Introduction

Because CO2 has good effects on injection and oil displacement (Ghasemi et al. 2018; Huang et al. 2016; Di et al. 2011), CO2 flooding has become one of the most effective methods for improving oil recovery in low-permeability reservoirs (Li et al. 2018; Zhou et al. 2018; Shen and James 2018). But research on the CO2-flooding effect in low-permeability reservoirs has been specific to the influencing factors that are easily observable, such as injection speed, injection pressure, number of injected pore volumes (PVs), oil production speed, different components, and various injection modes (Zhao et al. 2018; Chen et al. 2010; Cerasi et al. 2016; Huang et al. 2019; Cui et al. 2018; Zhou et al. 2016). However, for the influencing factors that are difficult to observe, research usually has not included specific analysis (Huang et al. 2018; Tang et al. 2016; Zhou et al. 2017; Wang et al. 2015; Huang et al. 2017), has been less detailed, or has neglected to include capillary pressure and CO2 dissolution.

Capillary pressure shows different functionalities (Abbasi et al. 2018; Shams et al. 2015; Hashmet et al. 2012; Carpenter 2015) under different reservoir properties and displacement modes in the process of CO2 flooding in low-permeability reservoirs. It is generally believed that capillary pressure is powered when the wetting phase drives the nonwetting phase and is resistance when the nonwetting phase drives the wetting phase. However, in the development of CO2 flooding for a low-permeability reservoir, the wetting and nonwetting phases do not drive one another, so the function of capillary pressure is difficult to confirm in the process of CO2 flooding. However, because of the threshold pressure gradient in the seepage of low-permeability reservoirs, the seepage law for this reservoir type is different from conventional and high-permeability reservoirs (Shams et al. 2015; Hashmet et al. 2012). At the same time, production is influenced by capillary pressure during the development of a low-permeability reservoir. Presently, CO2 flooding has various methods (Li et al. 2018; Zhou et al. 2018; Shen and James 2018; Zhao et al. 2018), and there are limited research studies on (or research studies have ignored) the function of capillary pressure in the reservoir development process.

Secondly, because of the physical properties of CO2, its dissolution ability in water is far greater than conventional hydrocarbon. There is always some water or aquifer in low-permeability reservoirs, existing as irreducible water, coexisting water in formation, edge water, or bottom water, and generally the water volume is much larger than the oil volume. There may be a high amount of CO2 dissolving in formation water when CO2 is injected into the reservoir, which then impacts the effect of the flooding. At present, scholars have performed plenty of research on CO2 dissolved in many kinds of fluids during the process of flooding (Dara et al. 2017; Zhou et al. 2018, 2019, 2020a, b; Nanta et al. 2017; Tsakiroglou et al. 2013; Shimokawara et al. 2017; Tham 2015; Feser and Gupta 2018), including the following: (1) the solubility of CO2 in formation water increases with increasing pressure and decreases with increasing temperature. The solubility of CO2 is slightly affected by pressure and temperature when it reaches certain temperature and pressure conditions. (2) Relative permeability is influenced by dissolution in the process of CO2 flooding. The oil flow is useful as CO2 properties, with results including enhanced oil-phase flow and reduced water flow, which reduce residual oil saturation and enhance oil recovery. (3) Factors exist that influence the flooding effect when considering CO2 dissolution in fluids. The higher the water saturation, the greater the influence on oil flooding. All previous research has shown that CO2 dissolution impacts flooding effect, but specific studies on the degree of influence of CO2 dissolution and different flooding modes are few, and it has not been made clear how the oil displacement effect impacts CO2 dissolution under different flooding modes.

Therefore, based on different CO2-flooding modes in long-core laboratory experiments, the research object of this paper is the functions of capillary pressure and CO2 dissolution in the CO2-flooding process in low-permeability reservoirs, and the research method combines laboratory experimentation with numerical simulation to analyze the results. Firstly, the authors carried out long-core laboratory experiments in different CO2-flooding modes. Secondly, researchers established a one-dimensional (1D) numerical simulation model for CO2 flooding based on laboratory experiments and analysis and matching of the production process to determine the related properties. Then, the functions of capillary pressure and CO2 dissolution were analyzed in different flooding modes by numerical simulation. The results show that the functions of capillary pressure and CO2 dissolution in different flooding modes are inconsistent in low-permeability reservoirs: (1) Capillary pressure is a driving force in the process of CO2 flooding and serves as a resistance force in the CO2-flooding process after pressure recovery. (2) Compared with not considering CO2 dissolution in CO2 flooding, oil recovery is reduced in the CO2-flooding process and is increased in the CO2-flooding process after pressure recovery.

