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. 2022 Nov 18;7(48):44420–44427. doi: 10.1021/acsomega.2c06450

Solubility Variation and Prediction Model of CO2 in Water-Bearing Crude Oil

Jinfa Zhang †,‡, Yingzhu Guan †,‡,*, Ting Li †,‡, Guojun Yin §
PMCID: PMC9730784  PMID: 36506220

Abstract

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The solubility of CO2 in water-bearing crude oil is of great significance for the calculation of crude oil reserves, the development of CO2-EOR (CO2-enhanced oil recovery), CO2-CCUS (carbon capture, utilization, and storage), and CO2 assisted steam huff-and-puff technology, and the optimization of the design of CO2 for heavy oil pipeline transportation. In order to determine the variation of the solubility of water-bearing crude oil by injecting CO2 into the formation, taking the Upper Wuerhe Formation reservoir in the 53 East Block as an example, the study of the dissolution characteristics of CO2 in water-bearing crude oil at different temperature and pressure conditions was carried out by using a high-temperature and high-pressure reaction kettle. At the same time, a new solubility prediction model of CO2 in water-bearing crude oil was proposed based on the existing solubility prediction models. The results show that, under the same water cut, the solubility of CO2 in water-bearing crude oil decreases with the increase of temperature and decreases with the decrease of pressure. At the same time, the solubility of CO2 in water-bearing crude oil is more sensitive to pressure. At the same temperature, the solubility of CO2 in water-bearing crude oil decreases with the increase of water cut, and the higher the pressure, the greater the effect of water cut on the solubility of CO2 in water-bearing crude oil. The newly established combined prediction model of CO2 solubility in water-bearing crude oil is convenient for calculation and has a wide range of applications. The average relative error is only 9.5%, which can meet the requirements of engineering calculation accuracy.

1. Introduction

Conventional water injection development has the problems of high water injection pressure, rapid production decline, low water flooding recovery, and strong reservoir damage for low permeability reservoirs and unconventional reservoirs. Gas injection can effectively solve the shortcomings of water injection development and has become an important means to enhance oil recovery in the world. At present, the gas injection media mainly include CO2, N2, air, hydrocarbon gas, and flue gas.1−5 Compared with other injection gases, CO2 has the advantages of being easily miscible with crude oil, having a low miscible pressure, promoting volume expansion of crude oil, reducing crude oil viscosity, reducing oil–water interfacial tension, improving crude oil flow characteristics, and forming dissolved gas flooding.6,7 In addition, the weak acidity of CO2 dissolved in water can play a role in acidizing plugging to a certain extent. CO2 flooding can enhance oil recovery by 7–18%.8 It has been widely used in the Lick Creek, Yates, and Kelly-Synder Oil Fields in the United States,8−10 Jilin, Xinjiang, and Shengli Oil Fields in China,11−13 and Weyburn, Ruofur, and Pabina Oil Fields in Canada.14,15 Injecting CO2 into the formation can achieve a win-win goal of enhancing oil recovery and reducing emission, with significant economic and social benefits. However, a large amount of CO2 dissolved in crude oil and the precipitation of CO2 in the production wells at the later stage of production will lead to changes in the physical properties of crude oil, making it more difficult to predict the PVT parameters of wellbore fluid. The solubility of CO2 in water-bearing crude oil is one of the PVT parameters of crude oil, which determines the changes of other PVT parameters of crude oil and CO2 flooding efficiency. Therefore, it is necessary to systematically study the solubility of CO2 in water-bearing crude oil. In addition, the PVT parameters of crude oil such as solubility are usually obtained by PVT sampling analysis. Due to the lack of sampling data in the new exploration area and the old oil area not meeting the sampling analysis conditions, prediction models such as the Briggs viscosity model,16 Quail density model,17 Vazquez volume coefficient model,18 and McCain solubility model19 are formed to calculate the PVT parameters of crude oil,20−23 but these empirical formulas have low accuracy and are only suitable for reservoirs of specific properties.

