Journal of Chemistry
Volume 2015 (2015), Article ID 873718, 11 pages
http://dx.doi.org/10.1155/2015/873718

Research Article

Phase Behavior and Physical Parameters of Natural Gas Mixture with

Dali Hou,1,2,3 Hucheng Deng,1,2 Hao Zhang,1,2 Kai Li,1,2 Lei Sun,³ and Yi Pan³

¹School of Energy Resources, Chengdu University of Technology, Chengdu, Sichuan 610059, China
²The State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Chengdu University of Technology, Chengdu, Sichuan 610059, China
³The State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation Engineering, Southwest Petroleum University, Xindu Avenue No. 8, Chengdu, Sichuan 610500, China

Received 3 January 2015; Revised 28 March 2015; Accepted 4 April 2015

Academic Editor: Christophe Coquelet

Copyright © 2015 Dali Hou et al. This is an open access article distributed under the Creative Commons Attribution License, which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

Abstract.

The two-flash experiment, constant composition expansion experiment, saturation pressure measurement experiment, and phase transition observation experiment from well bottom hole to well head of four high CO₂ content natural gas samples were carried out by using the JEFRI-PVT apparatus made from DBR Company of Canada. The experimental results show that in the four high CO₂ content gas samples no phase transitions will take place at temperatures greater than 35°C. In the gas-liquid two-phase region, saturation pressures, critical pressure, critical temperature, and an integrated P-T phase diagram of different CO₂ content natural gases are calculated by using the modified PR equation of state and modified (T) equation proposed by Saffari. The deviations between the saturation pressure calculated by using the model proposed in this study and experimental measured saturation pressure are very small; the average relative error is only 2.86%. Thus, the model can be used to predict the phase equilibrium parameters of high CO₂ content natural gas.

1. Introduction

With the increasing demand of CO₂ resource, exploration and development of high CO₂ content gas reservoirs are becoming one part of the future oil-gas strategy [1]. Currently, the discovered high CO₂ content gas reservoirs in the world are mainly distributed over the Pacific, such as Japan, Indonesia, New Zealand, Philippines, Vietnam, Thailand, Malaysia, Australia, Mexico, America, and Canada [2–5]. Twenty-eight high CO₂ content gas reservoirs have been discovered in China and they are mainly distributed in oil-bearing basins in the east of China, in which the high CO₂ content natural gas reserve is 20000 × 10⁸ m³ in Songliao basin [6]. Furthermore, CO₂ content in Changling, Gudian, Honggang, Shengping, Fangshen, and other gas reservoirs in Jilin oilfield of Songliao basin can even range from 20 mol% to 90 mol% [7–9]. High CO₂ content natural gas reservoir is very special and development is very difficult, which mainly reflects in the variation of fluid phase behavior. The research of some scholars at home and abroad focuses on the physical parameters and development index of the CO₂ contents in natural gas [7, 9–14], but seldom focus is directed on the phase behavior of natural gases with high CO₂ content and the phase behavior of natural gas with high CO₂ content is not entirely clear at present [15–19]. Thus, it is one of basic research topics on the experimental measured saturation pressure to determine whether any phase transitions in natural gases with high CO₂ content take place from formation to well head and the physical parameters of high CO₂ content natural gases for high-efficient developing the gas reservoirs with high CO₂ content.

It is revealed in this paper whether any phase transition in high CO₂ content natural gases takes place in the exploitation process. The saturation pressures of different CO₂ content in natural gases at different temperatures are measured by using the DBR-PVT apparatus, and the saturation pressures, critical pressures, critical temperatures, and an integrated - phase diagram of different CO₂ content natural gases are calculated by using the modified PR equation of state and modified equation proposed by Saffari. And the deviations between the saturation pressure calculated by using the model proposed in this paper and experimental measured saturation pressure are analyzed. Also revealed in this paper is the influence of different CO₂ content in natural gases on the - phase diagrams and critical points. Furthermore, the variation law and affecting factors of the physical parameters, such as relative volume, -factor, formation volume factor, and density of high CO₂ content natural gases are discussed in this paper.

