Reservoir rock residual water film in-situ measurement device under CO2 capture condition and characterization method

Abstract

A reservoir rock residual water film in-situ measurement device under a CO2 capture condition is characterized in that a rock core clamping module comprises a temperature-pressure-resistant sleeve, porous plugs at two ends of the temperature-pressure-resistant sleeve and an internal CO2 corrosion-resistant pipe, and an upstream porous cushion block, an upstream fluid disperser, an upstream electrode film, a rock core, a downstream electrode film, a downstream fluid disperser and a downstream porous cushion block are arranged in the CO2 corrosion-resistant pipe; the upstream / downstream electrode films are connected with the corresponding internal electrodes and are connected to the corresponding voltmeters; the upstream porous plug is connected with the fluid injection module through an injection pipeline, and an upstream external potential test module is arranged on the injection pipeline; the downstream porous plug is connected with the extraction metering module through an outflow pipeline, and a downstream external potential testing module is arranged on the outflow pipeline. According to the device, in-situ accurate measurement of the interface potential is realized, and key experimental parameters are provided for a residual water film thickness prediction model; a mineral surface water molecule mechanical model is further established, and the thickness of the residual water film on the mineral surface can be accurately solved.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development and carbon sequestration technology, and in particular to an in-situ measurement device and quantitative characterization method for residual water film in reservoir rocks under CO2 capture conditions in geological sequestration. Background Technology

[0002] In CO2 geological storage (CGS) and CO2-enhanced oil recovery (CO2-EOR) projects, the aqueous phase within the reservoir pores is displaced by the non-wetting phase (CO2 / oil), forming immobile residual water. Its spatial distribution and film thickness are key parameters affecting CO2 injection, transport characteristics, storage efficiency, and long-term stability. From a transport mechanism perspective, the water film significantly influences the CO2 seepage path and capillary capture efficiency by altering pore surface wettability and local capillary pressure. At the chemical level, the water film acts as a medium for the reaction between CO2 and minerals, and its thickness directly affects the mineral dissolution-precipitation reaction rate. This dual regulation mechanism of physical CO2 capture and chemical reaction makes residual water a pivotal element in the dynamics and geochemical processes of CO2 transport. Therefore, achieving precise characterization and intelligent control of the distribution and film thickness of residual water in reservoir rocks is a crucial technological foundation for improving the storage efficiency and operational stability of CGS systems.

[0003] Existing research has successfully achieved direct measurement of water film thickness on the surfaces of single-crystal minerals such as quartz, calcite, mica, and montmorillonite using tracer labeling combined with X-ray fluorescence spectroscopy (XRF). However, when the research focuses on porous media, technical bottlenecks such as uneven tracer distribution due to the three-dimensional heterogeneous pore network and enhanced X-ray scattering effects make it difficult for existing XRF techniques to accurately measure the water film distribution within the pores of real core samples, especially under high-temperature and high-pressure reservoir conditions. Nuclear magnetic resonance (NMR) T2 signal inversion is one of the commonly used methods for quantitatively characterizing water film thickness in core samples. During CO2 injection, the changes in the relaxation signal of the water phase within the core are measured in real time, and the changes in water film thickness are inferred by inverting the relaxation time distribution. However, this method has the following technical limitations in practical applications: ① The minimum detectable water film thickness is limited by the instrument's signal-to-noise ratio (typically around 5nm for commercial equipment), resulting in significant measurement errors for ultrathin water films (<10nm); ② It requires preset relaxation surface rate parameters, and the same T2 distribution may correspond to different pore structure combinations, leading to multiple solutions in the inversion process. Unlike NMR signal inversion methods, microfluidic methods utilize optical images to quantitatively analyze the water phase distribution and water film thickness characteristics. Patent CN115824744A discloses a visualized core model with fixed water film thickness for CO2 flooding experiments and its fabrication method, applying microfluidic technology to the core pores for precise control of water film thickness and observing the CO2-oil-water three-phase occurrence state under different water film thicknesses. However, this technology is still limited to ambient temperature and pressure conditions and cannot meet the requirements for in-situ reservoir measurements.

[0004] To address the technical bottleneck of existing experimental techniques (such as X-ray fluorescence spectroscopy, nuclear magnetic resonance, and microfluidics) in accurately characterizing the distribution of residual water under in-situ temperature and pressure conditions in reservoirs under CO2 capture, this study considers that residual water adheres to the pore walls of reservoir rocks through interfacial adsorption. A mechanical model of water molecules on the mineral surface is established through theoretical derivation, and combined with experimental testing of key parameters (including Hamaker's constant, Zeta potential, surface tension, and wettability), the interfacial forces such as van der Waals forces and double-layer electrostatic forces, as well as capillary pressure, are quantified. This provides a reliable means for the quantitative characterization of residual water under CO2 capture conditions. However, the methods for measuring the Zeta potential of reservoir rocks under CO2 capture conditions are still imperfect, especially the measurement techniques under in-situ high-temperature and high-pressure environments, which still present significant challenges. Therefore, it is urgent to develop new testing methods and devices to accurately characterize the distribution and film thickness of residual water in reservoir rocks under CO2 capture conditions. Summary of the Invention

[0005] The main objective of this invention is to provide an in-situ measurement device and characterization method for residual water film in reservoir rocks under CO2 capture conditions. This measurement device innovatively realizes the in-situ accurate measurement of interfacial potential under reservoir conditions, providing key experimental parameters for the residual water film thickness prediction model. In terms of characterization method, this invention proposes a characterization method for residual water in reservoir rocks under CO2 capture conditions and establishes a mechanical model of water molecules on the mineral surface, which can realize the accurate solution of the residual water film thickness on the mineral surface.

