High-temperature and high-pressure fully automatic co 2 flooding and sequestration integrated experimental device and method

Abstract

A high-temperature and high-pressure fully automatic CO2 flooding and sequestration integrated experimental device and method. The device comprises a core holding system (2) for holding a core sample (1), wherein a pressure measurement system (3) and a confining pressure system (4) are in communication with the core holding system (2); a fluid injection system is in communication with the core holding system (2); a fluid property measurement system (6) for measuring fluid properties is provided on the fluid injection system; an effluent separation system (7) is in communication with an outlet of the core holding system (2) by means of a back pressure regulation system (14); the effluent separation system (7) is in communication with a fluid recovery system (8), a fluid analysis system (9) and a fluid circulation system (10); and an effluent measurement system (11) is in communication with the core holding system (2). The high-temperature and high-pressure fully automatic CO2 flooding and sequestration integrated experimental device is not only suitable for evaluating CO2 enhanced oil recovery (EOR) and CO2 geological sequestration efficiency, but can also be used for research on related problems such as natural energy depletion development, secondary oil recovery and tertiary oil recovery.

Description

A high-temperature, high-pressure fully automated integrated experimental device and method for CO2 flooding and burial Technical Field

[0001] This invention relates to the field of petroleum extraction technology, and in particular to a high-temperature, high-pressure fully automated CO2 flooding and burial integrated experimental device and method. Background Technology

[0002] In laboratory and reservoir-scale studies of various technologies for enhancing oil recovery, CO2 is widely used as a displacement agent for secondary and tertiary oil recovery. Enhanced oil recovery (EOR) technology has received widespread attention due to its dual benefits of increasing oil and gas production and achieving in-situ CO2 geological sequestration.

[0003] Chinese patent CN202411140513.2 discloses an integrated experimental device and method for supercritical CO2 fracturing, displacement, and storage, belonging to the field of natural gas development technology. It primarily utilizes supercritical CO2 as the fracturing fluid to assess rock fracturing pressure under triaxial formation stress and to monitor and quantitatively characterize various fracturing-related parameters in real time. The experimental device is suitable for conducting basic experiments on supercritical CO2 displacement of methane in cubic cores, as well as determining rock permeability before and after fracturing. Due to the special properties of rock fracturing experiments, the device has a short operating cycle and cannot be used to complete core displacement experiments such as water flooding, chemical flooding, and CO2 flooding and storage. Therefore, it cannot quantitatively characterize the CO2 injection capacity and its oil displacement and storage efficiency. Currently, this invention patent is applicable to core displacement experiments with various displacing agents under high temperature and high pressure conditions, including chemical solution displacement experiments and water flooding experiments. It is particularly suitable for CO2 cyclic injection experiments, such as continuous vertical and horizontal CO2 injection, gas (CO2)-water alternating injection, and huff-and-puff injection experiments. However, due to the excellent resistance of the core components of this patent to CO2 and various acid corrosions, the device can operate stably for a long period of time to meet the needs of integrated water flooding and CO2 displacement / storage experiments. In the aforementioned experiments, this patent can accurately measure various dynamic parameters, including oil, gas, and water production, cumulative injected / produced CO2, inlet and outlet pressures, and pressure difference across the test sample. Simultaneously, it can quantitatively characterize key feature parameters, such as the effective permeability of the rock (oil / water / gas), the oil displacement efficiency of different displacing agents, and the CO2 displacement and storage efficiency. Furthermore, this device is suitable for the quantitative evaluation of the injection capacity of different displacing agents, and is particularly suitable for CO2 circulating injection experiments.

[0004] Therefore, this application discloses a high-temperature, high-pressure fully automated CO2 flooding integrated experimental device and method to solve the above-mentioned technical problems. Summary of the Invention

[0005] The purpose of this invention is to provide a high-temperature and high-pressure fully automated CO2 flooding and burial integrated experimental device and method, which is mainly used to study the CO2 flooding and burial efficiency and influencing factors of conventional and unconventional oil and gas reservoirs, shale oil and gas reservoirs and coal seams under high temperature and high pressure conditions. It is not only applicable to the evaluation of CO2 enhanced recovery rate (EOR) and geological sequestration, but can also be used to study related issues such as natural energy depletion development, secondary and tertiary oil recovery.

[0006] To achieve the above objectives, the present invention provides the following solution: The present invention provides a high-temperature and high-pressure fully automatic integrated CO2 flooding experimental device, comprising:

[0007] A core clamping system, wherein the core clamping system is used to clamp a core sample, and the core clamping system is connected to a pressure measuring system and a confining pressure system for adjusting the confining pressure;

[0008] A fluid injection system is connected to the inlet of the core clamping system and is used to inject fluid into the core clamping system; the fluid injection system is equipped with a fluid characteristic measurement system for measuring fluid characteristics;

[0009] The product separation system is connected to the outlet of the core clamping system via a back pressure regulating system, and is also connected to a fluid recovery system, a fluid analysis system, and a fluid circulation system.

[0010] The product measurement system is connected to the outlet of the core clamping system and is used to measure the product of the core sample within the core clamping system.

[0011] Preferably, the core clamping system includes a clamping body that is connected to the confining pressure system. The clamping body has end plugs with fluid diversion at both ends. The core sample is fixed inside the clamping body after being wrapped by a sleeve with pressure measuring points.

[0012] Preferably, the confining pressure system includes a confining pressure fluid storage tank, which is connected to the main body of the clamp via a confining pressure pump; the confining pressure pump is connected to a back pressure regulating system.

[0013] Preferably, the fluid injection system includes a first injection pump and a second injection pump that are independently configured. The first injection pump and the second injection pump are respectively connected to a first fluid tank, a second fluid tank and a third fluid tank. The first fluid tank, the second fluid tank and the third fluid tank are respectively connected to the clamp body and the fluid characteristic measurement system. The first fluid tank and the second fluid tank are respectively connected to a pressurization system.

[0014] Preferably, the fluid characteristic measurement system includes a viscometer and a densitometer connected in parallel. The fluids flowing out of the first fluid tank, the second fluid tank, and the third fluid tank are mixed and then enter the viscometer and the densitometer respectively to measure the characteristics of the mixed fluid.

[0015] Preferably, the booster system includes a first air source tank and a second air source tank that are independently configured. The first air source tank and the second air source tank are respectively connected to the inlet of the booster pump, and the outlet of the booster pump is respectively connected to the first fluid tank and the second fluid tank.

[0016] Preferably, the product separation system includes a product separator connected to the outlet of the gripper body for separating the fluid and liquid of the reaction products, and the outlet of the product separator is connected to the fluid recovery system, the fluid analysis system and the fluid circulation system respectively.

[0017] Preferably, the output measurement system includes an output collector and a gas volume recorder connected to the outlet of the gripper body, and the output collector and the gas volume recorder are respectively connected to the fluid circulation system.

[0018] Preferably, the fluid circulation system includes a first circulation tank, a second circulation tank, and a third circulation tank arranged in parallel. The first circulation tank and the second circulation tank are respectively connected to the first injection pump, and the third circulation tank is connected to the second injection pump.

[0019] This application also discloses an experimental method based on a high-temperature and high-pressure fully automated CO2 flooding integrated experimental device, including the following steps:

[0020] Prepare core samples according to experimental requirements, then load the core samples into the core clamping system, and connect the confining pressure system and pressure measurement system to the core clamping system;

[0021] The set surrounding rock pressure is applied to the core sample through the confining pressure system, and the pore pressure of the core sample is established through the back pressure adjustment system.

[0022] Salt water was introduced into the core clamping system through a fluid injection system, and the salt water permeability of the core sample was measured in an indoor environment.

[0023] The initial water saturation and original oil content of the core were established by degassing oil flooding.

[0024] To restore the wettability of the core sample;

[0025] Conduct waterflooding oil recovery rate experiments;

[0026] Experiments were conducted on CO2 miscible flooding for oil recovery and storage.

[0027] The collected data is processed.

