores, it is necessary to scan the steady-state seepage process under different gas-water composition and flow rate conditions to obtain steady-state seepage scanning images under different gas-water composition and flow rate conditions.

[0018] The beneficial effects of this invention are:

[0019] (1) Because the measurement results are statistical characteristics of a large number of local contact angles, the measurement results are more accurate than those of traditional methods;

[0020] (2) It can simulate the real three-phase flow process. Through one CT imaging, the three-phase contact angle distribution characteristics of multiple pore locations can be obtained, thereby reflecting the influence of pore structure, mineral composition, surface roughness and other factors on the three-phase wettability of porous media in oil reservoirs.

[0021] (3) It can achieve fine division of the water-wet, oil-wet and gas-wet pore space of porous media in oil reservoirs; the measurement results can provide reliable wettability data for pore-scale multiphase flow simulation;

[0022] (4) It can accurately describe the wetting characteristics of porous media in mixed-wetting reservoirs and can quantitatively characterize the wetting transformation law during the seepage process.

[0023] (5) Compared with static measurement of two-phase oil and water at selected locations without dynamic seepage processes, the real reservoir environment in this application involves the coexistence of three phases: oil, gas, and water. Its wettability characteristics are far more complex than those of a two-phase system. Since the three-phase contact line involves multiple factors such as interfacial tension, wettability competition, and local wetting reversal, traditional two-phase measurement methods are unable to capture these phenomena and cannot reveal the true configuration relationship of gas, water, and oil in porous media. This application achieves simultaneous identification of oil-water-gas three phases, accurate extraction of the three-phase contact line, and quantitative analysis of the contact angle. Attached Figure Description

[0024] Figure 1 This is a diagram of an experimental system for measuring the contact angle of the three phases (gas, water, and oil) in a porous reservoir.

[0025] Figure 2 This is a schematic diagram of the binarization process of CT images.

[0026] Figure 3 A diagram illustrating the process of determining the three-phase contact line and measuring the contact angle.

[0027] Figure 4 This is a statistical chart of the three-phase contact angle measurement results.

[0028] In the figure: 1. Core holder; 2. Vacuum pump; 3. Electric heater; 4. Thermocouple; 5. Circulating water bath; 6. Back pressure pump; 7. Brine injection pump; 8. Oil phase injection pump; 9. CO2 injection pump; 10. Aluminum plate; 11. Brine solution; 12. n-Decane solution; 13. CO2 gas; 14. Pressure sensor; 15. Data acquisition instrument; 16. Nano-CT. Detailed Implementation

[0029] The present invention will be specifically described below through embodiments. It should be noted that the following embodiments are only used to further illustrate the present invention, but are not limited thereto, unless otherwise stated.

[0030] The following describes the specific implementation of the present invention in detail, taking the measurement of the contact angle of the three phases CO2-water-n-decane in a porous medium of an oil reservoir as an example, in conjunction with experimental steps and accompanying drawings.

[0031] (1) After the sandstone core is encapsulated in the core holder 1, it is connected to the overall experimental system pipeline. The system is evacuated using the vacuum pump 2 to remove impurities and gases from the system.

[0032] (2) The core holder 1 was controlled by electric heater 3 and thermocouple 4. The back pressure pump 6, brine injection pump 7, oil phase injection pump 8 and CO2 injection pump 9 were controlled by four circulating water baths 5 respectively. The experimental system pipeline was controlled by circulating water bath 5 and aluminum plate 10. All temperatures were controlled at 50 ℃.

[0033] (3) Use back pressure pump 6 to control the system pressure, set the pressure value to 8 MPa, prepare 13% potassium iodide solution as saline solution 11, and use saline injection pump 7 to inject saline solution 11 at a constant capillary number. A total of 50 pore volumes of brine solution 11 were injected into the core holder 1 to fully saturate the core.

[0034] (4) After the core is saturated, oil phase injection pump 8 is used to inject into the core holder 1 to maintain a constant number of capillaries. A total of 50 pore volumes of n-decane solution 12 were injected into the core holder 1 to transform the continuous aqueous phase into a residual aqueous phase.

[0035] (5) Both the brine injection pump 7 and the CO2 injection pump 9 were used with the same number of capillaries. Simultaneously, brine solution 11 and CO2 gas 13 are injected into the core holder 1, and pressure sensor 14 and data acquisition instrument 15 are used to record the pressure difference data at both ends of the core.

[0036] (6) Adjust the scanning parameters of the nano-CT16 so that its resolution can clearly distinguish the core pores. After the system is evacuated, scan to obtain vacuum scanning CT images. After the pressure difference data of the gas-water co-injection process is stable, scan again to obtain steady-state seepage scanning CT images.

[0037] (7) Using the open-source image processing software Fiji, binarization segmentation of CT images at different stages was performed based on machine learning algorithms to obtain vacuum scan binarized images. Figure 2 (a) and steady-state seepage scan binarized images ( Figure 2 (b) Based on the vacuum scanning binarized image a, the distribution of core pores and skeleton (phase 0) is obtained; based on the steady-state seepage scanning binarized image b, the distribution of gas phase (phase 1) and oil phase (phase 2) is obtained; by performing Boolean operations on the vacuum scanning binarized image a and the steady-state seepage scanning binarized image b, the distribution of water phase (phase 3) within the pores is obtained; finally, a multiphase binarized CT image for contact angle measurement is obtained. Figure 2 (c)

[0038] (8) Mark the oil phase in the multiphase binarized CT image c and assign it as an invalid pixel. Use the connected region edge detection method to obtain the three-phase contact line between gas, water and skeleton. Figure 3 (Middle left image)

[0039] (9) For each node on the three-phase contact line, obtain the contact line normal plane at the node location through image reconstruction. Figure 3 (See the right image in the middle). A two-dimensional contact angle measurement is performed on the normal plane image; this contact angle value is the local gas-water contact angle value at the node location. By measuring the local contact angle values ​​at different nodes, a statistical map of the gas-water contact angle distribution within the sandstone core can be obtained.