Experiment

Experimental materials and setup

Using long-core laboratory experiments to perform CO2-flooding experiments, 22 cores were selected from a low-permeability reservoir, with a total length of 973.44 mm, a harmonic average permeability of 2.261 mD, an average diameter of 25.39 mm, and a total pore volume of 45.01 cm3. Each core was arranged according to the BRA law. The fluid composition used in the experiment is shown in Table 1, with a gas–oil ratio of 67.2 m3/t, a degassing oil molecular weight of 294.92 g/mol, and a degassing oil density of 0.858 g/mL at 20 °C. The experimental equipment mainly included a corrosion-resistant core clamp, high-pressure physical apparatus, high-pressure matching device, high-pressure metering pump, constant-temperature box, oil–gas separator, gas flowmeter, high-pressure drop ball viscometer, etc. (the temperature range was 20 to 200 °C with an accuracy of 0.1 °C, and the pressure range was 0.1 to 70 MPa with an accuracy of 0.01 MPa). The experimental process is shown in Fig. 1.

Table 1 Fluid composition of experiment
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Fig. 1
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CO2-flooding experimental device

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Experimental procedure

  1. 1.

    Firstly, the cores were installed according to the core sequence, the core system was vacuumed, and the saturated core was injected into the formation water. The saturation time was determined by the difference between the saturation volume and the pore volume. The saturation was recorded at the experimental temperature, and the pressure was steadied when the cores were fully saturated.

  2. 2.

    Because of the high viscosity of saturated crude oil, low viscosity of water, and low formation permeability, in order to establish the distribution of the initial oil and water in the formation, the saturated oil was used in the experiment to flood water in the long core.

  3. 3.

    The long-core flooding experiments were carried out under the conditions of formation temperature and pressure.

  4. 4.

    During the experiment, the displacement time, pump reading, injection pressure, injection speed, ring pressure, and back pressure were recorded, and the oil, gas, and water were monitored after separating. In order to test the start-up pressure of low-permeability reservoirs, the PV was recorded starting with the first drop of oil.

  5. 5.

    The cores were cleaned after each experiment, first with petroleum ether and then anhydrous alcohol. Then, the core was blown with nitrogen and dried.

  6. 6.

    Steps 1 and 2 were repeated to carry on the next group experiments after the formation of the original state.

Experimental scheme

Two groups of experiments were set up; the core parameters are shown in Table 2. Experiment 1 was a flooding experiment, with an injection gas pressure of 12.9 MPa, an injection gas of CO2, and an injection speed of 0.5 mL/min; the output end maintained the open state during the experiment. Experiment 2 was a pressure-recovery flooding experiment. The core was injected with CO2 at a certain gas injection rate until the core was pressed to 20 MPa before the experiment, and then the CO2 injection rate of 0.5 mL/min was injected into the core, and the oil recovery process was carried out by CO2 flooding.

Table 2 Core parameters of experiment
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Analysis of experimental results

Experiment 1

In the CO2-flooding experiment, the injection well was injected with CO2 gas into the core at a speed of 0.5 mL/min, and the oil production rate curve and cumulative oil production curve were produced (see Fig. 2). Oil production rate rose rapidly in the early stage of gas injection and hit a peak of 0.293 g/min when the experiment time was at 55 min. At the experiment time of 240 min, the oil production rate fell to less than 0.001 g/min; the experiment showed negligible increase in oil production. After 600 min, the oil production rate was basically 0 g/min. The accumulation of oil production tended to be constant; cumulative oil production was 10.73 g, and recovery degree was 38.96% at 600 min. Finally, cumulative oil production was 10.85 g and recovery degree was 39.41%. Generally, oil production was mainly concentrated in the early stage in the CO2-flooding experiment.

Fig. 2
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Production rate and cumulative oil production curves in the CO2-flooding experiment

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Experiment 2

In the pressure-recovery flooding experiment, the core pressure was restored to 20 MPa in the pressure-recovery stage, the injection well was injected with CO2 gas into the core at a speed of 0.5 mL/min, and the bottom pressure of the production well was maintained at 20 MPa; Fig. 3 shows the oil production rate curve and the cumulative oil production curve. The experimental results showed the following: (1) at 442 min into the pressure-recovery process, the model pressure rose to 20 MPa. (2) After the production well opened, CO2 gas slowly advanced to the bottom of the production well at the beginning of the 50-min point because the difference in production pressure had not been established; the production well did not have oil, and after the well was open for 50 min, the difference in production pressure was established between the injection and the production wells, at which point oil was the product in the production well. (3) Because of the CO2 gas being saturated in the fluid of the core in the pressure-recovery process, the oil production rate reached its peak (0.382 g/min) immediately after the well went into oil production. (4) After the CO2 gas broke through the injection and production wells, the oil production rate curve rapidly decreased without a change in trend because the oil production mainly came from a condensate of hydrocarbon components brought out by CO2; cumulative oil production was 13.161 g, and recovery degree was 48.09%. Finally, the cumulative oil production was 13.64 g, and recovery degree was 49.85%. In general, during the CO2 pressure-recovery flooding experiment, oil production was mainly concentrated in the early stage of the production well opening after pressure recovery.