[0006] The technical solution adopted in this invention is: An in-situ measurement device for residual water film in reservoir rocks under CO2 capture conditions includes a core clamping module, a fluid injection module, and a production metering module. The core clamping module includes a temperature- and pressure-resistant sleeve, an upstream porous plug and a downstream porous plug installed at both ends of the temperature- and pressure-resistant sleeve, and a CO2-resistant tube installed inside the temperature- and pressure-resistant sleeve. The CO2-resistant tube sequentially encloses an upstream porous pad, an upstream fluid disperser, an upstream electrode membrane, a core, a downstream electrode membrane, a downstream fluid disperser, and a downstream porous pad. The upstream electrode membrane is connected to an upstream internal electrode and to an upstream first voltmeter. The downstream electrode membrane is connected to a downstream internal electrode and to a downstream first voltmeter. The upstream porous plug is connected to the fluid injection module via an injection pipeline, on which an upstream external potential testing module is installed. The downstream porous plug is connected to the production metering module via an outflow pipeline, on which a downstream external potential testing module is installed. The upstream and downstream external potential testing modules are used to avoid the polarization effect of the internal electrodes.

[0007] In the above scheme, the upstream external potential testing module includes an upstream storage tank, an upstream external electrode, an upstream second voltmeter, and an upstream hypotonic porous baffle. The upstream storage tank contains water and is connected to the injection pipeline through the upstream hypotonic porous baffle. The upstream external electrode is connected to the upstream storage tank and then to the upstream second voltmeter. The downstream external potential testing module includes a downstream storage tank, a downstream external electrode, a downstream second voltmeter, and a downstream hypotonic porous baffle. The downstream storage tank contains water and is connected to the outflow pipeline through the downstream hypotonic porous baffle. The downstream external electrode is connected to the downstream storage tank and then to the downstream second voltmeter.

[0008] In the above scheme, the upstream porous pad and the downstream porous pad are provided with a cavity structure inside, and the middle is a solid structure. The solid structure has a through hole for fluid flow in the middle. Several fluid microchannels connecting the cavity structure are evenly opened at both ends of the porous pad. The cavity structure is used to hold water. The water vapor formed by water evaporation enters the area around the core through the fluid microchannels to provide a humidity environment.

[0009] In the above scheme, the injection pipeline is also equipped with an upstream pressure sensor and an upstream humidity sensor; the outflow pipeline is also equipped with an outlet pressure sensor and a downstream humidity sensor.

[0010] The above scheme also includes a stress loading module for simulating the in-situ formation stress environment of the core. It includes a hand-cranked injection pump and annular pressure gauge. The hand-cranked injection pump is connected to the gap between the temperature- and pressure-resistant sleeve and the CO2 corrosion-resistant pipe through the annular pressure pipeline. Water is injected into the gap through the hand-cranked injection pump to provide annular pressure. The annular pressure gauge is installed on the annular pressure pipeline for monitoring the annular pressure.

[0011] The above scheme also includes a backpressure control module, which is used to apply backpressure at the core outlet end to simulate the in-situ formation pore water pressure where the core is located. It includes a second high-pressure injection pump, a second piston container, and a backpressure valve. The backpressure valve is set on the outflow pipeline and located upstream of the production metering module. The backpressure valve is connected to the second piston container through the backpressure pipeline. The second piston container is connected to the second high-pressure injection pump through the pipeline. The second high-pressure injection pump injects water into the backpressure valve through the piston container to provide backpressure.

[0012] In the above scheme, a branch line is also provided on the outflow pipeline and connected to the third piston container. The third piston container is connected to the second high-pressure injection pump. This branch line is used to inject fluid from the outlet end of the core clamping module into the core.

[0013] In the above scheme, the fluid injection module includes a CO2 cylinder, a first high-pressure injection pump, a first piston container, and a water-CO2 mixing reactor. The outlet of the CO2 cylinder is connected to the injection pipeline and the first piston container through a three-way valve (F1). The first high-pressure injection pump is connected to the first piston container and the water-CO2 mixing reactor through a three-way valve (F2). The water-CO2 mixing reactor is connected to the injection pipeline through a three-way valve (F3). CO2 or saline water containing dissolved CO2 is injected into the core clamping module through the fluid injection module.