The comprehensive water cut of the Upper Wuerhe Formation reservoir in the 53 East Block of the Xinjiang Oil Field in China is 81.3%,24 and the potential of water flooding development is small. Carrying out the development test of CO2 injection to supplement energy is urgent. In this paper, the solubility characteristics of CO2 in water-bearing crude oil were obtained by an indoor miscible experiment of CO2-water-bearing crude oil, and the idea of a combined model was proposed based on the existing solubility models, which can lay a theoretical foundation for this reservoir to enhance oil recovery by CO2 flooding and provide a reference for solubility prediction of other reservoirs.

2. Basic Overview of the Reservoir

The Upper Wuerhe Formation reservoir in the 53 East Block of the Xinjiang Oil Field in China is located in the monoclinic zone of the footwall of the Ke-Wu fault in the Junggar Basin, which is a monoclinic structural lithologic reservoir with a southeast-sloping shape. The oil-bearing area of the upper Wuerhe Formation reservoir is 18 km2. The SW32 sand layer is the most developed, and the thickness is the largest, making it the main oil layer of the reservoir. The porosity of the oil layer is 9%, and the permeability is 23.89 mD, which makes it an extra-low porosity and low permeability reservoir.25 The original formation pressure of the reservoir is 28.20 MPa, and the saturation pressure is 24.00 MPa. It is an unsaturated reservoir with normal formation pressure. The formation temperature is 64 °C, the viscosity of the crude oil is 1.29 mPa·s, and the original gas–oil ratio is 121 m3/t. The reservoir has been dominated by water injection development for a long time. At present, the comprehensive water cut is 81.3%, and the potential of water flooding development is small. It is urgent to carry out the development test of gas injection to supplement energy. At the same time, the CO2 source is close to the oil area, and the CO2 emissions of major chemical enterprises near the Junggar Basin are large, which provides convenience for the reservoir to carry out CO2-EOR (CO2-enhanced oil recovery) and CCUS (carbon capture, utilization, and storage).

3. Experiment on the Dissolution Characteristics of CO2 in Water-Bearing Crude Oil

3.1. Experimental Instrument

The main experimental instrument used for testing the solubility of CO2 in water-bearing crude oil includes a PY-2 high-temperature and high-pressure sampler (reaction kettle), with an effective volume of 1000 mL, a maximum pressure resistance of 100 MPa, a maximum temperature resistance of 200 °C, a temperature control accuracy of 0.1 °C, a stirring speed of 10 r/min, and a stirring angle of 180°; a BY100-II high-pressure displacement pump, with an effective volume of a single pump body of 500 mL, a maximum pump pressure of 100 MPa, a pressure control accuracy of 0.1 level, and a flow range of 0.001–30 mL/min; an Agilent 6890 gas chromatograph for the determination of CO2, N2, O2, and C1–C8 components; an Agilent 7890 gas chromatograph for the determination of C1–C50 components; a QL-I gas meter, with an effective volume of 1000 + 1000 mL and volume accuracy of 1 mL; a BSA423 electronic balance, with an indexing value of 0.001 g; a ZR-III intermediate container; a constant temperature air bath; a gas booster pump, etc. The whole experimental device has good temperature and pressure control and can be tested under set temperature and pressure conditions, which provides a guarantee for the accuracy of experimental data.

3.2. Experimental Samples

The CO2 sample industrial analytical purity was 99.999%.

3.2.1. Crude Oil and Formation Water Samples

Oil and water samples were taken from Well W of the Upper Wuerhe Formation reservoir in the 53 East Block of the Xinjiang Oil Field in China. In order to obtain individual oil and water samples, oil and water were separated before the experiment. The oil released after separation was the experimental oil, and the released water was the experimental formation water after filtration.

3.2.2. Natural Gas Samples

Compounding natural gas samples was based on the known composition data of separated gas. The molar composition of the flash gas in Well W is shown in Table 1. The flash gas of Well W is mainly composed of C1–C8, CO2, and N2, so the natural gas compounding is divided into two parts: the compounding of CO2, N2, C1, C2, C3, and C4 gas and the compounding of C5, C6, C7, and C8 liquid. The gas compounding needs to use the deviation factor parameter (which can be simulated by PVTsim software according to the cylinder pressure and indoor temperature) to calculate the injection volume of each gas component, and the liquid compounding needs to use the mass and density parameters to calculate the injection volume of each liquid component.