2. Theories

By modifying the attractive term in the Redlick–Kwong equation of state, Peng and Robinson were able to enhance the model prediction of experimental data. Since its inception, Peng-Robinson EOS has been widely used to estimate thermodynamic properties for hydrocarbon systems. It reads [20, 21] as

where is pressure, is temperature, is the molar volume, is the gas constant, and and are the parameters of the EOS. At constant and , the equation will take the form of a cubic equation in and can be solved for using any standard analytical or numerical technique [22]. The limitations on critical point lead to the following relations for the PR-EOS parameters [20]:

where subscript indicates critical property and is temperature dependent. In this work, we use the new -function proposed by Saffari, which is written as [23]

The new -functions proposed are exponential functions, each with three adjustable parameters , , and . Since the adjustable parameters determine attractive intermolecular interactions in a pure component system, the values of are compound-specific and should be optimized for each pure component. In this work, we determine the optimum values of pure component parameters by minimizing the error of vapor pressure predicted by using the modified PR equation of state and modified equation proposed by Saffari with respect to the experimental values in the temperature range from triple point to critical point [23].

And we use the individually optimized parameters of pure components for the new -function proposed in this work (3) to develop generalized equations in terms of the acentric factor . Pure component constants, including critical properties, and vapor pressure data are obtained from Poling et al. [24], Yaws [25], and Smith and Srivastava [26]. The adjustable parameters of the new -function proposed by Saffari have been fitted to experimental vapor pressure data, given in Table 1.

Table 1: Optimized parameters of the new α-function proposed by Saffari (3).

Substance
range
Optimized parameters

CO₂
0.72–1
0.0056
0.0881
1.4928

N₂
0.52–1
0.0033
−0.0031
0.8180

methane
0.48–1
0.0039
0.0473
0.8514

ethane
0.30–1
0.0047
0.0359
1.0638

propane
0.26–1
0.0050
0.1010
1.3640

i-butane
0.28–1
0.0052
0.0730
1.4200

n-butane
0.33–1
0.0054
0.0780
1.4205

i-pentane
0.25–1
0.0060
0.0885
1.5626

n-pentane
0.31–1
0.0059
0.0872
1.5624

hexane
0.36–1
0.0072
0.1731
1.8759

And then, the parameters , , and are generalized as a function of acentric factor . Acentric factor of a pure component is obtained from Poling et al. [24]. Figures 1–3 show the trend of fitted parameters presented in Table 1 versus the acentric factor, as well as a linear fit and the -squared.

Figure 1: Linear trend of fitted parameter of the -function equation (3).

Figure 2: Linear trend of fitted parameter of the -function equation (3).

Figure 3: Linear trend of fitted parameter of the -function equation (3).

Consequently, the final form of new -function with the generalized parameters for natural gas components can be written as

Extending PR-EOS to mixtures requires replacement of coefficients and by the following van der Waals composition-dependent mixing rules [20]:

The unlike-interaction parameter, , formed between component and component , can be related to the pure components parameter with an extra fitting coefficient () known as the coupling parameter:

3. Experiments

3.1. Sample

Experimental gas samples were divided into 4 groups: one group was directly taken from surface separator of YP9 well in Jilin gas field, and the other three groups (Gas1, Gas2, and Gas3) were made from YP9 dry natural gas and pure industrial carbon dioxide (purity > 99.99%). The detailed synthetic process refers to SY/T6434-2000 [27]. The initial formation pressure and formation temperature of YP9 well are, respectively, 42.34 MPa and 127.5°C. The components of four groups of gas samples were analyzed by using HP-6890 gas chromatography and Shimadzu GC-14A gas chromatography. The results are shown in Table 2. The critical pressure and temperature [28, 29] of the pure components which are normally presented in natural gas are also listed in Table 2. The contents of CO₂ in YP9 well, Gas1, Gas2, and Gas3 are, respectively, 21.746 mol%, 10.045 mol%, 55.535 mol%, and 75.323 mol%. The CO₂ content in natural gas being more than 10 mol% is usually called the high CO₂ content natural gas [30]. Thus, The four groups of gas samples are all the high CO₂ content gas samples.

Table 2: Composition of various gas mixtures and the critical properties of the related component.