[0028] Compared with existing technologies, this invention has the following advantages and technical effects: This invention discloses a high-temperature and high-pressure fully automated CO2 flooding and burial integrated experimental device and method. It studies CO2 enhanced oil recovery and storage through various injection methods, including continuous CO2 injection, water-gas alternating injection, CO2 huff and puff, chemically assisted CO2 flooding, and gas-liquid or liquid-liquid two-phase flow. It can measure and analyze the composition of oil and gas in real time, assess the minimum miscibility pressure between crude oil and carbon dioxide, foam phase changes, and test the density and viscosity of the fluid. It is suitable for experimental devices and methods for CO2 flooding to enhance crude oil recovery and reservoir research under high-temperature and high-pressure conditions. It is applicable to research fields such as gas flooding, chemical flooding, and water flooding experiments. It can also be used to evaluate novel displacement agents for oil production, consistency control, and fracturing fluids. The entire set of equipment achieves multi-purpose functionality and can provide valuable information that existing equipment cannot obtain.

[0029] This invention achieves automated control of the entire equipment, and is suitable for evaluating enhanced oil recovery and in-situ storage of carbon dioxide. It can also be used for experimental research on issues related to natural energy depletion development, secondary and tertiary oil recovery, thus expanding the research field and broadening the application scope. Attached Figure Description

[0030] The accompanying drawings, which form part of this application, are used to provide a further understanding of this application. The illustrative embodiments and descriptions of this application are used to explain this application and do not constitute an undue limitation of this application. In the drawings:

[0031] Figure 1 is a schematic diagram of the high-temperature and high-pressure fully automatic CO2 flooding and burial integrated experimental device of the present invention;

[0032] Figure 2 is a schematic diagram of the high-temperature and high-pressure fully automatic CO2 flooding and burial integrated experimental device of the present invention;

[0033] Figure 3 is a schematic diagram of the core clamping system of the present invention;

[0034] In the diagram: 1. Core sample; 2. Core clamping system; 3. Pressure measurement system; 4. Confining pressure system; 5. Fluid delivery system; 6. Fluid characteristic measurement system; 7. Product separation system; 8. Fluid recovery system; 9. Fluid analysis system; 10. Fluid circulation system; 11. Product measurement system; 12. Pressurization system; 13. Imaging capture system; 14. Back pressure regulation system; 15. Data acquisition and control system; 201. Clamping device body; 202. End plug; 203. Pressure measuring point; 204. Sleeve; 301. Sensor; 401. Confining pressure liquid storage tank; 402, confining pressure pump; 501, first injection pump; 502, second injection pump; 503, first fluid tank; 504, second fluid tank; 505, third fluid tank; 601, viscometer; 602, densitometer; 701, product separator; 1001, first circulation tank; 1002, second circulation tank; 1003, third circulation tank; 1101, product collector; 1102, gas volume recorder; 1201, first gas source tank; 1202, second gas source tank; 1203, booster pump; 1301, camera. Detailed Implementation

[0035] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0036] To make the above-mentioned objects, features and advantages of the present invention more apparent and understandable, the present invention will be further described in detail below with reference to the accompanying drawings and specific embodiments.

[0037] Referring to Figures 1-3, this embodiment provides a high-temperature, high-pressure fully automated CO2 flooding integrated experimental device, comprising:

[0038] Core clamping system 2 is used to clamp core sample 1. Core clamping system 2 is connected to pressure measuring system 3 and confining pressure system 4 for adjusting confining pressure.

[0039] A fluid injection system is connected to the inlet of the core clamping system 2 and is used to inject fluid into the core clamping system 2; a fluid characteristic measurement system 6 is installed on the fluid injection system for measuring fluid characteristics;

[0040] Product separation system 7 is connected to the outlet of core clamping system 2 through back pressure regulation system 14. Product separation system 7 is also connected to fluid recovery system 8, fluid analysis system 9 and fluid circulation system 10.

[0041] The product measurement system 11 is connected to the outlet of the core clamping system 2 and is used to measure the product of the core sample 1 in the core clamping system 2.

[0042] This invention discloses a fully automated high-temperature, high-pressure CO2 flooding and in-situ storage experimental device and method. This device and method utilizes various injection methods to study CO2 enhanced oil recovery and storage, including continuous CO2 injection, alternating water-gas injection, CO2 huff and puff, chemically assisted CO2 flooding, and gas-liquid or liquid-liquid two-phase flow. It can measure and analyze the composition of oil and gas in real time, assess the minimum miscibility pressure between crude oil and CO2, foam phase changes, and test the density and viscosity of the fluid. This device and method are applicable to CO2 flooding for enhanced oil recovery and reservoir research under high-temperature, high-pressure conditions. It is suitable for research fields such as gas flooding, chemical flooding, and water flooding, and can also be used to evaluate novel displacement agents for oil recovery, consistency control, and fracturing fluids. The device achieves multi-purpose functionality and can provide valuable information that existing equipment cannot obtain. This invention achieves automated control of the entire device, is suitable for evaluating CO2 enhanced oil recovery and in-situ storage, and can also be used for experimental research on natural energy depletion development, secondary and tertiary oil recovery, and other related issues, expanding the research field and broadening the application scope.

[0043] Further optimizing the design, the core clamping system 2 includes a clamping body 201 connected to the confining pressure system 4. The clamping body 201 has end plugs 202 with fluid diversion lines at both ends. The core sample 1 is fixed inside the clamping body 201 after being wrapped by a sleeve 204 with pressure measuring points 203. The core clamping system 2 consists of the clamping body 201, the sleeve 204 with pressure measuring points 203, and the end plugs 202 with fluid diversion lines. The end plugs 202 have diversion lines and three inlets, allowing fluid to be evenly injected into the core. The sleeve 204 with pressure measuring points 203 is fitted over the core sample 1 to prevent fluid leakage into the core sample 1. After the core sample 1 is installed in place, the two end plugs 202 abut against the ends of the core sample 1 to fix it in place and allow fluid to flow into the core sample 1.

[0044] In one embodiment of this application, the clamp body 201 is made of a corrosion-resistant, high-temperature-resistant, and high-pressure-resistant material to ensure durability under extreme conditions.

[0045] In one embodiment of this application, the sleeve 204 is designed to withstand etching solutions, surfactants, polymer solutions, and acidic gases; pressure measurement points 203 are distributed on both sides of the central axis of the sleeve 204 and connected to end plugs 202 at both ends via 1 / 16 molybdenum-chromium alloy tubing. Furthermore, the tubing from the pressure measurement points 203 on the sleeve 204 is connected to the pressure measurement system 3 via the end plugs 202.

[0046] In one embodiment of this application, the clamp body 201 and the end plug 202 are preferably made of Hastelloy C276 nickel-molybdenum-chromium alloy, which is widely recognized for its excellent corrosion resistance, mechanical strength, and durability under high temperature and high pressure conditions. It is resistant to chemical attack from supercritical CO2 and strong acids.

[0047] In one embodiment of this application, sleeve 204 and other sealing components are preferably made of perfluoroelastomer (FFKM), a highly specialized elastomer made entirely of fluorinated monomers that combines the chemical resistance of polytetrafluoroethylene (PTFE, commonly known as Teflon) with the elastic properties of rubber, making it ideal for operation under extreme chemical and thermal conditions.

[0048] In one embodiment of this application, the application limit of the combination of the clamp body 201, the FFKM sleeve 204 and the sealing assembly will be determined by the performance of the two materials, Hastelloy C276 and FFKM; based on the characteristics of Hastelloy C276 and FFKM, the operating temperature and pressure of the core clamping system 2 are 300°C and 15000 psi (103 MPa), respectively.

[0049] In one embodiment of this application, the clamp body 201 is suitable for two sizes of core samples 1, with core diameters of 2.5 cm and 3.8 cm; the core length for a diameter of 2.5 cm ranges from 2.5 cm to 80 cm, and the core length for a diameter of 3.8 cm ranges from 3.8 cm to 80 cm. The length of the core sample 1 is adjustable. To accommodate the core diameter, two types of end plugs 202 for fluid distribution are used in the clamp body 201, with diameters of 2.5 cm and 3.8 cm, respectively.

[0050] In one embodiment of this application, the pressure measurement system 3 includes a plurality of sensors 301 connected to the gripper body 201 to record pressure data and history related to the use of the device. Its measurement functions include:

[0051] 1) Inlet and outlet pressure of core sample 1 (upstream and downstream pressure of core sample 1): In the displacement experiment of core sample 1, a pressure sensor of 0-70MPa is used to monitor the inlet and outlet pressure on both sides of core sample 1. The sensor is installed at the inlet and outlet ends of core sample 1. In the experiment, the outlet pressure should be equal to the pore pressure. This pressure is set by a pressure regulator.