[0014] Accordingly, this invention also proposes an in-situ characterization method for residual water film in reservoir rocks under CO2 capture conditions, comprising the following steps: S1. Core preparation: Cores obtained from well drilling are processed to the design specifications of the core clamping module; S2. Core saturation treatment: Based on the groundwater salinity information of the stratum where the core is located, a single salt solution is used to prepare formation saline water. A water-CO2 mixing reactor is used to fully dissolve CO2 into the saline water. Then, the core is saturated with the saline water containing dissolved CO2. S3. In-situ formation environment simulation: Install the measuring device according to any one of claims 1-8, apply ring pressure around the core, and apply a certain back pressure at the outlet end of the core clamping module. The back pressure value is set according to the pore water pressure of the formation where the core is located, and the temperature of the constant temperature chamber is set according to the formation depth to simulate the in-situ formation stress and temperature conditions. S4. Rock-Water Interface Flow Potential Test: The flow potential is tested using a paired stabilization method. Dissolved CO2-containing saline water is injected into the core clamping module at a constant rate. The displaced water is collected at the outlet. The relative humidity around the core is monitored by a humidity sensor, and the external potential change is monitored by an upstream external potential module until the humidity at both ends stabilizes and becomes equal. The rock-water interface flow potential is then tested using an internal potential testing module, and the pressure at both ends of the core is monitored until both stabilize, at which point injection stops. Then, the outlet and inlet ends of the core clamping module are swapped, and the displaced water is injected in the reverse direction at the same rate. The external potential change is monitored by a downstream external potential module, and the rock-water interface flow potential is tested using an internal potential testing module until the flow potential at both ends of the core stabilizes and is consistent with the forward potential value, and the forward and reverse pressure difference is consistent, at which point injection stops. The inlet pressure is recorded during the forward / reverse displacement process. and export pressure and upstream potential value and downstream potential value Subsequently, the core clamping module was disconnected, and the high-precision LCR meter was connected to the internal electrodes to measure the electrical conductivity of the core under water-saturated conditions. ; S5. CO2-Water Interface Flow Potential Test in Rock: The paired stabilization method was also used to test the flow potential. CO2 was injected into the core clamping module at a constant rate to displace the water in the core. The volume of water displaced was measured downstream until the water volume no longer changed, indicating residual saturation of the core. The volume of water displaced was recorded. The relative humidity around the core was monitored during the displacement process, and the external potential change was monitored using an upstream external potential module until the humidity at both ends stabilized and equalized. The flow potential of the CO2-water interface in the rock was tested using an internal potential testing module during the displacement process, and the pressure at both ends of the core was monitored until both stabilized, at which point injection was stopped. Then, the outlet and inlet ends of the core clamping module were swapped, and the displaced water was injected in the reverse direction at the same rate. The external potential change was monitored using a downstream external potential module, and the flow potential of the CO2-water interface was tested using an internal potential testing module until the flow potential at both ends of the core stabilized and remained consistent with the forward potential value, and the forward and reverse pressure differences remained consistent, at which point injection was stopped. The relative humidity around the core during the forward / reverse displacement process was recorded. Inlet pressure and export pressure and upstream potential value and downstream potential value Subsequently, the core clamping module was disconnected, and the high-precision LCR meter was connected to the internal electrodes to measure the conductivity of the core under residual water conditions. ; S6. Use a high-temperature, high-pressure interfacial tension / contact angle measuring instrument to measure the water-CO2 interfacial tension in the rock under the experimentally set CO2 pressure and temperature. and contact angle ; S7. Establish a mechanical model of water molecules on the mineral surface to analyze the distribution characteristics and film thickness of residual water in reservoir rocks under CO2 capture conditions.

[0015] In the above method, the mechanical model of water molecules on the mineral surface is: +

[0016] In the formula, It is the Hamek constant, which represents the interaction between solid particles, the gas phase, and the water film. It refers to the thickness of the water film; It refers to the concentration of ions in the water; It is the Boltzmann constant; It is Kelvin temperature; It is the electrostatic potential at the mineral / water interface. It is the electrostatic potential at the gas / water interface; It is the reciprocal of the Debye length. , It is the vacuum permittivity. It is the dielectric constant of water. It is electron charge. It is an ionic valence state; It is the surface tension at the CO2-water interface. It is the contact angle at the CO2-water interface; It is the pore radius; It is the ideal gas constant; It is the relative molecular volume of water; It refers to the relative humidity in the rock-CO2-water system under residual water conditions; in, , , and These are the Zeta potentials at the mineral / water interface and the gas / water interface, respectively. Based on the monitoring data of pressure and electric potential during the experiment, and Calculated using the Helmholtz-Smoluchowski equation:

[0017]

[0018] In the formula, It is the potential difference between the two ends of the core under water-saturated conditions. ; It is the pressure difference between the two ends of the core under water-saturated conditions. ; It is the potential difference between the two ends of the core under residual water conditions. ; It is the pressure difference between the two ends of the core under residual water conditions. ; It is the electrical conductivity of the core under water-saturated conditions; It is the electrical conductivity of the core under residual water conditions; It is the dynamic viscosity of water.

[0019] The beneficial effects of this invention are: 1. Addressing the technical bottleneck of existing experimental techniques (X-ray fluorescence spectroscopy, nuclear magnetic resonance, microfluidics, etc.) in accurately characterizing residual water in CO2-water-rock three-phase systems, this invention proposes a device for in-situ testing of reservoir rock interface potential. This device enables precise in-situ measurement of interface potential under CO2 capture conditions, providing key input parameters for residual water film thickness prediction models. The measurement accuracy is improved compared to traditional methods, overcoming the technical limitations of existing experimental techniques.

[0020] 2. This invention provides a method for characterizing the thickness of residual water film in reservoir rocks under CO2 capture conditions. By deriving a mechanical model of water molecules on the mineral surface, the interfacial forces such as van der Waals forces and double-layer electrostatic forces (within the range of 0.3–10 nm) are quantified, which can achieve an accurate solution for the thickness of water film on the mineral surface and provide key input parameters for CO2 geological sequestration efficiency assessment. Attached Figure Description

[0021] To more clearly illustrate the technical solutions in the embodiments of the present invention 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 some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0022] Figure 1 This is a schematic diagram of the overall structure of the in-situ measurement device for residual water film in reservoir rocks under CO2 capture conditions according to the present invention; Figure 2 yes Figure 1 A schematic diagram of the core clamping module of the measuring device shown; Figure 3 yes Figure 1 A schematic diagram of the porous plug of the measuring device shown.

[0023] In the diagram: 1. CO2 cylinder; 2. First high-pressure injection pump; 3. First piston container; F1~F3. Three-way valves; 5. Water-CO2 mixing reactor; 5-1. Piston container; 5-2. Stirring rotor; 5-3. Heating blanket; 6. Upstream second voltmeter; 7. Upstream pressure sensor; 8. Upstream external electrode; 9. Upstream storage tank; 10. Upstream low-permeability porous baffle; 11. Upstream humidity sensor; 12. Upstream first voltmeter; 13. Upstream porous plug; 14. Upstream porous pad; 14-1. Cavity structure; 14-2. Through hole; 14-3. Fluid microchannel; 15. Upstream fluid disperser; 16. Upstream internal electrode; 17. Upstream electrode membrane; 18. Core; 19. CO2 corrosion resistant tube; 20. Temperature and pressure resistant sleeve; 21. Downstream electrode membrane; 22. Downstream fluid disperser; 23. Downstream porous pad; 24. Downstream porous plug; 25. Downstream internal electrode; 26. Downstream first voltmeter; 27. Downstream humidity sensor; 28. Downstream low-permeability porous baffle; 29. ​​Downstream storage tank; 30. Downstream external electrode; 31. Outlet pressure sensor; 32. Downstream second voltmeter; 33. Back pressure valve; 34. Gas-liquid separator; 35. Gas flow meter; 36. Liquid collector; 37. Second piston container; 38. Third piston container; 39. Second high-pressure injection pump; 40. Ring pressure gauge; 41. Hand-cranked injection pump. Detailed Implementation

[0024] To make the objectives, technical solutions, and advantages of this invention clearer, the invention will be further described in detail below with reference to the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are merely illustrative and not intended to limit the invention.

