CN-122016905-A - CO2Method and device for evaluating wettability of water-oil-shale multiphase system

CN122016905ACN 122016905 ACN122016905 ACN 122016905ACN-122016905-A

Abstract

The specification provides a method and a device for evaluating wettability of a CO 2 -water-oil-shale multiphase system, which combine a traditional contact angle measurement method with a nuclear magnetic resonance technology, overcome the defect that the contact angle measurement method cannot quantitatively study micro-nano scale pore wettability, strengthen accuracy of the nuclear magnetic resonance technology shale pore scale wettability, simulate a shale reservoir high-temperature and high-pressure environment, establish a CO 2 -water-oil-shale multiphase coexisting system, realize comprehensive evaluation of shale reservoir wettability combined from a macroscopic scale to a microscopic scale, realize fine wettability characterization from the macroscopic scale to the microscopic scale, and establish a method for accurately evaluating shale reservoir wettability in the process of developing and geological burying of a CO 2 reinforced shale oil and gas reservoir. The scheme is simple, convenient, efficient, accurate, comprehensive and high in applicability, lays a solid foundation for large-scale development of shale oil and gas reservoirs by CO 2 and long-term sealing and storage of CO 2 , and has a wide application prospect.

Inventors

TIAN LENG
Huang Bocong
GU DAIHONG
JIANG LILI
WANG ZECHUAN
HUANG WENKUI
CHAI XIAOLONG

Assignees

中国石油大学(北京)
北京众博达石油科技有限公司

Dates

Publication Date: 20260512
Application Date: 20260121

Claims (10)