[0052] 2) Pressure difference across core sample 1: The pressure difference across core sample 1 is measured using a three-stage sensor, ranging from 0 to 0.07 MPa, 0.07 to 0.7 MPa, and 0.7 to 3.45 MPa. These ranges are selected based on the permeability of the rock. When the pressure difference approaches the maximum set measurement value, the system automatically jumps to the next stage. When the pressure difference approaches the system's maximum set measurement value, the pressure difference measurement automatically stops. In this case, the pressure difference across core sample 1 can be measured using upstream and downstream pressure sensors. Each stage of the pressure testing unit has a bypass valve to protect the pressure sensor. The valve automatically opens when the pressure approaches the preset pressure.

[0053] 3) Pressure measurement at pressure measuring point 203 on sleeve 204: Multiple pressure measuring points 203 are set on sleeve 204 and connected to pressure sensors. The number of pressure measuring points 203 depends on the design of the scheme. During the test, the sensors are used to measure the pressure at different locations inside the core sample 1.

[0054] 4) Pressure measurement of other pressure components: The pressure of these pressure components includes: confining pressure, pore pressure and back pressure of core sample 1.

[0055] Further optimizing the scheme, the confining pressure system 4 includes a confining pressure fluid storage tank 401, which is connected to the clamp body 201 via a confining pressure pump 402; the confining pressure pump 402 is connected to a back pressure regulating system 14. The confining pressure system 4, composed of the confining pressure pump 402 and the confining pressure fluid storage tank 401, achieves confining pressure by applying pressure to the sleeve 204 through the confining pressure fluid during the displacement experiment of the core sample 1, ensuring that the core sample 1 is firmly fixed in the sleeve 204 to simulate the overburden pressure of the reservoir. Furthermore, the confining pressure pump 402 is connected to a back pressure regulator and can serve as the pressure source for the back pressure regulator.

[0056] Further optimization of the scheme: The fluid injection system includes independently configured first injection pump 501 and second injection pump 502. The first injection pump 501 and second injection pump 502 are respectively connected to a first fluid tank 503, a second fluid tank 504, and a third fluid tank 505. The first fluid tank 503, the second fluid tank 504, and the third fluid tank 505 are respectively connected to the clamp body 201 and the fluid characteristic measurement system 6. The first fluid tank 503 and the second fluid tank 504 are respectively connected to a pressurization system 12. The fluid injection system comprises the first injection pump 501, the second injection pump 502, and several high-pressure, high-temperature, corrosion-resistant intermediate containers. The first injection pump 501 and the second injection pump 502 inject fluid into the core sample 1 within the clamp body 201 through the intermediate containers, connectors, and valves. This system can inject one or more fluids into the core sample 1 at a constant flow rate from 0.0001 cc / min to 15 cc / min, with a working pressure up to 70 MPa.

[0057] In one embodiment of this application, the intermediate container is designed to withstand working pressures up to 140 MPa.

[0058] In one embodiment of this application, the number of intermediate containers is no less than three, which respectively contain CO2, N2 / saltwater and crude oil.

[0059] In one embodiment of this application, the intermediate container is preferably made of nickel-molybdenum-chromium alloy (Hastelloy C276) material for loading CO2 and nitrogen, and is resistant to chemical degradation by supercritical CO2 and strong acids; the sealing piston of the intermediate container is a metal piston made of Hastelloy C276 material and inlaid with FFKMO-type sealing rings. The working limits of the intermediate container, including the metal piston and sealing components, are determined by the lower performance thresholds of Hastelloy C276 and FFKM.

[0060] Further optimizing the design, the fluid characteristic measurement system 6 includes a viscometer 601 and a densitometer 602 connected in parallel. Fluids flowing from the first fluid tank 503, the second fluid tank 504, and the third fluid tank 505 are mixed and then enter the viscometer 601 and the densitometer 602 respectively to measure the characteristics of the mixed fluid. The fluid characteristic measurement system 6, composed of a high-temperature, high-pressure viscometer 601 and a densitometer 602, measures the online viscosity and density of the fluid injected during the oil displacement process of the core sample 1 under specific reservoir conditions. It is also connected to the fluid delivery system 5 and the effluent measurement system. Both instruments can be installed inside or outside the oven to measure the viscosity and density of the fluid under indoor environmental conditions.

[0061] In one embodiment of this application, the fluid injection system is also connected to an imaging capture system 13. Before the fluid is injected into the core sample 1, the imaging capture system 13 is used to observe and evaluate fluid dynamic phenomena, such as CO2 miscibility, foam, microemulsions, and the characterization of phase state and two-phase flow between crude oil and surfactant.

[0062] In one embodiment of this application, the imaging capture system 13 includes a camera 1301 and an observation unit. The camera 1301 has a charge-coupled device (CCD) image sensor. A charge-coupled device (CCD) is a photosensitive integrated circuit that captures images by converting photons into electrons. The CCD sensor decomposes image elements into pixels, and each pixel is converted into a charge whose intensity is related to the intensity of the light captured by that pixel.

[0063] In one embodiment of this application, the observation unit connects the imaging capture system 13 to the fluid injection system and the product measurement system 11 via valves, fittings and pipelines.

[0064] Further optimizing the design, the pressurization system 12 includes independently configured first gas source tank 1201 and second gas source tank 1202. The first gas source tank 1201 and second gas source tank 1202 are respectively connected to the inlet of the booster pump 1203, and the outlet of the booster pump 1203 is respectively connected to the first fluid tank 503 and the second fluid tank 504. The pressurization system 12 includes a booster pump 1203, the first gas source tank 1201, and the second gas source tank 1202, which store CO2 and N2 respectively. This system connects to the fluid delivery and gas circulation systems. The system aims to increase the gas pressure to the test pressure using the booster pump 1203 and then deliver it to an intermediate container for storage.

[0065] In another embodiment of this application, another method of pressurization is to use a second injection pump, which can be used directly to increase the test pressure. For example, if the test pressure requires 4500 psi, a commercially available CO2-filled cylinder typically has a pressure of about 800 psi, so the gas pressure needs to be increased to the pressure required for the test.

[0066] In one embodiment of this application, taking the pressurization using the pressurization system 12 as an example, assuming the pressure of the CO2 cylinder is 5.5 MPa and the required experimental pressure is 31 MPa, the CO2 is first transferred from the cylinder to the intermediate CO2 container (where the pressure is 0 psi). When the pressure in the intermediate CO2 container reaches 800 psi, the valve on the first storage tank is closed. Then, the second injection pump 502 is started, allowing the CO2 to reach the pressurization pump 1203. The pressurization pump 1203 is then started to increase the pressure to the test level, which is monitored by a pressure gauge or pressure sensor. When the pressure reaches the required experimental pressure, the pressurized CO2 is transferred to the intermediate CO2 storage container in the fluid delivery system 5, which is connected to the first injection pump 501 and pre-pressurized. Once the CO2 is transferred from the CO2 source pressurization system 12 to the intermediate CO2 container in the fluid delivery system 5, the pressurization pump 1203 is activated to establish the test pressure.

[0067] In one embodiment of this application, the first injection pump 501 can be set to constant pressure reverse mode. The constant pressure setting should be less than the experimental pressure by 0.03 MPa. After the pressure is balanced, the corresponding valve is closed, and the above experiment is repeated until the CO2 in the fluid delivery system 5 is filled.

[0068] In one embodiment of this application, the fluid analysis system 9 includes a gas chromatograph and a high-performance liquid chromatograph for analyzing the content of various oil and gas components produced from the core sample 1. The gas chromatograph and the high-performance liquid chromatograph are used to separate, identify, and quantify compounds in the products of the core sample 1. The system is connected to the product measurement and product separation system 7 via automatic or manual valves. The analyzed liquids and gases are transported to the fluid circulation system 10 through pipelines, fittings, and valves.

[0069] Further optimizing the scheme, the product separation system 7 includes a product separator 701 connected to the outlet of the clamp body 201, used to separate the fluid and liquid of the reaction products. The outlet of the product separator 701 is connected to the fluid recovery system 8, the fluid analysis system 9, and the fluid circulation system 10, respectively. The product separation system 7 includes a product separator 701 and a trace gas meter. The products discharged from the outlet end of the core sample 1 enter the product separator 701 for separation, and the trace gas meter can measure the gas produced from the test core under test conditions. The system is connected to the outlet of the clamp body 201, the fluid recovery system 8, the fluid analysis system 9, and the fluid circulation system 10 through multiple valves, fittings, and connectors.