Table 1. Molar Composition of Flash Gas Components in Well Wa.
  component
  
  C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7 C8 CO2 N2 sum
mole fraction (%) 82.92 7.37 4.81 1.42 1.02 0.02 0.21 0.04 0.03 0.03 0.17 1.96 100
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a

“i” is isomeric hydrocarbon, and “n” is normal hydrocarbon.

3.3. Experimental Scheme

Temperature and pressure are two important parameters affecting the solubility of CO2 in water-bearing crude oil. According to the temperature and pressure conditions of Well W of the Upper Wuerhe Formation reservoir in the 53 East Block, the solubility of CO2 in different water cut crude oils is tested under the conditions of temperature change of 20–65 °C and pressure change of 2–20 MPa. The specific experimental scheme is as shown in Table 2.

Table 2. Solubility Experiment Scheme.

water cut (%) 0, 30, 60, 80
pressure (MPa) 20, 14, 8, 2
temperature (°C) 20, 35, 50, 65
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3.4. Experimental Steps

The solubility of CO2 in water-bearing crude oil refers to the volume of CO2 dissolved in a unit volume of degassed water-bearing crude oil under certain temperature and pressure conditions. The dissolution characteristics of the experiment mainly include four parts: natural gas compounding, formation crude oil compounding, CO2 injection, and solubility test. The experimental process is shown in Figure 1.

Figure 1.

Figure 1

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Determination process of CO2 solubility in water-bearing crude oil.

3.4.1. Natural Gas Compounding

The actual injection volumes of CO2, N2, and C1–C4 gas are calculated according to the molar compositions of each component of the flash gas in Well W and the original gas–oil ratio. Each gas is transferred to the intermediate container in order 2–3 times according to the order of cylinder pressure from small to large and pressurized to 20 MPa for subsequent formation crude oil compounding.

3.4.2. Formation Crude Oil Compounding

The actual injection volume of C5–C8 liquid injected into the high-temperature and high-pressure sampler equipped with dead oil in turn is calculated, and the sampler is closed. The formation water sample is injected into the sampler in a certain proportion according to the water cut requirement, and then the compounded natural gas samples is injected into the sampler. The sampler is shaken for 2–3 h, making the gas and liquid in the sampler mix evenly, then left still to complete the formation crude oil compounding.

3.4.3. CO2 Injection

First, excess CO2 is injected into the sampler at 30 MPa, shaken for 2 h, and left to stand still, and undissolved CO2 gas is released. The pressure is lowered to 20 MPa, and the shaking and standing steps are repeated. The valve is opened to release the gas, and then the valve is closed after the oil is discharged; at this time the solubility test can begin.

3.4.4. Solubility Test

The valve is opened under the test pressure, and the gas is released; a certain amount of gas is collected for chromatographic testing, until crude oil appears, when the the valve is closed. In order to prevent the slight decrease of pressure from causing the change of solubility, the solubility under this experimental condition can be calculated by increasing the pressure by 1 MPa and collecting crude oil and gas respectively after opening the valve. Then, the pressure is reduced in turn, and the above steps are repeated to obtain the solubility under the corresponding pressure until the experimental scheme is completed.

After a set of pressure measurements is completed, the experimental temperature and moisture content are changed to test the other experimental schemes.

4. Experimental Results and Discussion

The solubility of CO2 in water-bearing crude oil was tested under different pressures (2 MPa, 8 MPa, 14 MPa, 20 MPa) and different temperatures (20 °C, 35 °C, 50 °C, 65 °C). Figure 2 and Figure 3 show the solubility variation of CO2 in water-bearing crude oil at different temperatures and different water cuts, respectively.

Figure 2.

Figure 2

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Solubility of CO2 in water-bearing crude oil at different temperatures.

Figure 3.

Figure 3

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Solubility of CO2 in water-bearing crude oil at different water cuts.

4.1. Dissolution Characteristics of CO2 in Water-Bearing Crude Oil at Different Temperatures

It can be seen from Figure 2 that under the same water cut conditions, the solubility of CO2 in water-bearing crude oil decreases with the increase of temperature and decreases with the decrease of pressure. On the whole, when the pressure decreases from 20 to 2 MPa, the CO2 solubility decreases by 38.80–156.78 cm3/cm3, and when the temperature increases from 20 to 65 °C, the solubility of CO2 decreases by 3.54–63.45 cm3/cm3, indicating that the solubility of CO2 in water-bearing crude oil is more sensitive to pressure. Therefore, in the process of fluid flow, the solubility of CO2 will gradually decrease, and a large amount of CO2 will precipitate from the fluid.