Fig. 3
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Production rate and cumulative oil production curves in the CO2 pressure-recovery flooding experiment

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Analysis of the functions of capillary pressure and dissolution in different CO2-flooding modes

Numerical simulation model

Based on the two groups of long-core experiments, a 1D three-phase (oil/gas/water) component model was established in numerical simulation, and the component model in the reservoir simulation software was brought into the simulation. Each core was divided into five grids on average, and the 1D models had 110 grids in numerical simulation. Among them, the injection well was located in the first grid to represent the injection port, and the production well was located in the 110th grid to represent the production port. Firstly, the two groups of experiments were matched (see Figs. 4, 5). Meanwhile, a numerical simulation model was established considering CO2 dissolution, and then calculation and analysis were carried out to obtain the oil displacement effect under the different conditions of capillary pressure and CO2 dissolution.

Fig. 4
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Cumulative production match curves in CO2-flooding experiment

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Fig. 5
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Cumulative production match curves in CO2-flooding experiment after pressure recovery

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Analysis of the function of capillary pressure in different CO2-flooding modes

The function of capillary pressure in the CO2-flooding process

Based on the good match and the other physical parameters remaining unchanged in the experiment, two conditions were found with which to analyze the function of capillary pressure in the CO2-flooding process through numerical simulation: increase in capillary pressure and decrease in capillary pressure (see Fig. 6). The results showed that the higher the capillary pressure, the higher the cumulative oil production and recovery degree—the capillary pressure being a driving force in the process of CO2 flooding.

Fig. 6
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Capillary pressure curve for different schemes (experiment 1)

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The capillary pressure increased two times, and the valve pressure of the core changed slightly, but the peak pressure decreased from 13.77 to 13.61 MPa, and the corresponding peak time of arrival decreased from 81 to 71 min (see Table 3 and Fig. 7). The time to oil production decreased, and the peak time decreased from 67 to 55 min, increasing cumulative oil production and recovery degree (see Table 2 and Fig. 8). Increasing the capillary pressure decreased the resistance of CO2 into the core, decreased the pressure peak, and decreased the energy loss, leading to increased injection power of CO2, increased contact area and degree of dissolution between CO2 and oil, increased flooding speed in the core, and increased displacement efficiency. In general, capillary pressure showed a significant impact in this experiment.

Table 3 Capillary pressure function parameters in the CO2-flooding process
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Fig. 7
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Injection pressure curve under different capillary pressures (experiment 1)

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Fig. 8
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Oil production rate curve under different capillary pressures (experiment 1)

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The capillary pressure decreased 0.25 times, the valve pressure of the core increased from 13.28 to 13.35 MPa, the peak pressure increased from 13.77 to 14.27 MPa, and the corresponding time-of-arrival peak increased from 81 to 100 min (see Table 2 and Fig. 7). The time to oil production increased, the peak production rate decreased from 0.30 to 0.249 g/min in the production process, and the peak time increased from 67 to 90 min (see Table 2 and Fig. 8). Decreasing the capillary pressure increased the resistance of CO2 into the core, increased the valve pressure, increased the pressure peak, and increased the energy loss, leading to decreased injection power of CO2 and decreased contact area and degree of dissolution. As for the relationship between CO2 and oil, wave area decreased, as did displacement efficiency, cumulative oil production, and recovery degree. Capillary pressure was further proved to be a driving force in this experiment.

The function of capillary pressure in the CO2 pressure-recovery flooding process

Based on the good match and the other physical parameters remaining unchanged in the experiment, two conditions were found with which to analyze the function of capillary pressure in the CO2 pressure-recovery flooding process through numerical simulation: increase in capillary pressure and decrease in capillary pressure (see Fig. 9). The results showed that the higher the capillary pressure, the lower the cumulative oil production and recovery degree; the capillary pressure was shown to resist the process of CO2 pressure-recovery flooding.

Fig. 9
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Capillary pressure curve for different schemes (experiment 2)

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The capillary pressure increased five times, the effect was low on production and injection pressure, the peak time remained basically the same, and the cumulative oil production and recovery degree decreased slightly (see Table 3, Figs. 10, 11). Increasing the capillary pressure increased energy loss, leading to decreased CO2 injection power, decreased contact area and degree of dissolution between CO2 and oil, decreased wave area, and decreased displacement efficiency. In general, capillary pressure expressed resistance in this experiment.