[0070] The scheme is further optimized. The output measurement system 11 includes an output collector 1101 and a gas volume recorder 702 connected to the outlet of the gripper body 201. The output collector 1101 and the gas volume recorder 702 are respectively connected to the fluid circulation system 10. The product measurement system 11 consists of a high-temperature, high-pressure product collector 1101, automatic valves, and a gas volume recorder 1102, which measures the gas output. The product measurement system 11 is connected to a back pressure regulating system 14, a fluid recovery system 8, and a fluid analysis system 9 via several automatic valves, pipelines, and connectors. The effluent from the core sample 1 inside the holder body 201 can be transported to the product measurement system 11 via the back pressure regulating system 14. For example, in a liquid / gas displacement experiment using CO2 injection for oil recovery, the product collector 1101 can measure the produced liquid, and the gas volume recorder 1102 can measure the produced gas. This system can be installed inside or outside an oven to measure the amount of liquid and gas produced under experimental and room temperature conditions.

[0071] In a further optimized design, the fluid circulation system 10 includes a first circulation tank 1001, a second circulation tank 1002, and a third circulation tank 1003 arranged in parallel. The first and second circulation tanks 1001 and 1002 are respectively connected to a first injection pump 501, and the third circulation tank 1003 is connected to a second injection pump 502. The fluid circulation system 10 includes high-temperature, high-pressure gas from the first circulation tank 1001, second circulation tank 1002, and third circulation tank 1003, which are connected to the product measurement system 11, the fluid analysis system 9, and the product separation system 7 via pipelines, fittings, and automatic or manual valves. Under test conditions, gas and liquid from the product measurement system 11 and the product separation system 7 enter the fluid circulation system 10. The gas and liquid are then automatically transferred by the first injection pump 501 to an intermediate container in the fluid delivery system 5 for storage and subsequent use. The gas in the third circulation tank 1003 is injected into the intermediate container by the second injection pump 502 for recycling.

[0072] In one embodiment of this application, the data acquisition and control system 15 includes several units, such as a data acquisition and control processor, a memory, a data acquisition interface, a device control interface, and a network interface; the data acquisition and control system 15 can acquire information from various information sources of this invention.

[0073] This application also discloses an experimental method based on a high-temperature and high-pressure fully automated CO2 flooding integrated experimental device, including the following steps:

[0074] Core sample 1 is prepared according to experimental requirements. Then, core sample 1 is loaded into core clamping system 2, and confining pressure system 4 and pressure measurement system 3 are connected to core clamping system 2. Assuming that the size, physical properties, permeability and porosity of core sample 1 are known, saturated brine core sample 1 is placed in sleeve 204. End plug 202 is embedded in one side of sleeve 204 and installed in one end of clamping body 201. Then, the other end plug 202 is installed in the other end of clamping body 201. By combining them in this way, core sample 1, end plug 202 and clamping body 201 can be combined to form core sample 1 clamping system.

[0075] A set surrounding rock pressure is applied to the core sample 1 by the confining pressure system 4, and the pore pressure of the core sample 1 is established by the back pressure regulating system 14. Once the core sample 1 is placed in the holder body 201, under room temperature conditions, the confining pressure pump 402 injects confining pressure liquid into the annular space between the sleeve 204 and the holder body 201. The operating procedure is as follows: First, open valves MV#45 and MV#75, start the confining pressure pump 402 to inject confining pressure liquid into the annular space, and at the same time, vent the air in the annular space through valve MV#75; when the confining pressure liquid begins to flow out of MV#75, it indicates that the gas has been vented. Close MV#75 and apply the required confining pressure, usually 1500 psi or higher, to hold the core sample 1 in the holder body 201 at a constant pressure. The confining pressure is measured by the sensor 301 connected to the core sample 1 holder through valve MV#76. All pipelines and inlet / outlet pipelines of the pressure measurement system 3 are connected to the holder body 201. Before the pipelines are connected, all pipelines are saturated with brine used to saturate the core sample 1. Then, the back pressure regulating system 14 is used to establish the pore pressure inside the core sample 1. In this embodiment, the applied pore pressure is 500 psi. During operation, brine is injected into the core sample 1 through the confining pressure pump 402 and by opening a series of valves, including MV#4, six-way valve B, MV#7, MV#13, six-way valve C, MV#26, SV#9 (SV#7 and #8 are closed) and MV#29. Then, the injected water flows out of the core sample 1 to the back pressure regulating system 14. When the injection pressure exceeds the pressure of the back pressure regulating system 14, the brine flows into the product measurement system 11 through the back pressure regulating system 14. The second injection pump 502 in the fluid delivery system 5 is started to inject brine at a constant pressure or constant speed. The required pore pressure is established through the back pressure regulating system 14. After the pore pressure stabilizes, the pressure difference between the two ends of the core sample 1 is recorded. The brine permeability depends on the pressure difference between the two ends of the core sample 1.

[0076] Salt water was introduced into the core clamping system 2 via a fluid injection system, and the salt water permeability of core sample 1 was measured under indoor conditions. When the pore pressure reached 500 psi, the salt water permeability of core sample 1 was experimentally measured under indoor conditions. During the experiment, three flow rates (0.5, 1.0, and 2.0 cc / min) were used to inject salt water into core sample 1, and the corresponding pressure difference ΔP and injection flow rate were recorded to calculate the salt water permeability. For the salt water permeability measurement, salt water was first continuously injected into core sample 1 at a flow rate of 0.5 cc / min. During the injection, once ΔP at both ends of core sample 1 stabilized, ΔP and the injection flow rate were recorded. Then, the injection rate was increased to 1.0 cc / min, and the corresponding stable pressure was recorded. Finally, the injection flow rate was set to 2.0 cc / min, and the stable ΔP at both ends of core sample 1 was recorded. The relationship between pressure difference and injection rate should be linear, and the Darcy equation was used to calculate the salt water permeability of core sample 1.

[0077] Initial water saturation and original oil content of the core sample were established using a degassed oil flooding method. The initial water saturation and original oil saturation, or original oil saturation, were determined under pressure-free laboratory temperature and reservoir conditions. Experimental conditions: back pressure 500 psi, confining pressure 1500 psi, injection rates 0.05, 0.1, 0.2, 0.4, 0.8, 1.0, and 2.0 cc / min. First, the water in core sample 1 was displaced with degassed crude oil. During the crude oil flooding process at each rate, the water production and injection pressure were recorded until no more water was produced. It is important to note that during the brine injection stage, the brine in the pipeline should be replaced with dead crude oil to ensure that no brine or water enters core sample 1. The specific process is as follows:

[0078] Before oil drive, the inlet and outlet pipelines must be thoroughly cleaned with toluene or other cleaning fluid, and then saturated with crude oil. Assuming the inlet and outlet pipelines have been cleaned, the operating route for saturating crude oil at the inlet is as follows (refer to Figure 2): Starting from the second injection pump 502, open the following valves: MV#4, six-way valve B, MV#5, MV#11, six-way valve D, MV#24; close MV#23; close SV#10 and SV#11; open SV#12, MV#27, SV#3; close MV#6 to end plug 202; crude oil passes through MV#30 and then flows out from MV#78. The saturated crude oil operation route in the outlet pipeline is as follows: Starting from the second injection pump 502, open or close all valves: open valves MV#4, six-way valves B, MV#5, #11, six-way valves D, MV#24, and MV#27; close SV#3; open valve SV#6; then the crude oil passes through the outlet plug 202, through MV#48, MV#49, and MV#80; close MV#47, MV#50, and MV#79; and reaches the product measurement system 11, as shown in Figure 2. Once all pipelines, including the inlet and outlet pipelines, are saturated with crude oil, the crude oil water displacement experiment is ready.