Components
Gas1
YP9
Gas2
Gas3

(mol%)
(mol%)
(mol%)
(mol%)
(MPa)
(K)

CO₂
10.045
21.746
55.535
75.323
7.376
304.2
0.225

N₂
1.474
2.71
2.056
0.971
3.394
126.2
0.040

C₁
84.718
73.604
40.891
23.014
4.600
190.6
0.008

C₂
2.973
1.127
0.941
0.422
4.884
305.4
0.098

C₃
0.532
0.492
0.235
0.092
4.246
369.8
0.152

iC₄
0.064
0.006
0.299
0.034
3.640
408.1
0.176

nC₄
0.058
0.301
0.004
0.042
3.800
425.2
0.193

iC₅
0.026
0.003
0.005
0.047
3.384
460.4
0.227

nC₅
0.052
0.005
0.003
0.033
3.374
469.6
0.251

C₆
0.058
0.006
0.031
0.022
2.969
507.4
0.296

Note: gas sample with CO₂ content of 10.045 mol% is made from YP9 and dry natural gas, and gas sample with CO₂ content of 55.535 mol% or 75.323 mol% is made from YP9 and pure industrial carbon dioxide (purity > 99.99%).

3.2. Apparatus

The experimental facility is a mercury-free high pressure PVT system made by the DBR Company, Canada. A schematic diagram of the corresponding apparatus is given in Figure 4. It is mainly characterized by the visual observation of experimental phenomena and the specially designed piston in the PVT cell that allows us to precisely measure even minute liquid. The system is mainly made up of a PVT cell, thermostatic air bath, pressure sensor, temperature sensor, flash separator, electronic balance, gasometer, gas chromatography, sample container, automatic pump, and operation control system. Sample container is made from sapphire glass.

Figure 4: Schematic diagram of the experimental apparatus.

The volume of fluid in the PVT cell can be calculated by the internal cross-sectional area of sapphire glass cylinder multiplied by the height of the fluid, which was measured by the grating altimeter.

The physical parameters of main parts are as follows.

PVT cells: maximal working pressure is 70 MPa, the highest operating temperature is 200°C, the lowest operating temperature is −100°C, and maximal volume is about 150 cm³.

Pressure sensor: It is 0~100 MPa, and precision of pressure control is 1 Psi.

Temperature sensor: it is −100~200°C, and precision of temperature control is ±0.1°C.

Thermostatic air bath: the highest operation temperature is 200°C and precision of temperature control is ±0.1°C.

Sample container: it is 130 cm³.

Automatic pump: rated operation pressure is 100 MPa with resolution of 1 Psi, and the range of operation pump volume is 500 cm³ with resolution of 0.001 cm³.

Electronic balance: it is 0~500 g, and precision of weight control is 0.001 g.

The accuracy of PVT main parts satisfies the phase behavior experimental requirement of the synthetic gas sample with different CO₂ content [31].

3.3. Experimental Procedures

Experimental procedures are as follows:

(1)Clean PVT vessel and cells; then connect the PVT vessel to cells and evacuate the cells.(2)Prepare the gas samples, and control and maintain the desired temperature using the constant temperature air bath.(3)Introduce a test gas about 50 mL (YP9 gas sample) into PVT vessel at the specified temperature and pressure in the oven and keep it for 5 h, and then hold on an hour and measure the gas volume of the PVT vessel.(4)Two-flash experiment: slightly open the valve between the cells and bleed gas from the PVT vessel into the flash separators, at the same time, and keep the pressure using the automatic pump at formation temperature (127.5°C).(5)Record the bled gas volumes using the gasometer and remaining gas volumes of PVT vessel.(6)The bled gas was analyzed using gas chromatograph.(7)Constant composition expansion experiment (CCE experiment) or - relationship experiment: pressure was reduced step by step from initial formation pressure to the limit pressure of the piston movement under the formation temperature. The volumes were recorded when each pressure was stable.(8)Step was repeated at 35°C, 75°C, and 127.5°C, respectively. - relationship experiment was tested at least three times under each temperature and the average value was calculated.(9)Two-flash experiments and CCE experiments were also performed on the other three gas samples by repeating step to step .(10)The gas sample with the highest content of CO₂ (75.323 mol%) was introduced into the PVT vessel to study whether phase transition in high CO₂ content natural gas takes place from formation to well head. The experimental temperatures are −10°C and 35°C, respectively.

