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. 2025 Feb 18;10(8):8042–8051. doi: 10.1021/acsomega.4c09107

Density Measurement and Prediction Model of the CO2–Water-Bearing Crude Oil System

Menglan Li 1, Yingzhu Guan 1,*, Weiqi Wang 1
PMCID: PMC11886716  PMID: 40060828

Abstract

graphic file with name ao4c09107_0008.jpg

Accurately predicting the density variation trend of water-bearing crude oil in high-CO2-concentration production wells is of great significance for forecasting wellbore fluid flow dynamics and designing lifting processes at different stages of development. Indoor experiments were conducted on the CO2–water-bearing crude oil system, measuring the crude oil density under various conditions of temperature, pressure, CO2 concentration, and water cut. The study explored the behavior of crude oil density under different working conditions, and a predictive model for high-CO2-concentration water-bearing crude oil density was developed using multiple regression analysis. The results indicate that under a certain water-cut condition, when the CO2 content is below 50%, the density of the mixed fluid increases with rising pressure. However, when the CO2 content exceeds 50%, the density first decreases and then increases as the pressure continues to rise. Under the same CO2 injection volume, the density of the mixed fluid decreases with increasing temperature, and compared to the pressure, the density is more sensitive to temperature changes. Under the same temperature and pressure conditions, the density of the mixed fluid decreases with increasing the CO2 injection volume but increases with higher water content. The new predictive model for the density of the CO2–water-bearing crude oil system, accounting for the combined influence of multiple factors, has an average error of just 3.16%, meeting the precision requirements for engineering calculations. This model offers valuable theoretical guidance for CO2 flooding development in similar high-water-cut reservoirs.

1. Introduction

Within the framework of the “dual carbon” strategy, which aims to peak carbon emissions by 2030 and achieve carbon neutrality by 2060 in China, CCUS technology presents a transformative opportunity for the petroleum industry; moreover, CCUS aligns with global efforts to promote greener and more sustainable energy production.1−5 For many years, water injection has been the predominant method in oilfield development, particularly as a secondary recovery technique used to maintain the reservoir pressure and displace oil. This method has been widely applied globally, including in China’s eastern region, where many mature oilfields have now entered the mid-to-high water-cut stage. At this point, the water flooding efficiency significantly declines, limiting further improvements in oil recovery. As a result, conventional water injection has reached its practical limits in these aging fields, creating a pressing need for new solutions to sustain production levels and maximize recovery rates. One of the most promising technologies addressing this challenge is CO2 flooding.6,7 This advanced technique has garnered significant attention for its ability to achieve two crucial objectives: enhancing oil recovery and reducing carbon emissions.

CO2 flooding has emerged as an important enhanced oil recovery (EOR) method, offering several key advantages over traditional water flooding and other gas injection methods.8−11 Unlike conventional water flooding, not only does it act as an effective displacement agent but it also requires lower injection pressures due to its unique physical properties, making it easier to inject into the reservoir. CO2 has a higher injectivity compared to other gases, enabling more efficient displacement of oil within the reservoir.12−15 Additionally, under specific temperature and pressure conditions, CO2 can become miscible with crude oil. This miscibility causes the oil to expand, increasing its volume and reducing its viscosity, allowing the oil to flow more easily through reservoir rocks.16−18 Moreover, CO2 enhances the surface activity of the oil, helping to lower the interfacial tension between the oil and water. This reduction in interfacial tension facilitates the more efficient movement of oil droplets, which would otherwise remain trapped in the reservoir’s pores.19,20 Beyond these benefits, CO2 injection also improves the overall permeability of the reservoir, enhancing fluid flow through the rock formation and prolonging the exploitation life of highly water-containing oil reservoirs.21,22 However, during the late production stage of CO2 flooding in reservoirs, CO2 is often produced along with the associated gas.23,24 The significant presence of CO2 in the production stream leads to continuous variations in the density of the crude oil, complicating the prediction of wellbore pressure changes and making it challenging to maintain optimal production rates and efficiently manage the lifting process.25−28