[0079] Following the path of the oil saturation cutoff line described above, when bypass valve SV#6 is opened, degassed crude oil will be continuously injected into the system, bypassing core sample 1. At the start of injection, the flow rate is set as low as possible to ensure a uniform oil displacement front. Once SV#3 is opened and bypass valve SV#6 is closed, oil will be injected into core sample 1, with an initial injection rate set at 0.05 cc / min. During the injection process, water in core sample 1 will be displaced over time; the water production and pressure difference ΔP are recorded. When no additional water is produced at this injection rate and the pressure difference stabilizes, the total water displaced at the current flow rate and the stable ΔP are recorded. Then, the injection rate is doubled to 0.1 cc / min, and the process is repeated. When no more water is produced and ΔP stabilizes at each flow rate, the cumulative water production and pressure difference are recorded. This cycle is repeated, continuously increasing the flow rate until no more water is produced. In this case, the oil flow direction is changed to eliminate the end effect during oil displacement and ensure uniform water distribution in core sample 1. Maintaining the above injection path, close valve SV#3 and open valve SV#6 to inject crude oil into core sample 1 from the right side of the core sample 1 clamp. The crude oil extracted from core sample 1 flows through valve MV#30, then sequentially through valves MV#77 and MV#79, and finally reaches the fluid measurement system via back pressure regulation system 14. During the reverse displacement process, record the injection rate, the amount of water produced, and the stable pressure difference to measure the total water production. Calculate the initial water saturation Swi and the original oil content OOIP using the mass balance method. Furthermore, the effective permeability of the oil under Swi conditions is determined based on the pressure difference across core sample 1, the viscosity of the degassed crude oil, the size of core sample 1, and the injection rate. Calculate the effective permeability of the oil using Darcy's formula.

[0080] Restoring the wettability of the core sample: The wettability of core sample 1 is a key factor affecting fluid dynamics, fluid distribution in pores and recovery rate during water flooding, CO2 flooding and chemical flooding. Restoring the wettability of core sample 1 to reservoir conditions is crucial for reservoir engineering research and obtaining accurate experimental results.

[0081] Specific Procedure: The oven temperature was set to the project-specific test temperature and stabilized overnight to ensure thermal equilibrium. At an injection rate of 1.0 cc / min, the pore pressure and caprock pressure were gradually increased in increments of 500 psi until the target pore pressure (COXpsi) and confining pressure (COXpsi) were reached. During pressure setting, bypass valve SV#6 remained open, the injection flow rate was 1.0 cc / min, and confining pressure system 4 maintained a constant confining pressure, assuming the project required live displacement to restore the wettability of core sample 1 to reservoir conditions. During this process, the reservoir was emptied of dead crude oil and refilled with live crude oil, then, with bypass valve SV#6 closed, live crude oil was used to replace the dead oil. Subsequently, according to project requirements, the bridge plug of core sample 1 was aged in live crude oil under reservoir conditions for several weeks. During aging, one pore volume of live oil was injected daily to monitor differential pressure and water production. At the end of the aging process, the differential pressure and injection flow rate on core sample 1 were recorded to calculate the effective permeability (Keo) at the initial water saturation level (Swi). After aging with degassed and regenerated oil, core sample 1 is typically mixed wettability or slightly oily wettability.

[0082] Waterflooding recovery experiments are conducted to evaluate the waterflooding recovery factor, residual oil saturation, and waterflooding characteristic parameters. These experiments are typically performed under reservoir conditions, with pore pressure of COX MPa, confining pressure of COX MPa, and temperature of COX °C. This apparatus can be used to study the effects of injection flow rate, injection fluid viscosity, and water salinity on the waterflooding recovery rate of reservoirs with different lithologies.

[0083] Operating Procedure: Before starting the water drive, the live oil present in the inlet, bypass, and outlet pipelines must be driven out using injected water. These oil-filled pipelines are flushed with brine stored in the intermediate container to ensure that the oil produced during the water injection process comes entirely from core sample 1. The operating procedure is as follows: First, start the first injection pump 501, then open the following valves: MV2, six-way valve A, MV8, MV13, six-way valve C, and MV26. Close SV#7 and SV#8, open SV#9, and then open MV#29 to guide water to the inlet plug 202 of the clamp body 201. The water will then flow through SV#3 and SV#6 to the outlet plug 202 of the clamp body 201, through MV#48 and MV#49, and the back pressure regulating system 14. Once the water reaches the trap and no more oil flows out, it can be confirmed that the oil in the pipeline has been completely replaced.

[0084] Water Injection Test: After flushing all pipelines related to water drive, adjust the injection flow rate to meet engineering requirements. The operation path is as follows: Close valves SV#3 and SV#6. Then, inject water directly into core sample 1 to displace crude oil. The water and oil produced from core sample 1 are measured using product separation system 7 or product measurement system 11. Product separation system 7 can be used under high temperature and high pressure conditions. The flow path for measuring oil and water production using product separation system 7 is as follows: Crude oil from core sample 1 first passes through MV#47 and MV#53, then enters product separation system 7 for separation and measurement. Alternatively, under indoor environmental conditions, a trap can be used for separation and measurement, with the following path: After flowing out of core sample 1, crude oil passes through MV#48, MV#49, and MV#80, then enters product measurement system 11. During the water drive test, the collected data include oil and water production over time, total injected water volume, and pressure differential. This information is used to assess the recovery rate, remaining oil, and characteristic parameters of the waterflooding process, such as the maximum water saturation (Swmax) after waterflooding ends, the remaining oil saturation (Sorw) after waterflooding, and the relative permeability of the water phase at Sorw.

[0085] Injecting CO2 as a displacement agent into water-flooded core sample 1 during CO2 miscible flooding and oil recovery experiments yields two benefits: recovery of some residual oil in core sample 1 and in-situ sequestration of CO2 in the core sample 1 after waterflooding. The purpose of injecting CO2 into water-flooded core sample 1 is to study the oil recovery mechanism of CO2 miscible or immiscible flooding, chemically assisted CO2 injection, and the influence of various parameters on CO2 injection production dynamics. The following section uses miscible flooding as an example to illustrate how to use this device. To achieve miscible injection of crude oil and CO2 in the formation, it is assumed that the injection pressure must be higher than the minimum miscibility pressure MMP.

[0086] CO2 Cleaning Lines: Before starting CO2 miscible drive, if water is collected from the water-flooded core sample 1 during CO2 injection, the brine in the inlet, bypass, and outlet lines must be flushed with CO2. The procedure for cleaning the CO2 lines is as follows: First, set a low injection rate, then start the first injection pump 501 and open the following valves: MV#2, six-way valve A, MV#10, MV#15, six-way valve C, MV#26, SV#9, and MV#29, while keeping SV#7, SV#8, and MV#30 closed. CO2 passes through inlet plugs 202, SV#3, and SV#6, and then through outlet plugs 202, MV#48, MV#49, and MV#80 to reach the product measurement system 11.

[0087] CO2 injection operation procedure: Set the injection rate according to project requirements and conduct experiments under high temperature conditions. The CO2 flow path is similar to that used for cleaning pipelines. After setting the injection rate, start the first injection pump 501, immediately close valves SV#3 and SV#6, and then inject CO2 into core sample 1 to displace the remaining oil after water flooding. The effluent consisting of oil, water, and CO2 from core sample 1 passes through MV#48, MV#49, and MV#80 to reach the collector, where the oil, water, and gas are separated. The volume of produced oil and water can be measured using a graduated tube or an HPHT imaging system. The volume of produced gas is measured using a micro gas meter or a wet gas meter. The gas flows through MV#63 to a micro gas meter for measurement, or the volume of produced oil and gas can be measured using the effluent separation system 7. The produced gas can be separated using the product separation system 7, with the following gas flow path: Gas from core sample 1 flows through MV#47 and MV#53 to the product separation system 7, where its volume is measured. If gas component analysis is to be performed, the gas flows through SV#8 and MV#61 to the gas-liquid chromatography system. Valve MV#58 of this system is connected to valve MV#72 in the gas circulation system, and the gas is stored in an intermediate container within the gas circulation system. Additionally, gas from the product separation system 7 flows through SV#8, MV#61, and MV#71 to the gas circulation system.

[0088] The collected data were processed; the characteristic values ​​related to the above experiments included: brine permeability, initial water saturation and original oil saturation, effective oil permeability, maximum water saturation after waterflooding, residual oil saturation, effective brine permeability at residual oil saturation, and waterflood recovery rate. For CO2 miscible flooding, the relative CO2 permeability and maximum CO2 saturation were calculated at the total residual saturation of oil and water. At the end of CO2 miscible injection, the CO2 displacement and storage efficiency could be calculated.