[0040] (10) Similarly, by marking the water phase and gas phase in the multiphase binarized CT image and assigning them as invalid pixels, the gas-oil-skeleton and oil-water-skeleton three-phase contact lines can be obtained. By repeating the gas-water contact angle measurement steps, the gas-oil contact angle distribution statistics and oil-water contact angle distribution statistics in the porous medium of the reservoir can be obtained.

[0041] Preferably, in order to accurately measure the local contact angle value, it is necessary to ensure that the number of pixels of the selected three-phase contact line is greater than the number of pixels of the equivalent diameter of the aperture.

[0042] Preferably, since the pore distribution space of gas-water-oil is closely related to the fluid composition and flow rate, in order to obtain the distribution characteristics of the three-phase contact angle in different pores, it is necessary to scan the steady-state seepage process under different gas-water composition and flow rate conditions to obtain steady-state seepage scanning images under different gas-water composition and flow rate conditions.

[0043] The above embodiments are only used to illustrate the present invention. Any equivalent transformations and improvements made on the basis of the technical solutions of the present invention should not be excluded from the protection scope of the present invention.

Claims

1. A method for measuring the distribution and evolution characteristics of the gas-water-oil three-phase contact angle in porous media of an oil reservoir, characterized in that, Includes the following steps: (1) After sealing the sandstone core into the core holder, connect it to the overall experimental system pipeline and use a vacuum pump to evacuate the system; (2) Use an electric heater and thermocouple to control the temperature of the core holder, use a circulating water bath to control the temperature of the back pressure pump, brine injection pump, oil phase injection pump and CO2 injection pump respectively, and use a circulating water bath and aluminum plate to control the temperature of the experimental system pipeline. (3) Use a back pressure pump to control the system pressure, and use a brine injection pump to inject brine solution into the core holder at a constant number of capillaries to fully saturate the core. (4) After the core is saturated, an oil phase injection pump is used to inject n-decane solution into the core holder with a constant number of capillaries, so that the continuous aqueous phase becomes the residual aqueous phase; the number of capillaries injected into the core holder and the total pore volume injected with n-decane are the same as those injected with brine solution. (5) Use a brine injection pump and a CO2 injection pump to inject brine solution and CO2 gas into the core holder simultaneously with the same number of capillaries, and use a pressure sensor and a data acquisition instrument to record the pressure difference data at both ends of the core. (6) Adjust the nano-CT scanning parameters, perform scanning after the system is evacuated to obtain vacuum scanning CT images; perform scanning again after the pressure difference data of the gas-water co-injection process is stable to obtain steady-state seepage scanning CT images; (7) Using the open-source image processing software Fiji, the CT images at different stages were binarized and segmented based on the machine learning algorithm to obtain the vacuum scan binarized image and the steady-state seepage scan binarized image respectively. The core pore and skeleton distribution were obtained based on the vacuum scan binarized image, and the gas phase and oil phase distribution were obtained based on the steady-state seepage scan binarized image. The water phase distribution in the pores was obtained by performing Boolean operation on the vacuum scan binarized image and the steady-state seepage scan binarized image. Finally, a multiphase binarized CT image for contact angle measurement was obtained. (8) Mark one of the water phase, oil phase and gas phase in the multiphase binarized CT image and assign it as an invalid pixel. Use the connected region edge detection method to obtain the three-phase contact line between the remaining two phases and the skeleton. (9) For each node on the three-phase contact line, the normal plane of the contact line at the node location is obtained by image reconstruction. The two-dimensional contact angle is measured on the normal plane image. This contact angle value is the local contact angle value of the remaining two phases at the node location. By measuring the local contact angle values ​​at different nodes, the contact angle distribution statistics of the remaining two phases in the sandstone core can be obtained. Repeat steps (8) and (9) above to obtain a statistical diagram of the contact angle distribution of any two phases in the water, oil and gas phases in the sandstone core.

2. The method according to claim 1, characterized in that: In step (2), the temperature is controlled at 50 ℃.

3. The method according to claim 1, characterized in that: In step (3), the pressure value is set to 8 MPa, and a 13% potassium iodide solution is prepared as a saline solution. Injection conditions for saline solution: Use a saline injection pump to deliver the saline solution at a constant capillary rate. A total of 50 pore volumes of brine solution were injected into the core holder.

4. The method according to claim 1, characterized in that: In step (5), both the brine injection pump and the CO2 injection pump operate with the same number of capillary tubes. Simultaneously, brine solution and CO2 gas are injected into the core holder 1.

5. The method according to claim 1, characterized in that: The specific process for obtaining the contact angle distribution statistics of any two phases among the water, oil, and gas phases in a sandstone core is as follows: In multiphase binarized CT images, the oil phase is marked and assigned as invalid pixels. The three-phase contact line between gas, water, and skeleton is obtained using the connected region edge detection method. For each node on the three-phase contact line, the normal plane of the contact line at the node location is obtained through image reconstruction. The two-dimensional contact angle is measured on the normal plane image. This contact angle value is the local gas-water contact angle value at the node location. By measuring the local contact angle values ​​at different nodes, a statistical map of the gas-water contact angle distribution in the sandstone core can be obtained. Similarly, by marking the water phase and gas phase in the multiphase binarized CT image and assigning them as invalid pixels, the contact lines of the gas-oil-skeleton and oil-water-skeleton three phases can be obtained. By repeating the gas-water contact angle measurement steps, the statistical distribution maps of the gas-oil contact angle and oil-water contact angle in the porous media of the reservoir can be obtained.

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