Therefore, it is essential to study the rules governing density variations in high CO2–water-bearing crude oil systems. Standing et al.29 developed a model for calculating the density of saturated crude oil, taking into account factors such as temperature, dissolved gas–oil ratio, the relative density of degassed crude oil, and the relative density of gas. Quail et al.30 proposed a method for calculating the density of the CO2-crude oil system based on heavy oil characterization tests, considering the effects of CO2 and CH4 concentrations. Xue et al.31 derived a theoretical relationship between the density of dissolved gas crude oil and the molar solubility of CO2, temperature, and gas–oil ratio. Wang et al.32 established the relationship between density and solubility in saturated CO2 oil and water systems by fitting experimental data at 45 °C and high pressure. Wu et al.33 conducted gas injection and expansion experiments on ultraheavy oil in the Zheng 411 block, developing a model that correlates the density of ultraheavy oil with CO2 injection, temperature, and pressure. Based on Quail’s model, Yang et al.34 created a crude oil density prediction model that considers CO2 injection and water content, suitable for low CO2 concentration conditions. Comprehensive literature review reveals that (1) most existing density prediction models focus on heavy and ultraheavy oils and are not applicable to medium oil reservoirs, neglecting the effects of CO2 injection and water content on crude oil density; and (2) the accuracy of existing models in predicting the density of high CO2–water-bearing crude oil is low, leading to inaccuracies in wellbore pressure predictions. This highlights the need for improved models to enhance prediction precision in such systems.

In this paper, Well X from the XJ Oilfield, with a comprehensive water cutoff of 81.3%, is used as a case study. A laboratory experiment was designed to measure the density of the CO2–water-bearing crude oil system under various conditions of temperature, pressure, CO2 content, and water cut. The study explores the variation patterns of crude oil density in different scenarios. Based on the experimental results and a comparative error analysis with existing models, a new prediction model for the density of CO2–water-bearing crude oil is developed. This model incorporates a broader range of influencing factors, offers greater accuracy, and has wider applicability. The findings provide valuable insights for the efficient and rational development of oil reservoirs with similar high CO2–water-bearing characteristics.

2. Experimental Methods and Procedures

2.1. Experimental Materials

The experimental fluid is composed of three parts: degassed crude oil from the X well in the XJ oilfield, formation water separated from oil and water, and natural gas blended according to the flash vapor composition. The fluid properties are consistent with those of a light crude oil. Specifically, the degassed crude oil has a density of 0.865 g/cm3 and a viscosity of 24.9 mPa·s at 50 °C. The formation water has a total salinity of 13,978 mg/L, the initial gas–oil ratio is 121 m3/t, and the CO2 sample purity is 99.999%. The main components of the flash vapor are given in Table 1.

Table 1. Molar Composition of Flash Vapor Components in Well X.

component C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 N2 CO2 sum
mole fraction (%) 82.92 7.37 4.81 1.42 1.02 0.02 0.21 0.04 0.03 0.03 1.96 0.17 100
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2.2. Experimental Instruments

The equipment used in this experiment mainly includes a PY-2 high-temperature and high-pressure sampler, whose maximum pressure is 100 MPa and maximum temperature is 200 °C; a BY100-II high-pressure displacement pump, whose maximum pump pressure is 100 MPa and flow rate range is 0.001–30 mL/min; a QL-I gas meter; a BSA423 electronic balance; a densitometer; an oil-gas chromatograph; and so on, as shown in Figure 1.

Figure 1.

Figure 1

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Experimental procedure diagram.

2.3. Experimental Procedure

2.3.1. Experimental Scheme

According to the reservoir temperature and pressure conditions of X wells in the XJ oilfield, the density of the CO2–water-bearing crude oil system was determined under the conditions of temperature and pressure variations ranging from 35 to 95 °C and 3 to 28 MPa, respectively, and the experimental scheme is shown in Table 2.