[0025] It should be noted that the illustrations provided in the embodiments of the present invention are only schematic representations of the basic concept of the present invention. Therefore, the drawings only show the components related to the present invention and are not drawn according to the number, shape and size of the components in actual implementation. In actual implementation, the form, quantity and proportion of each component can be arbitrarily changed, and the layout of the components may also be more complex.

[0026] In this invention, it should also be noted that the terms "center," "upper," "lower," "left," "right," "vertical," "horizontal," "inner," and "outer," etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings. They are used only for the convenience of describing this application and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on this application. Furthermore, the terms "first" and "second" are used only for descriptive and distinguishing purposes and should not be construed as indicating or implying relative importance.

[0027] like Figure 1 As shown, an in-situ measurement device for residual water film in reservoir rocks under CO2 capture conditions includes a core clamping module, a fluid injection module, a production metering module, an electrical potential testing module, a stress loading module, a back pressure control module, and a temperature control module.

[0028] The core clamping module is the main site for simulating gas transport within the core. It includes a temperature- and pressure-resistant sleeve 20, upstream porous plugs 13 and downstream porous plugs 24 installed at both ends of the temperature- and pressure-resistant sleeve 20, and a CO2-resistant tube 19 installed inside the temperature- and pressure-resistant sleeve 20. The CO2-resistant tube 19 contains, in sequence, a tightly fitted upstream porous pad 14, an upstream fluid disperser 15, an upstream electrode film 17, a core 18, a downstream electrode film 21, a downstream fluid disperser 22, and a downstream porous pad 23. The upstream porous pad 14 is tightly fitted to the upstream porous plug 13, and the downstream porous pad 23 is tightly fitted to the downstream porous plug 24. The upstream porous plug 13 is connected to the fluid injection module via an injection pipeline. Fluid enters the core through the through-holes in the upstream porous plug. An upstream pressure sensor 7 and an upstream humidity sensor 11 are installed on the injection pipeline. The downstream porous plug 24 is connected to the production metering module via an outflow pipeline. An outlet pressure sensor 31 and a downstream humidity sensor 27 are installed on the outflow pipeline. The upstream porous pad 14 and the downstream porous pad 23 have a cavity structure 14-1 inside, with a solid structure in the middle. A through-hole 14-2 for fluid flow is opened in the middle of the solid structure. Several fluid microchannels 14-3 are evenly opened on both sides of the pad to connect the cavity structure. The cavity structure 14-1 is used to hold water. The water vapor formed by water evaporation enters the area around the core through the fluid microchannels 14-3 to provide a humidity environment. The injected fluid enters the core 18 through the upstream fluid disperser 15. The fluid disperser is used to ensure that the injected fluid can contact the core evenly.

[0029] The potential testing module is used to measure the flow potential in CO2-water saturated cores and includes an internal potential testing module and an external potential testing module. The internal potential testing module includes an upstream electrode membrane 17, an upstream internal electrode 16, an upstream first voltmeter 12, a downstream electrode membrane 21, a downstream internal electrode 25, and a downstream first voltmeter 26. The upstream porous plug 13, the upstream porous pad 14, and the upstream fluid disperser 15 are each provided with through holes for the upstream internal electrode 16 to pass through. The upstream electrode membrane 17 is connected to the upstream internal electrode 16 and is connected to the upstream first voltmeter 12 outside the core clamping module via a copper coaxial cable. The downstream porous plug 24, the downstream porous pad 23, and the downstream fluid disperser 22 are each provided with through holes for the downstream internal electrode 25 to pass through. The downstream electrode membrane 21 is connected to the downstream internal electrode 25 and is connected to the downstream first voltmeter 26 outside the core clamping module via a copper coaxial cable. The external potential testing modules are primarily designed to avoid the polarization effect of the internal electrodes. These include an upstream external potential testing module located on the injection pipeline and a downstream external potential testing module located on the outflow pipeline. The upstream external potential testing module comprises an upstream storage tank 9, an upstream external electrode 8, an upstream second voltmeter 6, and an upstream low-permeability porous baffle 10. The upstream storage tank 9 contains saline water identical to that used in the saturated core sample and is connected to the injection pipeline via the upstream low-permeability porous baffle 10. The upstream low-permeability porous baffle 10 prevents saline water from directly flowing into the injection pipeline. The upstream external electrode 8 is connected to the upstream storage tank 9 and then to the upstream second voltmeter 6. The downstream external potential testing module includes a downstream storage tank 29, a downstream external electrode 30, a downstream second voltmeter 32, and a downstream low-permeability porous baffle 28. The downstream storage tank 29 contains saline water identical to that in the saturated core and is connected to the outflow pipeline via the downstream low-permeability porous baffle 28. The downstream external electrode 30 is connected to the downstream storage tank 29 and then to the downstream second voltmeter 32. A low-permeability porous baffle is located at the bottom of the storage tank. This design has a dual function: it prevents saline water from directly flowing into the injection pipeline and allows CO2 to diffuse through the baffle into the saline water. This structural design ensures that the external and internal electrodes are always under the same CO2 / saline water environment conditions during the displacement experiment. If the measurement reading of the external electrode remains stable during the experiment, it indicates that no polarization effect occurs between the external and internal electrodes under the CO2 / saline water environment. Changes in the internal electrode reading can be attributed to changes in electrical properties caused by variations in CO2 / saline water saturation within the core.