4. Results and Discussion

4.1. Two-Flash and CCE Experiments

The results of two-flash experiments are listed in Table 3. Formation volumes (under the formation conditions) and ground volumes (under the standard conditions) are the experimental measurements, and density, molecular weight, formation volume factor, and -factor are calculated by using gas state equation. The gas state equation is expressed as follows [27].

Table 3: Results from two-flash experiments for different CO₂ contents in natural gas.

Parameters
Gas1
YP9
Gas2
Gas3

Formation volume/ (cm³)
2.97
3.951
3.762
6.676

Ground volume/ (cm³)
850
1135
1155
2160

Formation volume factor/
0.003496
0.003481
0.003257
0.003091

-factor/
1.0702
1.0663
0.9885
0.9295

Gas density/ (kg/m³)
230.00
268.51
398.75
494.13

(under the formation conditions)

Molecular weight/ (g/mol)
19.85
22.49
30.55
35.92

Relative density/
0.6853
0.7763
1.0545
1.2398

Under the formation conditions one has

Under the standard conditions one has

is the formation pressure; is the gas volume under the formation conditions; is the deviation factor under the formation conditions; is the formation temperature; is the number of moles; is the gas general constant, 8.3147 MPa·cm³·mol⁻¹·K⁻¹; is the atmospheric pressure, and it is usually approximately equal to 0.101325 MPa; is the gas volume under the standard conditions; is the deviation factor under the standard conditions, and it is usually approximately equal to 1; is the standard temperature, and it is usually approximately equal to 20°C.

Relative densities are calculated by using the following [27]:

is the gas molecular weight; is the air molecular weight, and it is usually approximately equal to 28.97 g/mol.

We can draw the conclusion from Table 3 that the density, molecular weight, and relative density increase with increasing CO₂ content in natural gas, while the formation volume factor and -factor decrease with increasing CO₂ content in natural gas.

CCE experiment was performed to draw the relative volume, -factor, formation volume factor, and density under the grading pressure. And the results are shown from Figures 5–12.

Figure 5: Variation of the relative volume of YP9 gas sample with pressure under different temperatures.

Figure 6: Variation of the formation volume factor of YP9 gas sample with pressure under different temperatures.

Figure 7: Variation of the gas density of YP9 gas sample with pressure under different temperatures.

Figure 8: Variation of the -factor of YP9 gas sample with pressure under different temperatures.

Figure 9: Variation of the relative volume of different CO₂ content natural gas samples with pressure at 127.5°C.

Figure 10: Variation of the volume factor of different CO₂ content natural gas samples with pressure at 127.5°C.

Figure 11: Variation of the gas density of different CO₂ content natural gas samples with pressure at 127.5°C.

Figure 12: Variation of the -factor of different CO₂ content natural gas samples with pressure at 127.5°C.

4.1.1. Effect of Temperature

The effect of temperature on the physical properties of YP9 gas sample was, respectively, tested under the formation temperature (127.5°C), the temperature in the well (75°C), and the ground temperature (35°C). It can be seen from Figures 5–7 that the relative volume and formation volume factor of high CO₂ content natural gases increase with increasing temperature under constant pressure, while the density of gas decreases with increasing temperature under constant pressure. And the relative volume and formation volume factor of high CO₂ content natural gases decrease with increasing pressure at isothermal conditions. The effects of temperature and pressure on the experimental -factors for YP9 gas sample are shown in Figure 8. It can be seen clearly form Figure 8 that -factor decreases with increasing pressure at lower pressure range, that is, less than 18 MPa, while it increases with increasing pressure at higher pressures, that is, higher than 18 MPa. And the -factor decreases with decreasing temperature and a greater decrease can be observed in a pressure range from about 15 MPa to 22 MPa [32].

4.1.2. Effect of CO₂ Content

Experimental relative volumes, formation volume factors, and densities of different CO₂ content natural gases are shown from Figures 9–11. It can be seen clearly from Figures 9–11 that relative volume and formation volume factor decrease with increasing CO₂ content in natural gas at 127.5°C isothermal and constant pressure conditions, but they do not change insignificantly. The effects of CO₂ content in natural gas on the experimental -factors of different CO₂ content natural gases are shown in Figure 12. It can be seen from Figure 12 that -factor decreases with increasing CO₂ content in natural gas at 127.5°C isothermal and constant pressure conditions. And the dependence of the pressure follows the same trends as mentioned in Figure 5.