Table 2. Density Determination Program for CO2–Water-Bearing Crude Oil Systems.
parameter value
temperature (°C) 20, 40, 60, 80, 95
pressure (MPa) 5, 8, 10, 12, 15
water cut (%) 20, 60, 90
CO2 content (%) 20, 40, 60, 90
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2.3.2. Experimental Steps

The density determination experiment of the CO2–water-containing crude oil system is mainly completed by the following five steps, and the experimental flow is shown in Figure 1.

Step 1: according to the flash vapor (Table 1) and the original gas–oil ratio, the volume of C1 ∼ C4, CO2, and N2 required to formulate a certain amount of stratum crude oil is calculated, the actual volume of each gas required into the intermediate container is injected according to the order of the cylinder pressure size in order, and then it is pressurized to 20 MPa for spare parts, and the natural gas reformulation is completed.

Step 2: according to the components of crude oil and flash vapor, the volume of liquid C5H12, C6H14, C7H16, and C8H18 required is calculated, liquid hydrocarbons are injected into the high-temperature and high-pressure sampler equipped with crude oil under the experimental temperature and pressure in sequence, then the stratum water obtained by oil–water separation is injected into the sampler proportionally according to the requirement of water content, and finally the reconstituted natural gas is injected into the sampler with 2–3 h shaking until gas and liquid are mixed evenly and it is left to stand, and the reconstitution of stratum crude oil is completed.

Step 3: a certain content of CO2 gas is injected into the crude oil of the stratum after compounding, the CO2 content is based on the requirements of the measurement program, the pressure in the sampler is kept at 15 MPa, and it is shaken for 1 h until the gas is fully dissolved and then left until the pressure is constant.

Step 4: the densitometer is installed, the sampler valve is opened until crude oil appears, and then the corresponding density value after the crude oil fills the densitometer is calculated. The pressure of the sampler is reduced to the next experimental pressure, and the above steps are repeated until the set of experiments is completed.

Step 5: the CO2 content, water content, and temperature are changed sequentially as required, and steps 1–4 are repeated until all test sets are complete.

3. Results and Discussion

3.1. Effect of Pressure on the Density of the CO2–Water-Bearing Crude Oil System

Figure 2 shows the variation in mixed fluid density at a water cut of 60% under different CO2 concentrations (20%, 40%, 60%, and 90%). From Figure 2, it can be observed that when the CO2 concentration is below 50%, the density of the mixed fluid increases with rising pressure. However, when the CO2 concentration exceeds 50%, the density first decreases and then increases as the pressure rises.

Figure 2.

Figure 2

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Effect of pressure on the density of the CO2–water-bearing crude oil system.

As shown in Figure 2a,b, when the CO2 concentration is below 50%, the increase in the pressure results in a more pronounced rise in the mixed fluid density, with the curve exhibiting an upward trend. This is because as pressure increases, the molecular spacing between the crude oil components is compressed, causing the molecules to pack more tightly. As a result, it becomes more difficult for CO2 to dissolve into crude oil, leading to less expansion of the crude oil volume and an eventual decrease in volume. Consequently, the density of the CO2–water-bearing crude oil system increases with rising pressure.

In contrast, as shown in Figure 2c,d, when the CO2 concentration is above 50%, the density behavior changes. When the pressure is below the saturation point, the volume of CO2 dissolved in the crude oil increases with rising pressure, increasing the kinetic energy within the oil, expanding the molecular spacing, and increasing the oil’s volume factor, which leads to a reduction in density. However, when the pressure exceeds the saturation point, a large amount of CO2 accumulates in the oil. As pressure continues to rise, less CO2 dissolves in the oil, or it ceases dissolving altogether, causing the density of the CO2 to increase. Simultaneously, crude oil undergoes elastic compression. The combined compressibility of both the CO2 and crude oil leads to an increase in the mixed fluid density. In summary, when the CO2 concentration is higher than 50%, the density of the CO2–water-bearing crude oil system first decreases and then increases with rising pressure.