[0030] The fluid injection module includes a CO2 cylinder 1, a first high-pressure injection pump 2, a first piston container 3, a water-CO2 mixing reactor 5, three-way valves F1, F2, and F3. The outlet of the CO2 cylinder 1 is connected to the injection pipeline and the first piston container 3 via the three-way valve F1. The first high-pressure injection pump 2 is connected to the first piston container 3 and the water-CO2 mixing reactor 5 via the three-way valve F2. The water-CO2 mixing reactor 5 is connected to the injection pipeline via the three-way valve F3. CO2 can be directly injected into the core clamping module through the injection pipeline, or it can be injected into the first piston container 3 first and then injected into the water-CO2 mixing reactor 5 to mix with saline water. The water-CO2 mixing reactor includes a piston container 5-1, a stirring rotor 5-2, and a heating blanket 5-3. The piston container 5-1 is used to hold brine. CO2 is injected into the piston container 5-1 by a first high-pressure injection pump 2. The stirring rotor 5-2 makes the CO2 fully dissolve into the brine. The heating blanket 5-3 is placed outside the piston container 5-1 to ensure that the brine containing dissolved CO2 maintains the same temperature as the core.

[0031] The metering module is used to collect the gas-liquid flux at the outlet end. It includes a gas-liquid separator 34, a gas flow meter 35, and a liquid collector 36. The gas-liquid separator 34 is installed on the outflow pipeline and is connected to the gas flow meter 35 and the liquid collector 36, respectively.

[0032] The stress loading module is used to simulate the in-situ formation stress conditions of the core. It includes a hand-cranked injection pump 41 and annular pressure gauge 40. The hand-cranked injection pump 41 is connected to the gap between the temperature-resistant and pressure-resistant sleeve 20 and the CO2 corrosion-resistant pipe 19 through the annular pressure pipeline. Water is injected into the gap through the hand-cranked injection pump 41 to provide annular pressure. The annular pressure gauge 40 is installed on the annular pressure pipeline to monitor the annular pressure.

[0033] The back pressure control module is used to apply back pressure at the core outlet end to simulate the in-situ formation pore water pressure where the core is located. It includes a second high-pressure injection pump 39, a second piston container 37, and a back pressure valve 33. The back pressure valve 33 is set on the outflow pipeline and located upstream of the production metering module. The back pressure valve 33 is connected to the second piston container 37 through the back pressure pipeline. The second piston container 37 is connected to the second high-pressure injection pump 39 through a pipeline. The second high-pressure injection pump 39 injects water into the back pressure valve 33 through the piston container to provide back pressure.

[0034] A branch line is also provided on the outflow pipeline, which is connected to the third piston container 38, and the third piston container 38 is connected to the second high-pressure injection pump 39. This branch line is used to inject fluid from the outlet end of the core clamping module into the core.

[0035] The temperature control module is used to simulate the temperature environment of the core sample. The temperature control module adopts an electrically controlled constant temperature chamber.

[0036] In one embodiment of the present invention, the CO2 corrosion resistant pipe 19 is a CO2 corrosion resistant rubber pipe.

[0037] In one embodiment of the present invention, the upstream electrode film 17 and the downstream electrode film 21 are AgCl electrode films, the electrodes are AgCl electrodes, and the voltmeter is an HP3490A voltmeter (internal impedance 10 GΩ, accuracy 0.15%, resolution 10 nV).

[0038] Accordingly, this invention also proposes an in-situ characterization method for residual water film in reservoir rocks under CO2 capture conditions, comprising the following steps: S1. Core Preparation: Cores obtained from well drilling are processed to the specifications of the core clamping module. In this embodiment, the rock sample is processed into a cylindrical core with a diameter of 2.5 cm and a length of 5 cm.

[0039] S2. Core Saturation Treatment: Based on the groundwater salinity information of the stratum where the core is located, a single salt solution is used to prepare formation saline water. A water-CO2 mixing reactor is used to fully dissolve CO2 into the saline water, and then the core is saturated with the CO2-infused saline water. In this embodiment, a single salt, NaCl, is used to prepare the saline water. Then, CO2 is injected into the water-CO2 mixing reactor at a certain pressure to fully dissolve the CO2 into the saline water and reach dissolution equilibrium.

[0040] S3. In-situ formation environment simulation: Connect the above testing device as shown in the figure; apply ring pressure around the core; apply a certain back pressure at the outlet end of the core clamping module, the back pressure value is set according to the pore water pressure of the formation; set the temperature of the constant temperature chamber according to the formation depth, and heat the core clamping module to simulate the in-situ formation stress and temperature conditions.