[0089] Eigenvalues ​​based on water drive experiments

[0090] The brine permeability of core sample 1 can be calculated using the Kb:Darcy law, as shown in the following formula:

[0091] In the formula: K b Let D and Q be the permeability of the saline solution. b The brine injection flow rate is in cm. 3 / s;μ b ρ is the viscosity of the brine, cP; L is the length of core sample 1, cm; Δp is the pressure difference between the two ends of core sample 1, 10 -1 MPa; A is the cross-sectional area of ​​core sample 1, cm 2 .

[0092] During the brine injection process, the flow rate and corresponding pressure difference of core sample 1 were measured. With the brine viscosity, core sample 1 length, and core sample 1 cross-sectional area remaining constant, the brine permeability can be calculated using these parameters.

[0093] Crude oil effective permeability (Keo) of core sample 1 at initial water saturation:

[0094] In the formula, K eo D; Q represents the effective permeability at initial water saturation. o The oil injection speed, in cm 3 / s;μ o ρ is the viscosity of the oil, cP; L is the length of core sample 1, cm; Δp is the pressure difference between the two ends of core sample 1, 10 -1 MPa; A is the cross-sectional area of ​​core sample 1, cm 2 .

[0095] During the oil injection process, the injection rate and corresponding pressure difference of core sample 1 were measured. Using these measurement data, the effective permeability of the oil at the initial water saturation can be calculated, provided that the oil viscosity, the length of core sample 1, and the cross-sectional area of ​​core sample 1 are known.

[0096] Remaining oil saturation and waterflood recovery: Remaining oil saturation can be obtained from the original crude oil reserves (OOIP), pore volume, and produced oil volume. The expression is as follows:

[0097] The water saturation after water drive is expressed as follows: Sw(max) =1-S or (4)

[0098] In the formula; S or Residual oil saturation at the end of water drive, %PV or OOIP; V oi The volume of the original oil content in core sample 1 is given in cm³. 3 V op The volume of oil produced in core sample 1 is given in cm³. 3 V p The pore volume of the core sample is 1 cm³. 3 S w(max) The maximum water saturation %PV.

[0099] Effective brine permeability of core sample 1 at residual oil saturation (Kew):

[0100] In the formula: K ew D represents the effective brine permeability of core sample 1 under residual oil saturation.

[0101] Waterflood oil recovery factor (oil recovery rate): The waterflood oil recovery factor can be characterized by the original oil-bearing volume and the volume of oil produced by waterflooding. The expression is as follows:

[0102] In the formula: R fw For waterflooding recovery, the primary objective of %OOIPCO2 miscible flooding is to recover the remaining oil in core sample 1 after waterflooding and to provide a site for in-situ CO2 sequestration. Quantitative determination of the remaining oil and water content in waterflooded core sample 1 is crucial for assessing the CO2 solubility and capture mechanism in storage. Furthermore, after the CO2 enhanced oil recovery phase, the CO2 injection potential can be assessed based on various characteristic parameters of the CO2 miscible flooding process. These characteristic parameters include CO2 recovery rate, sequestration efficiency (ratio of CO2 sequestrated volume to total CO2 injected from core sample 1), CO2-oil exchange rate (ratio of oil recovered from CO2 miscible flooding to total injected CO2), total residual oil, water saturation, CO2 effective permeability at total residual fluid saturation, and CO2 injection capacity coefficient.

[0103] CO2 miscible flooding oil recovery coefficient: There are two methods for calculating the recovery rate. One method is based on the pore volume and original oil-bearing volume of core sample 1, and the other is based on the remaining oil in core sample 1 after waterflooding. The expression for calculating the recovery coefficient during CO2 injection, based on the original oil-bearing volume, is as follows:

[0104] In the formula: V oCO2 The volume of oil produced in the CO2 miscible flooding process (cm³) 3 .

[0105] Based on the residual oil from water flooding in core sample 1, equation (5) can be rewritten as:

[0106] In the formula: V oi *S or The product of these two values ​​represents the oil volume in core sample 1 after waterflooding, in cm³. 3 ; or represents the remaining oil saturation, %OOIP.

[0107] CO2 storage efficiency (E sCO2 CO2 sequestration efficiency is defined as the ratio of the volume of CO2 sequestrated in core sample 1 during CO2 miscible flooding to the cumulative volume of CO2 injected during the CO2 miscible flooding process.

[0108] In the formula: E sCO2 CO2 sealing efficiency, expressed as a percentage or fraction; V CO2 V represents the CO2 retention volume within core sample 1, in cm³, which is the difference between the total injected and generated CO2 during the CO2 miscible injection process.in.CO2 -∑V opr.CO2 ;∑V in.CO2 The total volume of injected CO2 is expressed in cm. 3 Read by the injection pump or MGM instrument; ∑V opr.CO2 The total volume of CO2 produced during the CO2 miscible injection process is expressed in cm³. 3 .

[0109] CO2-oil exchange rate (R) CO2-oil The CO2-oil exchange rate is defined as the ratio of the volume of oil displaced by injected CO2 in core sample 1 to the total volume of injected CO2. The expression for the CO2-oil exchange rate is:

[0110] Total residual volume (Vrt): The total residual volume refers to the sum of the volumes of residual oil and residual water in core sample 1. The expression for the total residual volume is: V rt =V or +V wr (11)

[0111] In the formula: V or The volume of remaining oil in core sample 1 is given in cm³. 3 V wr The volume of remaining water in core sample 1 is given in cm³. 3 The mass balance method can determine these two values. The remaining oil volume is the difference between the original oil supply volume and the total volume of oil produced from core sample 1 during water flooding and CO2 flooding.

[0112] The depleted reservoir after water injection and CO2 development contains three phases: a CO2-rich residual oil phase, a CO2-rich water phase, and a CO2 phase. Quantitative analysis of these three phases in core sample 1 is crucial for accurately assessing CO2 storage capacity. Typically, only residual oil and maximum CO2 saturation are assessed during CO2-EOR processes. However, residual water after CO2 injection is often overlooked. CO2-rich residual water plays a significant role in CO2 storage because the presence of abundant water in the formation provides a medium for CO2 dissolution. The following procedure measures the water content after the CO2-EOR process.

[0113] At the end of water injection, the maximum water saturation S can be determined according to the material balance method. w(max)This is equivalent to the water content of core sample 1. During CO2 miscible flooding, a mixture of water, CO2, and oil is produced simultaneously, and the production amounts are recorded as a function of time. Therefore, at the end of CO2 miscible flooding, the total amount of water produced from core sample 1 should be known and collected in the trap of the product measurement system 11. Let Vrw-wf be the water volume in core sample 1 after water flooding, which is the product of water saturation and pore volume. Vpr.w-CO2 is the water volume produced during CO2 miscible flooding. In this case, the difference between Vrw-wf and Vpr.w-CO2 represents the volume of CO2 water remaining in core sample 1 after CO2 flooding.

[0114] Assuming that these two residual phases do not flow in the pores of core sample 1, the volume of CO2 in core sample 1 at the end of the CO2 injection process can be calculated by the following formula: V co2 =V p -V rt (12)

[0115] In the formula: V CO2 Let be the volume occupied by CO2 in core sample 1, in cm³. 3 ; represents the pore volume of core sample 1, in cm³. 3 V rt The total residual phase of oil and water, cm 3 .

[0116] CO2 injection capacity (ICO2) at the core sample 1 scale: Fluid injection capacity refers to the ease with which a fluid enters the formation. At the core sample 1 scale, the injection capacity index is directly proportional to the injection rate and inversely proportional to the pressure differential at the core sample 1. The CO2 injection capacity index ICO2 is expressed as:

[0117] In the formula: Q CO2 CO2 injection rate, cm³ / min; ΔP CO2 The pressure difference across core sample 1 is given in MPa. The relative injection rate of CO2, IrCO2, is also used to evaluate the degree of injection rate loss, as shown in the following formula:

[0118] In the formula: Iw is the water injection capacity index during water injection, %; its expression is as follows:

[0119] In the formula: Q w ΔPw represents the water injection rate, in cm³ / min; ΔPw represents the pressure difference between the two ends of core sample 1.

[0120] During water and CO2 flooding, Q can be obtained. CO2 Q w ΔP CO2and Δ Pw Each parameter. Therefore, I can be calculated quantitatively. CO2 and I rCO2 Expressions 7, 8, 9, 10, 11, and 12 can be used to evaluate CO2 sequestration potential studies.