3.2. Effect of Temperature on the Density of the CO2–Water-Bearing Crude Oil System

Figure 3 illustrates the variation in mixed fluid density at a water cut of 60% under different CO2 concentrations (20%, 40%, 60%, and 90%). It can be observed that under the same water cut, pressure, and CO2 concentration, the mixed fluid density decreases significantly as the temperature increases.

Figure 3.

Figure 3

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Effect of temperature on the density of the CO2–water-bearing crude oil systems.

In Figure 3, the downward trend of the curves is quite evident. For every 15–20 °C increase in temperature, the density decreases by an average of 0.52 g/cm3. This shows that, under the same water cut and CO2 concentration, the temperature has a more pronounced effect on the mixed fluid density compared to pressure. The reason for this is that as the temperature rises, molecular thermal motion intensifies, increasing the kinetic energy of the molecules and weakening the intermolecular forces. This results in an increase in the molecular spacing and a higher crude oil expansion coefficient, which leads to an increase in crude oil volume. Additionally, at higher temperatures, the gas–liquid interface becomes less stable, causing greater fluctuations in dynamic interfacial tension and an increase in equilibrium interfacial tension.18 Both CO2 molecules in the fluid and light hydrocarbon molecules in the crude oil tend to vaporize at higher temperatures,19 which further reduces the density of the mixed fluid.

In Figure 3c,d, there is an unusual variation in the curves where the density at 5 MPa is higher than that at 8 MPa. This occurs because, under CO2 concentrations not exceeding 60%, when the pressure is below the saturation pressure, the amount of CO2 dissolved in the crude oil increases with rising pressure, causing the crude oil to expand and its density to decrease. However, when the pressure exceeds the saturation point, the combined compressibility of both CO2 and crude oil leads to an increase in density as the pressure continues to rise. In summary, the mixed fluid density first decreases and then increases with rising pressure, which explains the observed curve variation.

3.3. Effect of CO2 Content on the Density of the CO2–Water-Bearing Crude Oil System

Figure 4 illustrates the variation in the density of the mixed fluid at a water cut of 60% under different temperatures (20, 40, 60, 80, and 95 °C). It can be observed that under the same water cut, temperature, and pressure conditions, the density of the mixed fluid decreases with an increase in CO2 injection.

Figure 4.

Figure 4

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Effect of CO2 content on the density of the CO2–water-bearing crude oil systems.

This occurs because, under reservoir conditions, CO2 exists in a supercritical state, exhibiting a high density and liquidlike properties, making it easily soluble in crude oil and slightly soluble in water. As CO2 injection increases, the amount of CO2 dissolved in crude oil rises, and the CO2 dissolved in water diffuses into the oil phase, reducing the interfacial tension between the oil and water.35 CO2 molecules enter the oil phase, causing swelling, which increases the intermolecular distance and reduces the molecular forces, leading to a noticeable expansion in the crude oil volume. As more CO2 dissolves into the crude oil, it extracts the lighter components of the oil,36 enriching the gas phase by vaporizing the lighter hydrocarbons first and then the heavier ones. This process lowers the oil–gas interfacial tension. The enriched CO2 further extracts and vaporizes heavier hydrocarbons from the crude oil, continuing this cycle until the CO2-rich phase becomes miscible with the oil, reducing the relative density of the crude oil. Thus, the density of the CO2–water-bearing crude oil system decreases with increased level of CO2 injection.

In Figure 4, when the pressure is 5 MPa and the CO2 content exceeds 50%, an intersection in the density variation curve is observed. This phenomenon is similar to the anomaly seen in the temperature-related analysis of the CO2–water-bearing crude oil system discussed in Section 3.2.

3.4. Effect of Water Cut on the Density of the CO2–Water-Bearing Crude Oil System

Figure 5 illustrates the variation in the density of the mixed fluid at a temperature of 60 °C and at different CO2 concentrations (20%, 40%, 60%, and 90%). It can be observed that under constant CO2 injection, temperature, and pressure conditions, the density of the mixed fluid increases significantly with the rise in water content.