4.2. Dissolution Characteristics of CO2 in Water-Bearing Crude Oil at Different Water Cuts

It can be seen from Figure 3 that, under the same temperature conditions, the solubility of CO2 in water-bearing crude oil decreases with the increase of the water cut, and the higher the pressure, the greater the effect of water cut on the solubility of CO2. In addition, Figure 3a,b follows almost the same pattern at different water cuts, and the same tendency is also observed in Figure 3c,d, but slightly different. The main reason is that the solubility of CO2 in water-bearing crude oil is less affected by the change of temperature, which further confirms the above conclusion about the solubility of CO2 in water-bearing crude oil at different temperatures. On the whole, the water cut increases from 0% to 80%. When the pressure is not higher than 8 MPa, the water cut has little effect on the solubility of CO2 in water-bearing crude oil, and the maximum decrease of CO2 solubility is only 30.91 cm3/cm3. When the pressure is higher than 8 MPa, the water cut has a great influence on the solubility of CO2 in water-bearing crude oil, and the maximum decrease of CO2 solubility can reach 109.60 cm3/cm3. Therefore, the lower the oil well pressure and the higher the water cut, the smaller the CO2 solubility and the worse the CO2 flooding efficiency.

5. Analysis and Correction of Solubility Prediction Model of CO2 in Water-Bearing Crude Oil

5.1. Comparison of Existing CO2 Solubility Prediction Models in Water-Bearing Crude Oil

At present, the solubility prediction models of CO2 in crude oil mainly include the Mehrotra model, Frank model, and Taylor model. The following introduces the above three commonly used prediction models, which provide a theoretical basis for the selection of the solubility prediction model of the Upper Wuerhe Formation reservoir in the 53 East Block.

In 1982, Mehrotra et al.26 studied the solubilities of synthetic gas and N2, CO2, and CH4 components in asphalt through experiments and proposed a solubility prediction model for each component. The average deviation of CO2 solubility prediction in asphaltene crude oil was 6.3%. The model is suitable for a temperature range of 23.89–99.22 °C and pressure range of 0.4–6.8 MPa.

5.1. 1

where Rs is the solubility of CO2 in asphaltene crude oil (cm3/cm3), T is the system temperature (K), P is the system pressure (MPa), and b1, b2, b3, and b4 are model coefficients; the specific values are shown in Table 3.

Table 3. Mehrotra Model Correlation Coefficients.

  coefficient
  b1 b2 b3 b4
value –0.0073508 –14.794 6428.5 4971.39
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In 1988, Frank Chung et al.27 tested the solubility of CO2 in five kinds of heavy oil under different temperature and pressure conditions. It was found that the solubility of CO2 in crude oil was mainly related to the temperature, pressure, and relative density of crude oil. It decreased with the increase of temperature and increased with the increase of pressure. However, when the pressure was higher than 6.9 MPa, the solubility is not very sensitive to pressure. Through the analysis of experimental data, the calculation formula of CO2 solubility in heavy oil is proposed. The model is suitable for the temperature range of 24–94 °C and the pressure below 6.9 MPa.

5.1. 2

where Rs is CO2 solubility (m3/m3), γ is the relative density of heavy oil (API), T is the temperature (°F), P is the pressure (psia), and a1, a2, a3, a4, a5, a6, and a7 are model coefficients; the specific values are shown in Table 4.

Table 4. Frank Model Correlation Coefficients.

  coefficient
  a1 a2 a3 a4 a5 a6 a7
value 0.4934 × 10–2 4.0928 0.571 × 10–6 1.6428 0.6763 × 10–3 781.334 –0.2499
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In 2016, Taylor Barclay et al.28 established a calculation model for the solubility of CO2 in light crude oil based on the experimental data integrated by Emera. The model is suitable for the temperature range of 32.2–73.9 °C, pressure range of 1.81–27.4 MPa, crude oil weight range of 0.85–0.90, and CO2 solubility (mole fraction) range of 0.12–0.85.