[0121] In one embodiment of this application, the fluid property measurement system 6 according to an exemplary embodiment of this disclosure includes a densitometer 602 and a viscometer 601. This system can determine the density and viscosity of the fluid before it is injected into the core sample 1 online, ensuring that the measurement results have the same test conditions as the data obtained from the displacement experiment of the core sample 1. Under the test conditions, these two parameters can be determined in real time for any single fluid or liquid / liquid, gas / liquid, and gas / gas mixtures. The densitometer and viscometer 601 can be installed in an oven, such as the clamp body 201, the imaging capture system 13, and the product separation system 7, along with other equipment. The system is connected to the fluid delivery system 5 and the back pressure regulation system 14 via connectors and valves. The data acquisition and control system can obtain information from the fluid property measurement system 6.

[0122] Fluid Flow Path: Taking the measurement of oil density and viscosity as an example, the first injection pump 501 is started and valve MV#2 is opened, while valves MV#1, 6-way valve A, and MV#6 connected to the intermediate oil storage container are closed. The oil passes through MV#11, 6-way valve D, MV#23, MV#31, and MV#37. Then, the oil is injected into the densitometer 602 and flows out through valve MV#43. From there, it flows through MV#42, MV#50, and MV#80, and enters the product measurement system 11 through the back pressure regulating system 14. Valves MV#37 and MV#43 should remain closed during the measurement process. For oil viscosity measurement, the operating path is the same as for density measurement, up to MV#32. From there, the oil enters the viscometer 601 through MV#32 and MV#38 and flows out through outlet MV#44. Afterward, the oil follows the same path as in the density measurement process until it reaches the trap.

[0123] In one embodiment of this application, before CO2 is injected into core sample 1, an imaging capture system 13 can be used to evaluate the dynamic behavior of injectants (such as CO2 foaming agents, microemulsions, and gels) in real time under test conditions. This system is connected to the fluid delivery system 5 and the product measurement system 11 via connectors and valves. The imaging capture system 13 can be used to evaluate the minimum miscibility pressure of supercritical CO2 with crude oil, the bubble size in CO2 foam, and the phase behavior of surfactant solutions with crude oil in tertiary oil recovery.

[0124] Typically, two injecting agents combine to form a single phase, such as CO2 foam, which is a product formed by a surfactant and CO2 under certain conditions. This foam is used in chemically assisted CO2 enhanced oil recovery and geological storage research projects. In the imaging capture system 13, the first injection pump 501 and the second injection pump 502 can inject the surfactant solution and CO2 into the observation chamber respectively. The fluid flow path is as follows:

[0125] Fluid flow path: Before injecting either of the two fluids into the observation chamber, fill the observation chamber with one of the two fluids and establish the test conditions. For example, if the surfactant solution and CO2 are injected simultaneously, the surfactant solution can be used to fill the observation chamber.

[0126] Starting from the first injection pump 501 and the second injection pump 502, the CO2 is connected to the intermediate container for storage via valve MV#2, six-way valve A, and MV#10 of the first injection pump 501. CO2 flows from the intermediate container through MV#16, SV2, six-way valve D, MV#23, MV#34, and MV#35 to the observation chamber. The surfactant is injected using the second injection pump 502 via MV#4, six-way valve B, and MV#7 to the intermediate container for storing the surfactant solution (labeled as a brine / nitrogen intermediate container, as shown in Figure 2). The surfactant solution flows from the intermediate container through MV#13, six-way valve C, MV#25, MV#33, and MV#35 to the observation chamber. Before both fluids reach the observation chamber, MV#39, MV#41, and MV#50 are opened to the backpressure regulating system 14, and under test conditions, the observation chamber is filled with one of the two fluids. For example, if the surfactant solution and CO2 are injected simultaneously, the observation chamber can be filled with the surfactant solution.

[0127] In one embodiment of this application, the gas flow path of the booster system 12 is as follows: Taking the use of the booster system 12 for pressurization as an example, assuming the pressure of the CO2 cylinder is 5.5 MPa and the required pressure for the experiment is 31 MPa. First, the CO2 in the cylinder is transferred to the intermediate CO2 container (the pressure in the container is 0). When the pressure in the intermediate CO2 container reaches 800 psi, the valve on the cylinder is closed. The MV#3 valve of the second injection pump 502 is connected to the MV#84 valve. The second injection pump 502 is started, the MV#3 valve, MV#84 valve are opened, and then the MV#22 valve is opened, allowing the CO2 to flow through the MV#19 valve and SV#1 valve to the booster pump 1203. Then the MV#17 valve is closed and the MV#18 valve for monitoring pressure is opened through the booster pump 1203. The booster pump 1203 is started to increase the pressure to the test level, which is monitored by a pressure gauge or pressure sensor. When the pressure reaches the required level for the experiment, open MV#17 and MV#16. This transfers the pressurized CO2 to the intermediate CO2 storage container in the fluid delivery system 5. This intermediate container is connected to the first injection pump 501 via MV#2, a six-way valve, and MV#10 valve, and has been pre-pressurized. Once the CO2 has been transferred from the CO2 source pressurization system 12 to the intermediate CO2 container in the fluid delivery system 5, close SV#1 and activate the booster pump 1203 to establish the test pressure. The first injection pump can be set to constant pressure reverse mode (this pressure setting should be 0.03 MPa less than the test pressure). After the pressure is balanced, close MV#16 and MV#17, and repeat the above experiment until the fluid delivery system 5 is full of CO2.

[0128] In one embodiment of this application, the heating system consists of two ovens, simulating test conditions by controlling the temperature. The ovens should have front and rear doors for easy maintenance and replacement of components. The temperature control range is from 20°C to 150°C. The first oven houses the clamp body 201, a densitometer 602, a viscometer 601, a product separator 701, and an observation window for fluid imaging. Several sensors are mounted on the outside of the first oven.

[0129] The second oven contains all the intermediate containers: the CO2 / N2 intermediate container from the pressurization system 12, the CO2, oil, and brine / N2 intermediate containers from the fluid delivery system 5, and the liquid and gas recovery system intermediate containers from the gas circulation system. Other components, such as the gas chromatograph, the back pressure regulating system 14, and the exterior of the first oven are also included.

[0130] In one embodiment of this application, the data acquisition and control system 15 includes memory for data (acquisition instructions and control instructions), a control processor, a data acquisition interface, a device control interface, and control instructions. It may also include a network interface. The data acquisition and control system may include a personal computer, such as a desktop computer, laptop computer, tablet computer, etc.

[0131] The data acquisition and control system 15 can acquire information from various components of the present invention, such as the fluid delivery system 5, image capture system, pressure system, automatic containment system, fluid property measurement system, automatic gas or liquid / liquid separator system, gas micro-metering system, back pressure regulation system 14, pressurization system 12, gas-liquid chromatography, gas circulation system and fluid recirculation system.

[0132] Data acquisition and control processor: The data acquisition and control processor may include one or more processors capable of receiving and processing data from sensors of the data acquisition and control system 15. The processor may include application-specific integrated circuits (ASICs) in some embodiments, and the data acquisition processor may include a reduced instruction set processor (RISC). Additionally, the processor may include a single-core processor, a multi-core processor, and a graphics processor. Multiple processors may provide parallel or sequential execution of one or more technologies described in this disclosure. The processor may include, for example, a first data acquisition processor for data acquisition functions and a control processor for control functions. The processor may receive instructions and data from memory.

[0133] Memory: The memory may include one or more tangible, non-transitory computer-readable storage media of the data acquisition and control system 15, and may include volatile memory, such as random access memory, and non-volatile memory, such as ROM, flash memory, hard disk drive, any other suitable optical, magnetic, or solid-state storage media, or combinations thereof. The memory is accessible by a processor and may store executable computer code. The executable computer code may include program instructions for implementing one or more technologies of this disclosure. For example, the executable computer code may include processor-executable data acquisition instructions to implement one or more embodiments of this disclosure. The data acquisition instructions may include instructions for acquiring data from sensors of the data acquisition and control system 15 via a data acquisition interface and processing the acquired data (e.g., converting data from analog data to digital data). Processing may include comparing the acquired data value (e.g., pressure value) with a threshold and providing a comparison-based notification.