Figure 5.

Figure 5

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Effect of water content on the density of the CO2–water-bearing crude oil systems.

In Figure 5a, for every 30% increase in the water content, the density rises by 3.15%. The higher the water content, the more pronounced the density increase, indicating a positive linear correlation between the density of the CO2–water-bearing crude oil system and the water content. This occurs because under the same CO2 injection conditions, as the water content increases, the volume of the water phase in the mixed fluid gradually expands. The water phase acts as a barrier, preventing the diffusion of CO2 molecules into crude oil and inhibiting the release of light hydrocarbons into the gas phase. As a result, CO2 cannot directly contact the crude oil, reducing its solubility in the oil phase. Meanwhile, the CO2 content dissolved in the water phase increases, while its content in the oil phase decreases, leading to a reduction in the crude oil expansion coefficient.37 Consequently, the crude oil volume decreases, causing the density of the CO2–water-bearing crude oil system to rise as the water content increases.

3.5. Comparison of Existing Density Prediction Models

The current CO2–crude oil density prediction models primarily include the Standing29 model, the Quail30 model, the Xue Haitao31 model, the Wang Shaopeng32 model, and the Wu Guanghuan33 model. Among these, the Standing model, the Quail model, and the Wu Guanghuan model are the most commonly used for density prediction. The details of these density prediction models are listed in Table 3. To develop a prediction model that fits the conditions of this experiment, we compared the calculated values from these three models with the experimental results. The comparison between the calculated and experimental values is shown in Figure 6. The relative error of this paper is calculated as follows: relative error = |predicted density – experimental density|/experimental density.

Table 3. Density Prediction Model.

model equation annotation
Standing
graphic file with name ao4c09107_m004.jpg
 ρo is the density of crude oil (kg/m3), Rs is the dissolved gas–oil ratio of natural gas in crude oil (m3/m3), γo is the relative density of degassed crude oil, γg is the relative density of natural gas (taking the density of air to be 1 kg/m3), and T is the temperature of the ground layer (°C)
Quail
graphic file with name ao4c09107_m005.jpg
 ρ is the density of the crude oil (g/cm3), T is the temperature (K), [CO2] is the molar fraction of CO2 (mol %), [CH4] is the molar fraction of CH4 (mol %), Ci is model coefficient, as shown in Table 4
Wu Guanghuan
graphic file with name ao4c09107_m006.jpg
 ρo is the density of the crude oil (g/cm3), T is the temperature (°C), x is the CO2 injection rate (%), and p is the pressure (MPa)
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Figure 6.

Figure 6

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Comparison between calculated and measured values of calculation models with different crude oil density prediction models.

Based on the comparison results shown in Figure 6, the models were evaluated using error analysis and mathematical statistics, leading to the following conclusions: Each model considered different influencing factors when established, as shown in Tables 5 and 6, and the degree of alignment with the experimental conditions was relatively low. Additionally, none of the models accounted for the effect of the water content on density, which has a significant impact, particularly in cases of high water content. As a result, all of the models showed large prediction errors. Among the models, the Standing model exhibited the smallest average relative error percentage at 14.39%, as it considered more factors. In contrast, the Quail and Wu Guanghuan models had larger average relative error percentages of 32.91% and 61.74%, respectively. Therefore, this experiment selected the Standing model as the base model for further modification, aiming to develop a more accurate and broadly applicable CO2–water-bearing crude oil density prediction model.