[0041] S4. Rock-Water Interface Flow Potential Test: To maintain the stability of the flow potential test, a paired stabilization method is used. First, the forward displacement stage: saline water containing dissolved CO2 is injected at a constant rate into the inlet of the core clamping module. The displaced water is collected at the outlet. The relative humidity around the core is monitored by upstream and downstream humidity sensors, and the external potential is monitored by an upstream external potential module. If the external potential does not change (potential fluctuation ≤ ±10 nV), it indicates that no polarization effect has occurred between the internal and external electrodes. This continues until the humidity reaches a stable and equal level. The rock-water interface flow potential is then tested using an internal potential testing module, and the pressure at both ends of the core is monitored by upstream and downstream pressure sensors until both reach a stable level, at which point injection stops. The following is the reverse displacement verification: the outlet and inlet ends of the core clamping module are swapped, and the displaced water is injected in the reverse direction at the same rate through the third piston container 38 and the second high-pressure injection pump 39. The change in external potential is monitored by the downstream external potential module. If the external potential does not change (potential fluctuation ≤ ±10 nV), it indicates that no polarization effect has occurred between the internal and external electrodes. Then, the flow potential at the rock-water interface is tested using the internal potential testing module until the flow potential at both ends of the core is stable and consistent with the forward potential value (the difference between the forward and reverse potentials|). Δ V 正 - Δ V 反 |<5%), and the positive and negative pressure differences remain consistent ( ΔP 正 / ΔP 反 ≈1), stop injection and record the inlet pressure during forward / reverse displacement. and export pressure and upstream potential value and downstream potential value Finally, conductivity testing was performed: the core clamping module was disconnected, and the high-precision LCR meter was connected to the internal electrodes to test the conductivity of the core under saturated water conditions. .

[0042] S5. Flow Potential Test of CO2-Water Interface in Rock: The flow potential is tested using a paired stabilization method, similar to S4, including a forward displacement stage and a reverse displacement verification. In the forward displacement stage, CO2 is injected into the core clamping module at a constant rate to displace the water in the core. The volume of water displaced is measured downstream until the water volume no longer changes, indicating residual saturation of the core. The volume of water displaced is recorded. The relative humidity around the core is monitored during displacement, and the external potential is monitored using an upstream external potential module. If the external potential does not change (potential fluctuation ≤ ±10 nV), it indicates that no polarization effect occurs between the internal and external electrodes. The process continues until the humidity stabilizes and becomes equal. The flow potential of the CO2-water interface in the rock is tested using an internal potential testing module during displacement, and the pressure at both ends of the core is monitored until both stabilize, at which point injection is stopped. The subsequent verification involved reverse displacement. The outlet and inlet ends of the core clamping module were swapped, and the displaced water was injected in reverse at the same rate through the third piston container 38 and the second high-pressure injection pump 39. The downstream external potential module monitored changes in the external potential. If the external potential remained unchanged (potential fluctuation ≤ ±10 nV), it indicated that no polarization effect occurred between the internal and external electrodes. Then, the internal potential testing module was used to test the flow potential at the CO2-water interface until the flow potential at both ends of the core stabilized and remained consistent with the forward potential value (forward-reverse potential difference | Δ V 正 - Δ V 反 |<5%), and the positive and negative pressure differences remain consistent ( ΔP 正 / ΔP 反 ≈1), stop injection and record the relative humidity around the core during forward / reverse displacement. Inlet pressure and export pressure and upstream potential value and downstream potential value Then, the core clamping module was disconnected, and the high-precision LCR meter was connected to the internal electrodes to measure the conductivity of the core under residual water conditions. ; S6. Use a high-temperature, high-pressure interfacial tension / contact angle measuring instrument to measure the water-CO2 interfacial tension in the rock under the experimentally set CO2 pressure and temperature. and contact angle ; S7. Establish a mechanical model of water molecules on the mineral surface to analyze the distribution characteristics and film thickness of residual water in reservoir rocks under CO2 capture conditions.

[0043] The mechanical model of water molecules on the mineral surface is derived as follows: Under residual water conditions, the water in the core reaches stability under the action of separation pressure and capillary force, and is in mechanical equilibrium with the relative vapor pressure in the rock-CO2-water system.

[0044] According to the Derjaguin–Landau–Verwey–Overbeek (DLVO) theory, the separation pressure ( ) is mainly composed of van der Waals forces ( ) and electrostatic force ( )constitute: (1) van der Waals ( ) is the intermolecular force generated between solid particles, the aqueous phase, and the gas phase, which is related to the thickness of the water film ( h The reciprocal of the cube is directly proportional, that is: (2) (3) In the formula: It is the Hamek constant, which represents the interaction between mineral particles, the gas phase, and the water film. , , These represent the Hamek constants for minerals, gaseous phases, and aqueous phases in vacuum, respectively. In one embodiment, The mineral composition of the core was obtained through a weighted average.

[0045] electrostatic force ( The electrostatic attraction generated by the approaching electric double layer (EDL) at the mineral / water interface and the EDL at the gas / water interface can be obtained by solving the Poisson-Boltzmann equation. Considering that the electric potential fields at the mineral / water interface and the gas / water interface are generally low to moderate in intensity in formation water environments, the double-layer compression approximation method can be used to solve the Poisson-Boltzmann equation. It can be represented as follows: (4) , (5) (6) In the formula, It refers to the concentration of ions in the water; It is the Boltzmann constant; It is Kelvin temperature; and These are the electrostatic potentials at the mineral / water interface and the gas / water interface, respectively. and These are the Zeta potentials at the mineral / water interface and the gas / water interface, respectively. It is the reciprocal of the length of the Debye; It is electron charge. It is an ionic valence state; It is the vacuum permittivity. It is the dielectric constant of water.

[0046] Based on the monitoring data of pressure and electric potential during the experiment, and It can be calculated using the Helmholtz-Smoluchowski equation: (7.1) (7.2) In the formula: It is the potential difference between the two ends of the core under water-saturated conditions. ; It is the pressure difference between the two ends of the core under water-saturated conditions. ; The potential difference between the two ends of the core under residual water conditions. ; It is the pressure difference between the two ends of the core under residual water conditions. ; μ It is the dynamic viscosity of water; It is the electrical conductivity of the core under water-saturated conditions; It is the electrical conductivity of the core under residual water conditions.