Fig. 10
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Injection pressure curve under different capillary pressures (experiment 2)

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Fig. 11
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Oil production rate curve under different capillary pressures (experiment 2)

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The capillary pressure decreased 0.25 times, there was low effect on production and injection pressure, and cumulative oil production and recovery degree rose slightly (see Table 4, Figs. 10, 11). Capillary pressure was further proved to be resistant in this experiment.

Table 4 Capillary pressure function parameters in the CO2 pressure-recovery flooding process
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Analysis of the function of dissolution in different CO2-flooding modes

The function of dissolution in the CO2-flooding process

Based on the good match and the other physical parameters remaining unchanged in the experiment, two conditions were found with which to analyze the function of dissolution in the CO2-flooding process through numerical simulation: considering CO2 dissolution and not considering CO2 dissolution (see Table 5 and Figs. 12, 13, 14). The results showed that when comparing consideration and nonconsideration of CO2 dissolution, the peak production rate decreased from 0.30 to 0.265 g/min, and the peak time slowed slightly. The peak pressure decreased from 13.78 to 13.61 MPa, cumulative oil production decreased from 10.85 to 10.38 g, and recovery degree decreased from 39.41 to 37.72%. When CO2 dissolution was considered during the flooding process, CO2 gas was used to saturate fluids in the model at the start, thus delaying the flooding process, reducing the production pressure difference, expanding the breakthrough time, and decreasing the peak production rate, leading to reduced efficiency of displacement crude oil in this experiment.

Table 5 Dissolution function parameters in the CO2-flooding process
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Fig. 12
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Oil production rate curve contrasting dissolution and no dissolution (experiment 1)

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Fig. 13
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Injection pressure curve contrasting dissolution and no dissolution (experiment 1)

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Fig. 14
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Cumulative oil production curve contrasting dissolution and no dissolution (experiment 1)

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The function of dissolution in the CO2 pressure-recovery flooding process

Based on the good match and the other physical parameters remaining unchanged in the experiment, two conditions were found with which to analyze the function of dissolution in the CO2 pressure-recovery flooding process through numerical simulation: considering CO2 dissolution and not considering CO2 dissolution (see Table 6 and Figs. 15, 16, 17). The results showed that when comparing the consideration and nonconsideration of CO2 dissolution, peak production rate increased from 0.390 to 0.415 g/min, peak pressure increased from 22.09 to 22.19 MPa, cumulative oil production increased from 13.64 to 14.07 g, and recovery degree increased from 49.85 to 51.40%. When CO2 dissolution was considered during the pressure-recovery flooding process, the fluid was saturated with CO2 in the model at the stage of pressure recovery, and CO2 gas was completely used for displacement at the stage of flooding. At the same time, when the pressure dropped, CO2 precipitated from the saturated fluid and took part in the flooding, increasing the production pressure difference and the oil production rate, leading to increased efficiency of displacement crude oil in this experiment.

Table 6 Dissolution function parameters in the CO2 pressure-recovery flooding process
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Fig. 15
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Oil production rate curve contrasting dissolution and no dissolution (experiment 2)

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Fig. 16
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Injection pressure curve contrasting dissolution and no dissolution (experiment 2)

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Fig. 17
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Cumulative oil production curve contrasting dissolution and no dissolution (experiment 2)

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Conclusions

  1. 1.

    In the CO2-flooding experiments, the effect of pressure-recovery flooding was shown to be better than direct flooding, with recovery increasing from 39.41 to 49.85%, an increase of 10.445%. The main reason behind this result is that pressure rise is limited during flooding experimentation. Meanwhile, pressure is higher in the process of pressure recovery, close to the minimum miscibility pressure and near-miscible drive.

  2. 2.

    In low-permeability reservoirs, capillary pressure is a driving force in the process of CO2 flooding. When capillary pressure is reduced 0.25 times, recovery is reduced by 0.92%. Capillary pressure is resistant in the CO2-flooding process after pressure recovery. When capillary pressure is reduced 0.25 times, recovery is increased by 0.31%.

  3. 3.

    In low-permeability reservoirs, dissolution leads to decreased displacement efficiency in the CO2-flooding process, with recovery reduced by 1.69%. Dissolution leads to increased displacement efficiency in the CO2 pressure-recovery flooding process, with recovery increased by 1.55%.

  4. 4.

    Capillary pressure and dissolution affect the production of low-permeability reservoirs and cannot be ignored in field development, as shown by the only theoretical response of capillary pressure and dissolution in the numerical simulation presented in this study. Later studies could suggest the microscopic functions of capillary pressure and dissolution by physical experimentation to demonstrate the mechanism of action and to establish the related models.