1. A method for evaluating wettability of a CO 2 -water-oil-shale multiphase system, comprising: Continuously monitoring the pressure, the temperature and the density of a fluid mixture in a high-pressure unit in the process of constructing a high-temperature and high-pressure multiphase system of CO 2 -water-oil-shale and carrying out a high-temperature and high-pressure multiphase contact angle experiment on a first-page rock sample, and continuously shooting images by means of a high-resolution optical camera; calculating a water wetting angle and an oil wetting angle according to the monitoring result and the photographed image, and further calculating a contact angle wettability parameter based on the water wetting angle and the oil wetting angle; calculating a contact angle correction parameter, and correcting the wettability parameter of the contact angle by adopting the contact angle correction parameter; during the nuclear magnetic resonance experiment of the second shale sample, acquiring the mass of the second shale sample after each operation step; Calculating the water absorption and oil absorption of the second shale sample after the action of CO 2 in the nuclear magnetic resonance experiment process according to the mass of the second shale sample after each operation, and calculating the nuclear magnetic wettability parameter based on the water absorption and the oil absorption; calculating a nuclear magnetic correction index, and correcting the nuclear magnetic wettability parameter by adopting the nuclear magnetic correction index; and evaluating the wettability of the CO 2 -water-oil-shale multiphase system according to the corrected contact angle wettability parameter and the corrected nuclear magnetic wettability parameter.
2. The method of claim 1, wherein constructing a high temperature high pressure multiphase system of CO 2 -water-oil-shale for a first page of rock sample, performing a high temperature high pressure multiphase contact angle experiment, comprises: Cleaning all components of the device by using ethanol and distilled water, polishing a first rock sample by using a diamond abrasive, and cleaning by using ethanol; placing a sheet-shaped first-page rock sample into a molecular vacuum pump for vacuumizing so as to saturate formation water at high pressure and high temperature; Placing a first page of rock sample on a movable magnetic device and in a high-temperature high-pressure model, and simultaneously raising the temperature to a required value; Opening a water injection valve, injecting reservoir saline into the high-temperature high-pressure model by using a first injection pump until the container is filled, and closing the water injection valve; Opening an air injection valve, slowly injecting CO 2 gas into a high-temperature high-pressure model filled with salt water through a first constant-pressure/constant-flow pump, and pressurizing the high-temperature high-pressure model to a preset pressure at a constant temperature; After the pressure in the high-temperature and high-pressure model is stable, an oiling valve is opened, a drop of crude oil is distributed to the surface of a first rock sample through an injection needle, so that the construction of a high-temperature and high-pressure multiphase system of CO 2 -water-oil-shale is finished; Images were continuously taken with a high resolution optical camera and drop volumes and contact angles were estimated by detecting drop contours and multiphase contact points using axisymmetric drop shape analysis techniques.
3. The method of claim 1, wherein further calculating the contact angle wettability parameter based on the water wetting angle and the oil wetting angle comprises calculating the contact angle wettability parameter by the formula I CA =（90-θ CW ）/90-（90-θ CO /90, wherein I CA represents the contact angle wettability parameter, θ CW represents the water wetting angle after CO 2 , and θ CO represents the oil wetting angle after CO 2 ; And/or the number of the groups of groups, Calculating the contact angle correction parameters comprises calculating the contact angle correction parameters according to the following formula C CA =A d /A s , wherein C CA represents the contact angle correction parameters, A d represents the projection area of the target fluid in the process of shooting the image, and A s represents the projection area of the first shale sample in the process of shooting the image.
4. The method of claim 1, wherein the second shale sample is subjected to nuclear magnetic resonance experiments and the mass of the second shale sample after each operating step is obtained by: Carrying out vacuumizing and pressurizing saturated formation water test on the second shale sample, measuring a first mass m 1 of the second shale sample after saturation is completed, and simultaneously obtaining a nuclear magnetic resonance T2 spectrum curve of the second shale of saturated formation water; loading a second shale of saturated formation water into a core holder, connecting a displacement flow, displacing a second shale sample of the saturated water by heavy water, monitoring a nuclear magnetic resonance T2 spectrum curve in the displacement process, stopping the displacement after no signal response is caused on the nuclear magnetic resonance T2 spectrum curve, and measuring the second shale sample to obtain a second mass m 2 ; Displacing a second shale sample of saturated heavy water with formation crude oil to establish irreducible water saturation, measuring a third mass m 3 of heavy water displaced from the second shale sample; Aging the displaced second shale sample at the stratum temperature for a preset time, measuring a nuclear magnetic resonance T2 spectrum curve of the aged second shale sample, and measuring a fourth mass m 4 of the second shale sample; Injecting CO 2 into the second shale sample by using a high-pressure pump, keeping the temperature and the pressure of the second shale sample the same as those of a high-temperature high-pressure multiphase contact angle experiment, closing an inlet valve and an outlet valve of an experimental device to enable the second shale sample to be in a well-stewing state, and recording the environmental pressure of the second shale sample in the well-stewing process; the outlet valve is opened and the pressure is reduced step by step until the second shale sample is not discharged, then the fifth mass m 5 of the displaced heavy water, the sixth mass m 6 of the displaced crude oil are measured, and the nuclear magnetic resonance T2 spectrum curve after the CO 2 is acted on is measured.
5. The method of claim 4, wherein calculating the water absorption and oil absorption of the second shale sample after CO 2 acts during the nuclear magnetic resonance experiment based on the mass of the second shale sample after each operation, and calculating the nuclear magnetic resonance wettability parameters based on the water absorption and oil absorption comprises: Calculating the water absorption NMR CW =m 2 -m 3 -m 5 of the second shale sample after the CO 2 acts in the nuclear magnetic resonance experiment process, and calculating the oil absorption NMR CO =m 4 -（m 2 -m 3 ）-m 6 of the second shale sample after the CO 2 acts in the nuclear magnetic resonance experiment process; the nuclear magnetic wettability parameter was calculated according to the following formula: , Where j is the minimum value for which NMR CW ×10 j and NMR CO ×10 j are integers; And/or the number of the groups of groups, Calculating the nuclear magnetic correction index includes calculating the nuclear magnetic correction index according to the following formula: , Wherein, C NMR nuclear magnetic correction index, TOC is total organic carbon content of the second shale sample, M w is hydrophilic mineral percentage, For the porosity of the second shale sample, j is the smallest integer that makes C NMR a pure decimal.
6. The method of claim 1, wherein evaluating wettability of the CO 2 -water-oil-shale multiphase system based on the corrected contact angle wettability parameter, the corrected nuclear magnetic wettability parameter, comprises: I w =I CA ×C CA +I NMR ×C NMR , wherein I w represents the wettability comprehensive parameter, I CA represents the contact angle wettability parameter, C CA represents the contact angle correction parameter, I NMR represents the nuclear magnetic wettability parameter, and C NMR represents the nuclear magnetic correction index; The wettability of the CO 2 -water-oil-shale multiphase system was evaluated based on the wettability integrated parameters.
7. The method of claim 6, wherein evaluating wettability of the CO 2 -water-oil-shale multiphase system based on the wettability integrated parameter comprises: Judging the lipophilicity and the hydrophilicity of the shale reservoir according to the positive and negative characteristics of the wettability comprehensive parameters, wherein the method comprises the steps of determining that the shale reservoir is hydrophilic when the wettability comprehensive parameters are larger than 0, and determining that the shale reservoir is oleophilic when the wettability comprehensive parameters are smaller than 0.
8. The method of claim 6, wherein evaluating wettability of the CO 2 -water-oil-shale multiphase system based on the wettability integrated parameter comprises: the method comprises the steps of determining that the shale reservoir is basically weak in wettability when the absolute value of the wettability comprehensive parameter is smaller than a wettability threshold value, and determining that the shale reservoir is strong in wettability when the absolute value of the wettability comprehensive parameter is larger than or equal to the wettability threshold value.
9. A device for evaluating wettability of a CO 2 -water-oil-shale multiphase system, comprising: The first experiment unit is used for continuously monitoring the pressure, the temperature and the density of the fluid mixture in the high-pressure unit and continuously shooting images by means of a high-resolution optical camera in the process of constructing a high-temperature and high-pressure multiphase system of CO 2 -water-oil-shale and carrying out a high-temperature and high-pressure multiphase contact angle experiment on a first rock sample; The first calculating unit is used for calculating a water wetting angle and an oil wetting angle according to the monitoring result and the shot image, and further calculating a contact angle wettability parameter based on the water wetting angle and the oil wetting angle; the second calculation unit is used for calculating a contact angle correction parameter and correcting the wettability parameter of the contact angle by adopting the contact angle correction parameter; The second experiment unit is used for acquiring the mass of the second shale sample after each operation step in the process of performing nuclear magnetic resonance experiment on the second shale sample; the third calculation unit is used for calculating the water absorption and oil absorption of the second shale sample after the CO 2 acts in the nuclear magnetic resonance experiment process according to the mass of the second shale sample after each operation, and calculating the nuclear magnetic wettability parameters based on the water absorption and the oil absorption; A fourth calculation unit for calculating a nuclear magnetic correction index, and correcting the nuclear magnetic wettability parameter by using the nuclear magnetic correction index; And the evaluation unit is used for evaluating the wettability of the CO 2 -water-oil-shale multiphase system according to the corrected contact angle wettability parameter and the corrected nuclear magnetic wettability parameter.
10. An electronic device, comprising: the device comprises a memory and a processor, wherein the processor and the memory are in communication connection, the memory stores computer instructions, and the processor realizes the method for evaluating the wettability of the CO 2-water-oil-shale multiphase system according to any one of claims 1 to 8 by executing the computer instructions.