5.1. 3

where Rs is the solubility of CO2 in crude oil (mole fraction), T is the temperature (°C), P is the pressure (MPa), and a, b, c, and d are model coefficients; the specific values are shown in Table 5.

Table 5. Taylor Model Correlation Coefficients.

  coefficient
  a b c d
value 0.36913 –0.00106 0.01280 –0.00160
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In 2011, Xing et al.29 conducted a physical property test experiment of CO2 flooding produced fluid and studied the effect of water on the solubility of CO2 in crude oil and the effect of oil on the solubility of CO2 in water. It is found that the effect of water (oil) on the solubility of CO2 in crude oil (water) can be ignored. The solubility of CO2 in water-bearing crude oil can be expressed by the weighted average of its solubility in pure oil and pure water:

5.1. 4

where Rs is the solubility of CO2 in the oil–water mixture, Rw and Ro are the solubilities of CO2 in water and oil, respectively, and Xw and Xo are the volume fractions of water and oil in the oil–water mixture, respectively.

In 2012, Wang et al.30 studied the solubility of CO2 in formation fluid at 45 °C and 3.0–8.5 MPa for Daqing Oil Field fluid and obtained similar conclusions. Under the same temperature and pressure conditions, the relationship between the solubility of CO2 in the oil–water mixture and its solubility in crude oil and formation water is

5.1. 5
5.1. 6
5.1. 7

where R1:1, R2:1, and R4:1 are the solubility of CO2 in the mixtures with oil–water volume ratios of 1:1, 2:1, and 4:1, respectively.

Therefore, based on the research of Xing et al. and Wang et al., it can be concluded that the solubility of CO2 in the oil–water mixture at constant temperature is only related to pressure and liquid composition, which can be expressed by the weighted average of its solubility in pure oil and pure water, which is called the combined model. When applying the combined model, it is necessary to know not only the solubility of CO2 in crude oil but also the solubility of CO2 in water. The solubility of CO2 in crude oil can be calculated by the Mehrotra model, Frank model, and Taylor model. The solubility of CO2 in water can be calculated by the model proposed by Chang et al.31 in 1996. The model is suitable for the temperature range of 12–100 °C, pressure range of 0.1–69 MPa and NaCl solution with salinity of 0–6 mol/L. The specific expressions are as follows:

If P < Po:
5.1. 8

If P ≥ Po:
5.1. 9

where

5.1. 10
5.1. 11
5.1. 12
5.1. 13
5.1. 14
5.1. 15

Rsw is the solubility of CO2 in water (scf/STB), T is temperature (°F), P is pressure (psia), and a, b, and c are model coefficients; the specific values are shown in Table 6.

Table 6. Chang Model Correlation Coefficients.

coefficient i = 0 i = 1 i = 2 i = 3 i = 4
ai 1.163 –16.630 111.073 –376.859 524.889
bi 0.965 –0.272 0.0923 –0.1008 0.0998
ci 1.280 –10.757 52.696 –222.395 462.672
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In summary, domestic and foreign scholars have conducted a lot of research on the solubility of the CO2–crude oil mixed fluid and put forward many prediction models. Table 7 lists the commonly used prediction models of CO2 solubility and their applicable ranges.

Table 7. Application Scope of Common CO2 Solubility Prediction Models in Water-Bearing Crude Oil.

prediction model temperature (°C) pressure (MPa) others medium
Mehrotra model 23.89–99.22 0.4–6.8 — oil
Frank model 24–94 <6.9 — oil
Taylor model 32.2–73.9 1.81–27.4 crude oil weight range of 0.85–0.90, CO2 solubility (mole fraction) range of 0.12–0.85 oil
Chang model 12–100 0.1–69 NaCl solution with salinity of 0–6mol/L water
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By comparing the reservoir conditions of the test block and the applicable scope of various commonly used solubility prediction models, it is found that it is impossible to find a complete set of physical parameter calculation methods suitable for the target block from Table 7. Therefore, it is necessary to carry out the solubility prediction model correction of CO2 in water-bearing crude oil.