[0047] Meanwhile, capillary forces exist at the water / CO2 interface to maintain the stability of the water film thickness at the pore walls, which can be described by the Laplace equation. Assuming the pores are cylindrical and the water film is uniformly distributed inside, the force maintaining the water film equilibrium is in mechanical equilibrium with the relative vapor pressure in the rock-CO2-water system, and can be expressed as follows: (8) In the formula: It is the pore radius; It is the ideal gas constant; It is the relative molecular volume of water; It refers to the relative humidity in the rock-CO2-water system under residual water conditions; It is the surface tension at the CO2-water interface. It is the contact angle of the CO2-water interface.

[0048] By combining equations (2) to (8), the mechanical model of water molecules on the mineral surface can be obtained: + (9) Using the proposed water molecule mechanics model for mineral surfaces, the thickness of the water film on the mineral surface can be accurately calculated. hThis study analyzes the distribution characteristics of residual water films in different pores of reservoir rocks under CO2 capture conditions. It also analyzes the changes in residual water films under the influence of different environmental factors. The environmental variables that can be studied include: ion type and ion concentration, pH value, rock wettability, mineral composition, temperature, etc., thereby revealing the influence mechanism of different environmental factors on the distribution characteristics of residual water films.

[0049] It should be noted that, depending on the implementation needs, the various steps / components described in this application can be broken down into more steps / components, or two or more steps / components or parts of the operation of steps / components can be combined into new steps / components to achieve the purpose of this invention.

[0050] The order of the steps in the above embodiments does not imply the order of execution. The execution order of each process should be determined by its function and internal logic, and should not constitute any limitation on the implementation process of the embodiments of this application.

[0051] It should be understood that those skilled in the art can make improvements or modifications based on the above description, and all such improvements and modifications should fall within the protection scope of the appended claims.

Claims

1. An in-situ measurement device for residual water film in reservoir rocks under CO2 capture conditions, comprising a core clamping module, a fluid injection module, and a produced metering module, characterized in that, The core clamping module includes a temperature-resistant and pressure-resistant sleeve, an upstream porous plug and a downstream porous plug installed at both ends of the temperature-resistant and pressure-resistant sleeve, and a CO2-resistant tube installed inside the temperature-resistant and pressure-resistant sleeve. The CO2-resistant tube sequentially encloses an upstream porous pad, an upstream fluid disperser, an upstream electrode membrane, a core, a downstream electrode membrane, a downstream fluid disperser, and a downstream porous pad. The upstream electrode membrane is connected to the upstream internal electrode and is connected to the upstream first voltmeter. The downstream electrode membrane is connected to the downstream internal electrode and is connected to the downstream first voltmeter. The upstream porous plug is connected to the fluid injection module via an injection pipeline, and an upstream external potential testing module is provided on the injection pipeline. The downstream porous plug is connected to the extraction metering module through an outflow pipeline, and a downstream external potential testing module is provided on the outflow pipeline; the upstream external potential testing module and the downstream external potential testing module are used to avoid the polarization effect of the internal electrodes.

2. The in-situ measurement device for residual water film in reservoir rocks under CO2 capture conditions according to claim 1, characterized in that, The upstream external potential testing module includes an upstream storage tank, an upstream external electrode, an upstream second voltmeter, and an upstream hypotonic porous baffle. The upstream storage tank contains water and is connected to the injection pipeline through the upstream hypotonic porous baffle. The upstream external electrode is connected to the upstream storage tank and then to the upstream second voltmeter. The downstream external potential testing module includes a downstream storage tank, a downstream external electrode, a downstream second voltmeter, and a downstream hypotonic porous baffle. The downstream storage tank contains water and is connected to the outflow pipeline through the downstream hypotonic porous baffle. The downstream external electrode is connected to the downstream storage tank and then to the downstream second voltmeter.

3. The in-situ measurement device for residual water film in reservoir rocks under CO2 capture conditions according to claim 1, characterized in that, The upstream and downstream porous pads have internal cavity structures with a solid middle structure. The solid structure has through holes for fluid flow. Several fluid microchannels connecting the cavity structures are evenly distributed at both ends of the porous pads. The cavity structures are used to hold water. Water vapor formed by water evaporation enters the area around the core through the fluid microchannels to provide a humidity environment.

4. The in-situ measurement device for residual water film in reservoir rocks under CO2 capture conditions according to claim 1, characterized in that, The injection line is also equipped with an upstream pressure sensor and an upstream humidity sensor; the outflow line is also equipped with an outlet pressure sensor and a downstream humidity sensor.

5. The in-situ measurement device for residual water film in reservoir rocks under CO2 capture conditions according to claim 1, characterized in that, It also includes a stress loading module for simulating the in-situ formation stress environment of the core, including a hand-cranked injection pump and annular pressure gauge. The hand-cranked injection pump is connected to the gap between the temperature- and pressure-resistant sleeve and the CO2 corrosion-resistant pipe through the annular pressure pipeline. Water is injected into the gap by the hand-cranked injection pump to provide annular pressure. The annular pressure gauge is installed on the annular pressure pipeline for monitoring the annular pressure.

6. The in-situ measurement device for residual water film in reservoir rocks under CO2 capture conditions according to claim 1, characterized in that, It also includes a backpressure control module, which is used to apply backpressure at the core outlet end to simulate the in-situ formation pore water pressure where the core is located. The module includes a second high-pressure injection pump, a second piston container, and a backpressure valve. The backpressure valve is located on the outflow pipeline and upstream of the production metering module. The backpressure valve is connected to the second piston container through the backpressure pipeline. The second piston container is connected to the second high-pressure injection pump through the pipeline. The second high-pressure injection pump injects water into the backpressure valve through the piston container to provide backpressure.

7. The in-situ measurement device for residual water film in reservoir rocks under CO2 capture conditions according to claim 6, characterized in that, A branch line is also provided on the outflow pipeline, which is connected to the third piston container. The third piston container is connected to the second high-pressure injection pump. This branch line is used to inject fluid from the outlet end of the core clamping module into the core.