Description

Method and device for evaluating wettability of CO 2 -water-oil-shale multiphase system Technical Field The application relates to the technical field of oil and gas exploration and development, in particular to a method and a device for evaluating wettability of a CO 2 -water-oil-shale multiphase system. Background Compared with the conventional reservoir, the shale reservoir has micro-nano pore development, complex mineral composition and obvious capillary effect, so that the development difficulty is high. CO 2 has been widely demonstrated to be an effective carrier for the efficient development of shale oil and gas resources. In the long-term development process of injecting CO 2 into shale reservoirs, complex phase environment where CO 2 -water-oil-shale coexist can be formed, and a series of interactions between reservoir rocks and fluid can be caused, and the changes directly affect the wettability of the shale reservoirs. Wettability is a macroscopic manifestation of interfacial interactions between formation fluids and reservoir rocks, and is also a key factor in controlling fluid flow, displacement mechanisms, and spatial distribution characteristics, directly determining the implementation effects of CO 2 in enhanced shale hydrocarbon reservoir recovery and CO 2 geological sequestration. Through extensive investigation, the method for evaluating the interface wetting characteristics mainly comprises a contact angle measurement method, an Amott method, a USBM method, an Amott/USBM combination method, a spontaneous imbibition method and the like. Contact angle measurement is one of the most commonly used methods for characterizing shale wettability at present due to its intuitiveness and convenience. The method for measuring the contact angle of the shale after the action of CO 2 mainly comprises the following steps of (1) an indirect method of continuously injecting CO 2 into a reaction kettle containing a sufficient amount of solution, immersing a sheet or powder shale sample under high temperature and high pressure conditions, taking out the sample, and measuring the contact angle at normal temperature and normal pressure, and (2) a direct method of directly measuring the contact angle in a CO 2 gas environment and researching the wettability of the rock by changing the temperature and the pressure. However, unlike conventional hydrocarbon reservoirs, shale is rich in organic matter as a source rock and has complex mineral composition, while developing oleophilic organic matter pores and hydrophilic inorganic mineral pores, so shale exhibits strong wetting heterogeneity on a microscopic scale. Although the shale contact angle indirect measurement method after the CO 2 is acted can simulate the high-temperature and high-pressure environment of the stratum, a CO 2 -water-oil-rock multiphase system cannot be directly established, and the difference exists between the method and the actual reservoir condition. Direct contact angle measurement although it is possible to build a multiphase CO-existence system, it does not take into account changes in the physicochemical properties of the reservoir mineral components, etc. caused by the long-term interaction of shale with CO 2. In addition, the contact angle measurement method is characterized by shale surface macroscopic wettability, and quantitative statistical research on micro-nano scale pore wettability cannot be carried out. Although the nuclear magnetic resonance technology can obtain the distribution characteristics of the wettability of the rock sample pores, the test result is also influenced by the characteristics of the pores, the properties of the fluid and the interaction between the pores and the fluid, and the characterization difficulty of the scale wettability of the shale pores is increased. Nuclear Magnetic Resonance (NMR), a technique that is efficient, non-destructive, and rapid in measuring fluids and their distribution, can provide nanoscale pore fluid distribution information at the microscopic scale, and the test results are not affected by sample heterogeneity. In recent years, nuclear magnetic resonance technology has also been tried as a method for efficiently evaluating the wettability distribution characteristics of shale pore dimensions after CO 2 is acted on. Due to the limitation of testing conditions, a CO 2 -water-oil-rock multiphase system cannot be formed in the nuclear magnetic testing process, and the nuclear magnetic resonance technology is still imperfect in the aspects of CO 2 enhanced oil and gas exploitation and wettability characterization in the geological storage process. Currently there are relatively few methods of measuring wettability of shale reservoirs and each method has its own limitations. The reservoir fluid distribution and fluid phase change after the CO 2 is injected into the shale oil and gas reservoir are complex, so that the overall wettability evaluation difficulty is increased again, and