Table 5. Scope of Application of the Crude Oil Density Prediction Model.

  oil properties temperature pressure degassed crude oil viscosity gas–oil ratio
Standing   22.2–144.4 °C ≤57 MPa 0.377–0.5 mPa·s 51–3542 m3/m3
Quail heavy oil   <17 MPa    
Wu Guanghuan ultraheavy oil 0–230 °C ≤60 MPa    
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Table 6. Analysis of the Crude Oil Density Prediction Results of Different Models.

  average relative error analysis of error causes
Standing 14.39% the calculated density values are mostly higher than the experimentally measured values the crude oil in this experiment is unsaturated, differing from Standing model’s optimal conditions, and water content effects on density are not considered
Quail 32.91% the calculated density values are significantly higher than the experimentally measured values the oil used in this experiment is light crude, which is inconsistent with Quail model’s applicable oil type, and the effects of water content and pressure on density are not considered
Wu Guanghuan 61.74% the calculated density values are significantly higher or lower than the experimental values the experimental temperature range of 20–95 °C is below Wu Guanghuan model’s optimal range, the crude oil properties do not match, and the effect of water content on oil density is not considered
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Table 4. Quail Model Correlation Coefficients.

coefficient C1 C2 C3 C4
value 1.1685 6.848 × 10–4 1.495 × 10–4 1.279 × 10–4
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3.6. Modification of the Density Prediction Model for the CO2–Water-Bearing Crude Oil System

An analysis of the standing model shows that crude oil density is influenced by gas solubility, the relative density of degassed crude oil, the relative density of degassed gas, and temperature, while gas solubility is affected by water content, with the CO2 solubility in water-containing crude oil decreasing significantly as water content increases, following a linear negative correlation. This occurs because the water phase hinders direct contact between CO2 and crude oil, reducing the CO2 dissolution capacity and thereby lowering its solubility. As the volume of the CO2 injection increases, the solubility initially rises but then declines. This is because the dissolution of CO2 causes crude oil to swell, which initially reduces its density and enhances its capacity to dissolve CO2. However, when the volume of injected CO2 becomes excessive, the surplus CO2 may form a separate gas phase, limiting its interaction with crude oil and reducing its solubility, as illustrated in Figure 7.

Figure 7.

Figure 7

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Solubility of CO2 in the water-bearing crude oil system.

Combined with the analysis of the experimental results, it was determined that the density of the CO2–water-bearing crude oil system is influenced by temperature, pressure, CO2 concentration, and water content. To enhance the accuracy of the Standing calculation model, two additional variables—water content and pressure—were introduced. In order to account for the effect of water content on solubility, Zhang et al.,38 building on previous research, developed a solubility model for the CO2–water-bearing crude oil system using a weighted average method. Since this model closely matches the experimental conditions of this study, it was selected as the solubility calculation model for the experiment, as shown in eq 1:

3.6. 1

where Rs is the solubility of CO2 in the mixed fluid, and Ro and Rw are the solubility of CO2 in crude oil and formation water, respectively. In summary, the basic form of the modified formula is shown in eq 2:

3.6. 2

where ρo is the crude oil density, kg/m3; γo is the relative density of degassed crude oil; γg is the relative density of gas (taking the air density of 1 kg/m3); Rs is the gas–oil ratio, m3/m3; P is the pressure, MPa; T is the temperature, °C; A, B, C, D, E, and F are all correlation coefficients. A total of 300 groups of data were used in this experiment, from which 100 groups were randomly selected and fitted using multiple regression calculation to obtain a new formula (see Table 7 for the values of the correlation coefficients), and eq 3, which is the formula for calculating the density under the conditions of this experiment, is

3.6. 3

Table 7. New Model Correlation Coefficient.

coefficient A B C D E F
value 50.02254 0.04407 0.40982 0.04569 –0.0077 0.93838
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3.6.1. Model Verification

To validate whether the new model maintains high predictive accuracy under varying conditions of the temperature, pressure, CO2 content, and water content, the remaining 200 sets of experimental data were used for testing. A selection of the calculated results is shown in Table 8. According to the error analysis, the average relative error percentage of density was 3.47% when the water content was 20%, 2.95% at 60%, and 3.05% at 90%, with an overall average relative error of 3.16%. These error values meet the precision requirements for engineering calculations, indicating that the new model fits well with the experimental data. The model can accurately predict the density of the CO2–water-bearing crude oil system at any point in the production well, making it suitable for high water content and high gas–liquid ratio wellbore environments.