8. The in-situ measurement device for residual water film in reservoir rocks under CO2 capture conditions according to claim 1, characterized in that, The fluid injection module includes a CO2 cylinder, a first high-pressure injection pump, a first piston container, and a water-CO2 mixing reactor. The outlet of the CO2 cylinder is connected to the injection pipeline and the first piston container via a three-way valve (F1). The first high-pressure injection pump is connected to the first piston container and the water-CO2 mixing reactor via a three-way valve (F2). The water-CO2 mixing reactor is connected to the injection pipeline via a three-way valve (F3). CO2 or saline water containing dissolved CO2 is injected into the core clamping module through the fluid injection module.

9. A method for in-situ characterization of residual water film in reservoir rocks under CO2 capture conditions, characterized in that, Includes the following steps: S1. Core preparation: Cores obtained from well drilling are processed to the design specifications of the core clamping module; S2. Core saturation treatment: Based on the groundwater salinity information of the stratum where the core is located, a single salt solution is used to prepare formation saline water. A water-CO2 mixing reactor is used to fully dissolve CO2 into the saline water. Then, the core is saturated with the saline water containing dissolved CO2. S3. In-situ formation environment simulation: Install the measuring device according to any one of claims 1-8, apply ring pressure around the core, and apply a certain back pressure at the outlet end of the core clamping module. The back pressure value is set according to the pore water pressure of the formation where the core is located, and the temperature of the constant temperature chamber is set according to the formation depth to simulate the in-situ formation stress and temperature conditions. S4. Rock-Water Interface Flow Potential Test: The flow potential is tested using a paired stabilization method. Dissolved CO2-containing saline water is injected into the core clamping module at a constant rate. The displaced water is collected at the outlet. The relative humidity around the core is monitored by a humidity sensor, and the external potential change is monitored by an upstream external potential module until the humidity at both ends stabilizes and becomes equal. The rock-water interface flow potential is then tested using an internal potential testing module, and the pressure at both ends of the core is monitored until both stabilize, at which point injection stops. Then, the outlet and inlet ends of the core clamping module are swapped, and the displaced water is injected in the reverse direction at the same rate. The external potential change is monitored by a downstream external potential module, and the rock-water interface flow potential is tested using an internal potential testing module until the flow potential at both ends of the core stabilizes and is consistent with the forward potential value, and the forward and reverse pressure difference is consistent, at which point injection stops. The inlet pressure is recorded during the forward / reverse displacement process. and export pressure and upstream potential value and downstream potential value ; The core clamping module was then disconnected, and the high-precision LCR meter was connected to the internal electrodes to measure the conductivity of the core under saturated water conditions. ; S5. CO2-Water Interface Flow Potential Test in Rock: The paired stabilization method was also used to test the flow potential. CO2 was injected into the core clamping module at a constant rate to displace the water in the core. The volume of water displaced was measured downstream until the water volume no longer changed, indicating residual saturation of the core. The volume of water displaced was recorded. The relative humidity around the core was monitored during the displacement process, and the external potential change was monitored using an upstream external potential module until the humidity at both ends stabilized and equalized. The flow potential of the CO2-water interface in the rock was tested using an internal potential testing module during the displacement process, and the pressure at both ends of the core was monitored until both stabilized, at which point injection was stopped. Then, the outlet and inlet ends of the core clamping module were swapped, and the displaced water was injected in the reverse direction at the same rate. The external potential change was monitored using a downstream external potential module, and the flow potential of the CO2-water interface was tested using an internal potential testing module until the flow potential at both ends of the core stabilized and remained consistent with the forward potential value, and the forward and reverse pressure differences remained consistent, at which point injection was stopped. The relative humidity around the core during the forward / reverse displacement process was recorded. Inlet pressure and export pressure and upstream potential value and downstream potential value ; The core clamping module was then disconnected, and the high-precision LCR meter was connected to the internal electrodes to measure the conductivity of the core under residual water conditions. ; S6. Use a high-temperature, high-pressure interfacial tension / contact angle measuring instrument to measure the water-CO2 interfacial tension in the rock under the experimentally set CO2 pressure and temperature. and contact angle ; S7. Establish a mechanical model of water molecules on the mineral surface to analyze the distribution characteristics and film thickness of residual water in reservoir rocks under CO2 capture conditions.

10. The method for in-situ characterization of residual water film in reservoir rocks under CO2 capture conditions according to claim 9, characterized in that, The mechanical model of water molecules on the mineral surface is as follows: + In the formula, It is the Hamek constant, which represents the interaction between solid particles, the gas phase, and the water film. It refers to the thickness of the water film; It refers to the concentration of ions in the water; It is the Boltzmann constant; It is Kelvin temperature; It is the electrostatic potential at the mineral / water interface. It is the electrostatic potential at the gas / water interface; It is the reciprocal of the length of Debye. , It is the vacuum permittivity. It is the dielectric constant of water. It is electron charge. It is an ionic valence state; It is the surface tension at the CO2-water interface. It is the contact angle at the CO2-water interface; It is the pore radius; It is the ideal gas constant; It is the relative molecular volume of water; It refers to the relative humidity in the rock-CO2-water system under residual water conditions; in, , , and These are the Zeta potentials at the mineral / water interface and the gas / water interface, respectively. Based on the monitoring data of pressure and electric potential during the experiment, and Calculated using the Helmholtz-Smoluchowski equation: In the formula, It is the potential difference between the two ends of the core under water-saturated conditions. ; It is the pressure difference between the two ends of the core under water-saturated conditions. ; It is the potential difference between the two ends of the core under residual water conditions. ; It is the pressure difference between the two ends of the core under residual water conditions. ; It is the electrical conductivity of the core under water-saturated conditions; It is the electrical conductivity of the core under residual water conditions; It is the dynamic viscosity of water.

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