1. Introduction
The storage of CO
2 in oil and gas reservoirs is the best among the various methods of CO
2 storage. Although the theoretical storage amount is small, oil and gas reservoirs are the preferred sites for underground CO
2 storage from the perspective of economy and safety [
1,
2]. An oil reservoir is a closed environment with a high temperature and high pressure, and it contains crude oil and formation water. The properties of the rock in an underground reservoir are completely different from those of rocks found aboveground. After the injection of CO
2, the temperature and pressure of the formation gradually return to their initial state, and the interaction between the CO
2, crude oil, and formation water also rebalance [
3,
4]. After CO
2 is injected into the formation, some will displace the space in the reservoir originally occupied by the oil and water, and some will be dissolved in the residual oil and formation water. New minerals are generated by geochemical reactions between the CO
2 and the rock. Due to the multiphase flow of oil and gas/water in the capillaries of porous media, some of the CO
2 is confined in the pores and cannot flow in its bound state, while the rest of the undissolved CO
2 exists in a free state [
5]. In addition, the static parameters and injection parameters of the CO
2 in the CCUS (Carbon Capture, Utilization, and Storage) project affect the final storage capacity and storage state of the CO
2 [
6,
7,
8].
Detailed laboratory studies on the physical properties of CO
2–crude oil systems and CO
2–formation water systems have been carried out by many scholars at home and abroad. The effects of different temperatures and pressures on the solubility and diffusion coefficient of CO
2 in oil/water have been measured through laboratory experiments [
9,
10,
11,
12,
13]. The ability of CO
2 to dissolve in oil/water after injection into a reservoir has significance for the study of the laws affecting the storage of CO
2 in reservoirs. The law governing the erosion of CO
2 in heavy oil systems was studied in detail by Miller and Jones using dehydrated and degassed heavy oil from three different oilfields in the eastern United States [
14]. Experimental temperatures of 25 °C, 50 °C, and 90 °C were selected, and the experimental pressure range was 1.5~36 MPa. When the experimental temperature was 25 °C, the CO
2 solubility curve had an inflection point at its saturation pressure. After exceeding the saturation pressure, the physical properties of the CO
2 changed. The diffusion coefficient determines the erosion rate and diffusion efficiency of CO
2 in reservoir fluid and ultimately affects the spread range and storage rate of CO
2 as well as the crude oil recovery. Therefore, it is very important to establish a diffusion mass transfer model using molecular diffusion and to study the diffusion law of CO
2 in its liquid phase. A physical model of the diffusion of CO
2 into its liquid phase using a constant-volume PVT cell was constructed by Riazi [
15]. The pressure change–time function and the liquid level position–time function were linked with the diffusion coefficient by Riazi. The diffusion coefficient was obtained by determining the change in the gas–liquid boundary position with time and the change in pressure with time at a constant temperature. This method was used to obtain measurements from a methane–pentane system at 311 K and 7 MPa, and the corresponding data errors were all below 5%.
After CO
2 is injected into a formation, some of the CO
2 is retained in the formation water in a dissolved state, and the rest of the CO
2 produces an acidic liquid with the formation water which corrodes the rock minerals. CO
2 is consumed via the mineralization reaction. New secondary minerals are generated and stored in the formation or extracted with the fluid. The CO
2–water–rock interactions play a role in the storage of CO
2, that is, mineralized storage [
16,
17,
18]. The erosion reaction between CO
2 and albite was studied by Ryzhenko et al. at different temperatures [
19]. Their results showed that the degree to which the albite eroded intensified as the temperature increased, and dawsonite was formed at 150 °C. lzgec et al. [
20] evaluated the influence of CO
2 injection pressure, reservoir temperature, and formation water salinity on the chemical equilibrium of carbonate rocks and feldspar minerals as well as the variability of porosity and permeability parameters by means of various laboratory experiments. According to their experimental data, the permeability and porosity trends were basically the same when the temperature was between 20 °C and 60 °C. When the CO
2 injection pressure was 2.0 MPa, the permeability decreased by 58.4%.
Some research into methods for improving CO
2 storage rates during dynamic flooding has been carried out by experts and scholars at home and abroad in recent years [
21,
22,
23,
24]. Numerical simulation software was used by Yao et al. [
25] to study the influences of reservoir porosity, permeability parameters, fluid properties, and injection methods on CO
2 flooding/storage. By analyzing the retention ratio of CO
2 and the recovery degree of crude oil, insight into the influences of these different factors on the storage rate and recovery rate of CO
2 flooding was obtained.
The purpose of this paper is to systematically study the static parameters and the dynamic parameters of CO2 after it is injected into reservoirs through various macro and micro means, including ICP (ion chromatography), XRD (X-ray diffraction), SEM (scanning electron microscopy), NMR (nuclear magnetic resonance), static erosion, and core flooding. In addition, the interactions between CO2, crude oil, formation water, and the rock surface after the CO2 entered the formation was also analyzed to assist in the analysis of the internal mechanisms and the potential of CO2 storage in reservoirs. This will provide a theoretical basis for the design of CO2 flooding/storage sites.
4. Conclusions
In this study, the static and dynamic parameters of CO2 after being injected into a reservoir were systematically studied using various macro and micro methods. The interaction between CO2, formation water, and the rock surface as well as the mechanism by which this interaction influences CO2 storage were also studied in this paper. The main conclusions are as follows:
(1) The variation in the solubility of CO2 in crude oil with pressure is similar to that in formation water. The solubility of CO2 increases as the pressure increases under low-pressure conditions. As the temperature increases, the viscosity of crude oil decreases significantly, and the solubility of CO2 is significantly increased in low-viscosity crude oil.
(2) The ability of crude oil to accommodate CO2 can be improved; it is easier for CO2 to diffuse into the oil phase at a high temperature. More resistance is encountered when CO2 diffuses into the liquid-containing space of the irregular core, causing the coefficient of diffusion into the oil–water two-phase flow in the porous medium to become smaller.
(3) Because CO2–water has a certain erosion effect on albite and potassium feldspar, the Na+ and K+ content increased as the erosion time increased. The change trend of the Ca2+ concentration was roughly consistent with that of the Na+ and K+. The quartz content in the mineral component increased and the plagioclase and potassium feldspar content significantly decreased due to the erosion reaction with CO2. The dissolution of the feldspar led to the formation of a large amount of secondary kaolinite, causing the kaolinite content to increase.
(4) In the early stage of erosion by CO2 during the dynamic flooding, the core permeability and porosity increased slowly. As the erosion progressed, the degree of influence of particle migration on the permeability and porosity of the cores gradually decreased while the influence of inorganic precipitation increased. The secondary pores played a role during the flooding, causing the permeability and porosity of cores to gradually increase.
(5) The percentages of free and irreducible storage, mineralized storage, and dissolved storage were 60.6%, 27.9%, and 11.5%, respectively. CO2 is mainly stored in a free and irreducible state in the reservoir. Some of the CO2 participates in the erosion reaction and is stored in the rock or solution in mineralized form or as ions. In addition, a small portion of the CO2 is dissolved in the residual water and oil after CO2 flooding.