[0134] Computer code: Executable computer code may include device control instructions. For example, control instructions for the oil displacement device of core sample 1 may include instructions for controlling the fluid delivery system 5, image capture system, differential pressure system, density and viscosity measurement system, pressurization system, imaging capture system 13, gas chromatography, gas or liquid / liquid separator, back pressure regulation system, automatic confining pressure system 4, or any combination thereof. Such instructions may include instructions for sending control signals, for example, sending control signals to valves, displacement pumps, back pressure regulation system 14, automatic pneumatic control enhancer, and other components described in this disclosure. Processing may include comparing data values ​​with thresholds and providing comparison-based notifications. Processing may include comparing data values ​​with thresholds and performing actions based on the comparisons.

[0135] Data Acquisition Interface: The data acquisition interface may include one or more interfaces providing communication between the data acquisition and control system 15 and the components of the core displacement unit. For example, the data acquisition interface may include circuitry for communicating with upstream and downstream pressure sensors, differential pressure sensors, pressure sensors of the injection pump, cameras in the imaging capture system 13, densitometer 602, viscometer 601, booster pump 1203, separators, back pressure regulators, and other components of the core sample 1 displacement unit. The data acquisition interface may include wired or wireless interfaces and may be used for communication via wired or wireless networks.

[0136] Network Interface: The network interface provides communication between the data acquisition and control system 15 and other devices such as the control system. The network interface and the data acquisition interface can be combined. The network interface may include a wired network interface card, a wireless network interface card, or a combination thereof. The network interface may include circuitry for receiving and transmitting signals to and from a communication network, such as an antenna system, radio frequency transceiver, amplifier, tuner, oscillator, digital signal processor, etc. The network interface can communicate with networks such as the Internet, intranet, wide area network, local area network, metropolitan area network, or other networks.

[0137] Display: The display may include a cathode ray tube display, a liquid crystal display, an organic light-emitting diode display, or other suitable display. The display may show a user interface that displays data acquired from components received from the core sample 1 displacement device. The display may be a touchscreen and may include or provide touch-sensitive elements through which the user can interact with the user interface. If the data received from the components of the core sample 1 displacement device meets certain conditions, the display may display a notification, such as an alarm. For example, if the pressure value obtained from the pressure sensor exceeds a threshold, a notification may be displayed.

[0138] The data acquisition and control system can also provide control signals to the components of the core sample 1 displacement device. For example, it can provide control signals to the fluid delivery system 5, the pressurization system 12, the image capture system, the differential pressure system, the pressurization system, the gas chromatography, the density and viscosity measurement system, the gas or liquid / liquid separator, the back pressure regulation system 14, the gas / liquid recovery system, the gas circulation system, the automatic confining pressure system 4, or any combination thereof.

[0139] Equipment control interface: The equipment control interface may include one or more interfaces that provide communication between the data acquisition and control system 15 and the equipment of the core sample 1 displacement device. For example, the equipment control interface may include circuitry for sending control signals to valves, pumps, cameras, automatic confining pressure system 4, back pressure regulation control system, and other equipment in the core sample 1 displacement device. The equipment control interface may include wired or wireless interfaces and may be used for communication via wired or wireless networks.

[0140] The data acquisition and control system can be coupled to input devices (e.g., one or more input devices). Input devices may include, for example, a keyboard, mouse, microphone, or other input devices. Input devices can enable interaction with a user interface displayed on a monitor. For example, input devices can provide value input to directly or indirectly control components of the core sample displacement device.

[0141] In the description of this invention, it should be understood that the terms "longitudinal", "lateral", "up", "down", "front", "rear", "left", "right", "vertical", "horizontal", "top", "bottom", "inner", "outer", etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings, and are only for the convenience of describing this invention, and are not intended to indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation, and therefore should not be construed as a limitation of this invention.

[0142] The embodiments described above are merely preferred embodiments of the present invention and are not intended to limit the scope of the present invention. Various modifications and improvements made by those skilled in the art to the technical solutions of the present invention without departing from the spirit of the present invention should fall within the protection scope defined by the claims of the present invention.

Claims

1. A high-temperature and high-pressure full-automatic CO2 flooding and embedding integrated experimental device, characterized in that, include: A core clamping system (2) is used to clamp a core sample (1). The core clamping system (2) is connected to a pressure measuring system (3) and a confining pressure system (4) for adjusting the confining pressure. The core clamping system (2) includes a clamping body (201) connected to the confining pressure system (4). The clamping body (201) is provided with end plugs (202) with fluid diversion at both ends. The core sample (1) is fixed in the clamping body (201) after being wrapped by a sleeve (204) with a pressure measuring point (203). A fluid injection system, which is connected to the inlet of the core clamping system (2), is used to inject fluid into the core clamping system (2); The fluid injection system is equipped with a fluid characteristic measurement system (6) for measuring fluid characteristics; the fluid injection system includes an independently configured first injection pump (501) and a second injection pump (502), the first injection pump (501) being connected to a first fluid tank (503), a second fluid tank (504), and a third fluid tank (505), and the second injection pump (502) being connected to the first fluid tank (503), the second fluid tank (504), and the third fluid tank (505), respectively. The body tank (505) is connected to the clamp body (201) and the fluid characteristic measurement system (6) respectively. The first fluid tank (503) and the second fluid tank (504) are respectively connected to the pressurization system (12). The fluid characteristic measurement system (6) includes a viscometer (601) and a densitometer (602) arranged in parallel. The fluids flowing out of the first fluid tank (503), the second fluid tank (504) and the third fluid tank (505) are mixed and then enter the viscometer (601) and the densitometer (602) respectively to measure the characteristics of the mixed fluid. The product separation system (7) is connected to the outlet of the core clamping system (2) through the back pressure regulating system (14). The product separation system (7) is connected to the fluid recovery system (8), the fluid analysis system (9), and the fluid circulation system (10). The fluid circulation system (10) includes a first circulation tank (1001), a second circulation tank (1002), and a third circulation tank (1003) arranged in parallel. The first circulation tank (1001) and the second circulation tank (1002) are respectively connected to the first injection pump (501), and the third circulation tank (1003) is connected to the second injection pump (502). The product measurement system (11) is connected to the outlet of the core clamping system (2) and is used to measure the product of the core sample (1) in the core clamping system (2).

2. The high-temperature and high-pressure fully automatic CO2 flooding integrated experimental device according to claim 1, characterized in that: The confining pressure system (4) includes a confining pressure fluid storage tank (401), which is connected to the clamp body (201) via a confining pressure pump (402); the confining pressure pump (402) is connected to a back pressure regulating system (14).

3. The high-temperature and high-pressure fully automatic CO2 flooding integrated experimental device according to claim 1, characterized in that: The booster system (12) includes a first gas source tank (1201) and a second gas source tank (1202) that are independently set up. The first gas source tank (1201) and the second gas source tank (1202) are respectively connected to the inlet of the booster pump (1203), and the outlet of the booster pump (1203) is respectively connected to the first fluid tank (503) and the second fluid tank (504).

4. The high-temperature and high-pressure fully automatic CO2 flooding integrated experimental device according to claim 1, characterized in that: The product separation system (7) includes a product separator (701) connected to the outlet of the clamp body (201) for separating the fluid and liquid of the reaction products. The outlet of the product separator (701) is connected to the fluid recovery system (8), the fluid analysis system (9) and the fluid circulation system (10), respectively.

5. The high-temperature and high-pressure fully automatic CO2 flooding integrated experimental device according to claim 1, characterized in that: The output measurement system (11) includes an output collector (1101) and a gas volume recorder (702) connected to the outlet of the gripper body (201), and the output collector (1101) and the gas volume recorder (702) are respectively connected to the fluid circulation system (10).

6. A high-temperature, high-pressure fully automated CO2 flooding and burial integrated experimental method, employing the high-temperature, high-pressure fully automated CO2 flooding and burial integrated experimental device as described in any one of claims 1-5, characterized in that... Includes the following steps: Prepare core samples (1) according to experimental requirements, then load the core samples (1) into the core clamping system (2), and connect the confining pressure system (4) and the pressure measurement system (3) to the core clamping system (2); The set surrounding rock pressure is applied to the core sample (1) by the confining pressure system (4), and the pore pressure of the core sample (1) is established by the back pressure adjustment system (14). Salt water was introduced into the core clamping system (2) through a fluid injection system, and the salt water permeability of the core sample (1) was measured in an indoor environment. Data on initial water saturation and original oil content of core samples were obtained through degassing oil flooding. To restore the wettability of the core sample; Conduct waterflooding oil recovery rate experiments; Conduct CO2 miscible flooding oil recovery and storage experiments; The collected data is processed.

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