5.2. Correction of Solubility Prediction Model of CO2 in Water-Bearing Crude Oil

Based on the research results of Xing et al. and Wang et al., it is considered that the solubility of CO2 in the oil–water mixture at constant temperature is only related to pressure and liquid composition. The solubility combination model is established by the weighted average method:

5.2. 16

where Rs is the solubility of CO2 in the oil–water mixture, Ro and Rw are the solubilities of CO2 in crude oil and water, respectively, and Xw is the volume fraction of water in the oil–water mixture.

The solubility prediction models of CO2 in crude oil include the Mehrotra model, Frank model, and Taylor model, and the solubility prediction model of CO2 in water includes the Chang model. The solubility of CO2 in crude oil and water is calculated by different methods, and different combination models will be formed. Therefore, the solubility prediction model of CO2 in water-bearing crude oil can be divided into six solubility models as shown in Table 8.

Table 8. Different Solubility Prediction Models.

type model
single models Mehrotra model
Frank model
Taylor model
combined models Mehrotra–Chang combined model (combined model 1)
Frank–Chang combined model (combined model 2)
Taylor–Chang combined model (combined model 3)
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The above six models were used to calculate the solubility of CO2 in water-bearing crude oil under different experimental conditions, and the calculated values were compared with the measured values, as shown in Figure 4. The average error of each model is shown in Figure 5. The solubility relative error of each group of data points = (solubility calculated value – solubility measured value)/solubility measured value. The average solubility error of each model is the average value of the solubility relative error of each group of data points of each model.

Figure 4.

Figure 4

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Comparison of different solubility calculation models of CO2 in water-bearing crude oil.

Figure 5.

Figure 5

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Error comparison of different solubility calculation models of CO2 in water-bearing crude oil where “A” is the Mehrotra model, “B” is the Frank model, “C” is the Taylor model, “D” is combined model 1, “E” is combined model 2, and “F” is combined model 3.

It can be seen from Figure 4 and Figure 5 that the CO2 solubility calculated by the combined model 1 (Mehrotra–Chang combined model) is in good agreement with the measured value, and the average error is 9.5%. Therefore, for the upper Wuerhe Formation reservoir in the 53 East Block, the solubility of CO2 in crude oil can be calculated by the Mehrotra model, and the solubility of CO2 in water can be calculated by the Chang model; then, the solubility of CO2 in water-bearing crude oil can be calculated by the weighted average method according to the water cut.

6. Conclusions

The study of the solubility characteristics of CO2 in water-bearing crude oil under different pressure and temperature conditions was carried out. The existing solubility prediction models of CO2 in water-bearing crude oil were compared, and a new prediction model was proposed. The main conclusions are as follows:

  • (1)

    The solubility of CO2 in water-bearing crude oil shows that, under the same water cut, the solubility of CO2 in water-bearing crude oil decreases with the increase of temperature and decrease with the decrease of pressure. At the same temperature, the solubility of CO2 in water-bearing crude oil decreases with the increase of water cut, and the higher the pressure, the greater the effect of water cut on the solubility of CO2 in water-bearing crude oil.

  • (2)

    A combined model was established by combining the Mehrotra model, Frank model, Taylor model, and Chang model. The average error of the optimal combined model for the solubility prediction of the Upper Wuerhe Formation reservoir in the 53 East Block of the Xinjiang Oil Field was only 9.5%, which was much lower than that of other solubility prediction single models.

  • (3)

    The existing solubility prediction models of CO2 in water-bearing crude oil have low accuracy and poor adaptability. The combination of different CO2 solubility prediction models in crude oil and water provides a new idea for predicting the solubility of CO2 in water-bearing crude oil in other reservoirs. The combined model has strong adaptability and is easy to calculate. The best solubility prediction model of CO2 in water-bearing crude oil can be selected by combining different models.

Acknowledgments

This work was supported by the National Science and Technology Major Project (2016ZX05060) and the Oil and Gas Resources and Exploration State Key Laboratory Open Project (PRP/open-1901). The authors gratefully acknowledge their support. The first author Jinfa Zhang is very grateful to Dr. Zhijuan Hao from the School of Economics and Management, Ningxia University, for her continuous encouragement and support.

The authors declare no competing financial interest.

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