Table 8. Calculated Values of Density for the New Model.
water cut (%) CO2 content (%) temperature (°C) pressure (MPa) measured value (g/cm3) new model (g/cm3) relative error (%)
20 20 20 15 0.905 0.839 7.2
    40 5 0.760 0.743 2.1
    60 12 0.758 0.719 5.0
    80 8 0.704 0.662 5.9
    95 10 0.663 0.643 2.9
  40 20 8 0.809 0.814 0.6
    40 5 0.725 0.742 2.3
    60 10 0.727 0.712 1.9
    80 12 0.719 0.675 6.0
    95 15 0.670 0.664 0.8
60 40 40 5 0.745 0.722 2.9
    60 8 0.721 0.722 0.1
    80 10 0.713 0.721 1.1
    95 12 0.637 0.720 7.0
    95 15 0.682 0.725 6.3
  60 20 8 0.803 0.828 3.1
    40 5 0.738 0.750 1.6
    60 12 0.714 0.734 2.8
    80 10 0.675 0.678 0.4
    95 15 0.647 0.674 4.2
90 60 20 15 0.866 0.887 2.4
    40 8 0.752 0.775 3.0
    60 5 0.710 0.702 1.0
    80 10 0.683 0.684 0.2
    95 12 0.641 0.664 3.7
  90 20 8 0.789 0.839 6.3
    40 10 0.771 0.787 2.1
    60 12 0.715 0.743 4.0
    80 5 0.665 0.656 1.2
    95 15 0.639 0.681 6.6
average relative error       3.16%    
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4. Conclusions

The indoor miscibility experiment between CO2 and water-cut crude oil was conducted under varying pressure and temperature conditions to investigate the impact of CO2 on the density of the water-cut crude oil. The experiment revealed the changes in the density of the mixed fluid under different conditions of the temperature, pressure, CO2 injection, and water content. Based on these findings, a corresponding computational model was developed. The key conclusions derived from this study are as follows:

  • (1)

    Temperature effect: under the same water-cut conditions, the density of the mixed fluid decreases significantly as the temperature increases. Pressure effect: when the CO2 content is below 50%, the density of the mixed fluid increases with rising pressure. However, when the CO2 content exceeds 50%, the density first decreases and then increases as pressure continues to rise. CO2 content effect: under the same temperature and pressure conditions, as the CO2 content increases, the density of the mixed fluid decreases. Water-cut effect: as the water cut increases, the density of the mixed fluid increases significantly.

  • (2)

    A comprehensive analysis of the applicability of existing crude oil density prediction models indicates that none of the models take into account the impact of water cut on crude oil density. The average relative errors between the predicted and experimental density values for the Standing, Quail, and Wu Guanghuan models are 14.39%, 32.91%, and 61.74%, respectively. Both the Quail and Wu Guanghuan models exhibit significant deviations in their predictions of crude oil density, while the Standing model shows much smaller deviations and also considers a wider range of influencing factors.

  • (3)

    Based on experimental data, the Standing model was revised to develop a new density prediction model for the CO2–water-cut crude oil system. This new model is more comprehensive, distinguishing itself from existing density prediction models by incorporating key factors such as water cut, CO2 injection volume, gas–liquid ratio, pressure, and temperature, all of which affect crude oil density. The model’s predicted values showed average relative errors of 3.47%, 2.95%, and 3.05% under water-cut conditions of 20%, 60%, and 90%, respectively, with an overall average error of 3.16%, indicating high calculation accuracy. This model can accurately predict the density variations of produced fluids in the reservoir wellbore under temperature conditions ranging from 35 to 95 °C and pressure conditions from 3 to 28 MPa. This provides a solid foundation for future wellbore flow dynamics predictions, optimization of lifting processes, and related technical designs. Additionally, it offers valuable insights for density prediction in other high-water-cut reservoirs.

The authors declare no competing financial interest.

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