4.2. Effect of CO₂ Content on - Diagram

In order to test and draw the - phase diagram of the high CO₂ content natural gas, we have tested saturation pressures of the high CO₂ content natural gases at different temperatures (−60°C, −50°C, −40°C, −30°C, −20°C, −10°C, and 0°C) based on the above CCE experimental test methods. The test results are shown in Table 4. At the same time, saturation pressures at the corresponding conditions are calculated by using (1) to (7), and the tested saturation pressures are fitted by adjusting critical parameters (critical temperature and critical pressure) of C₆ on the basis of the fixed binary interaction coefficients in the process of calculation; the calculated results are also shown in Table 4. C₆ has several isomers; the critical parameters are not fixed, so we choose the critical parameters of C₆ as adjustable parameters to fit the saturation pressure of different CO₂ content natural gases. The fixed binary interaction coefficients are given in Table 6 and the critical parameters (critical temperatures and critical pressures) of C₆ are given in Table 7. It can be seen from Table 7 that the higher the CO₂ content, the higher the critical temperature, the lower the critical pressure, and the heavier the system (different CO₂ content natural gas). And we compare the saturation pressure calculated by using the model proposed in this paper with the experimental measured saturation pressure; the deviations between the saturation pressure calculated by using the model proposed in this paper and experimental measured saturation pressure are shown in Table 5. The absolute relative error (11) and the average absolute relative error (12) are used to express the deviation between the saturation pressure calculated by using the model proposed in this paper and the experimental measured saturation pressure. We can draw the conclusion from Table 5 that the temperatures are colder, the absolute relative error is greater, and the higher the CO₂ content in natural gas, the greater the absolute relative error. The average relative errors of Gas1, YP9, Gas2, and Gas3 are 1.62%, 2.03%, 3.29%, and 3.38%, respectively. Overall, the deviations between the saturation pressure calculated by using the model proposed in this paper and experimental measured saturation pressure are very small; the average relative error of all the gas samples is 2.86%. So it shows that the model can be used to predict the - phase diagram of the high CO₂ content natural gas. Consider

Table 4: Saturation pressure calculated by using the model proposed in this paper and experimental measured saturation pressure.

Parameters
Gas1
YP9
Gas2
Gas3

Calculated value
Measured value
Calculated value
Measured value
Calculated value
Measured value
Calculated value
Measured value

(MPa)
(MPa)
(MPa)
(MPa)
(MPa)
(MPa)
(MPa)
(MPa)

Saturation pressure (−60°C)
6.21
6.05
6.28
6.11
4.88
4.62
/
/

Saturation pressure (−50°C)
6.75
6.68
7.05
6.92
5.69
5.51
3.99
3.75

Saturation pressure (−40°C)
6.08
6.01
6.88
6.98
6.48
6.66
4.68
4.45

Saturation pressure (−30°C)
/
/
/
/
7.32
7.15
5.42
5.65

Saturation pressure (−20°C)
/
/
/
/
8.13
8.45
6.23
6.35

Saturation pressure (−10°C)
/
/
/
/
8.48
8.65
7.08
6.95

Saturation pressure (0°C)
/
/
/
/
/
/
7.85
8.02

Note: “/” shows that no saturation pressure is measured and calculated.

Table 5: The deviations between the saturation pressure calculated by using the model proposed in this paper and experimental measured saturation pressure.

Parameters
Gas1
Gas1
YP9
YP9
Gas2
Gas2
Gas3
Gas3
Total

ARE, %
AARE, %
ARE, %
AARE, %
ARE/%
AARE/%
ARE/%
AARE/%
AARE/%

Saturation pressure (−60°C)
2.64
1.62
2.78
2.03
5.63
3.29
/
3.38
2.86

Saturation pressure (−50°C)
1.05
1.88
3.27
6.40

Saturation pressure (−40°C)
1.16
1.43
2.70
5.17

Saturation pressure (−30°C)
/
/
2.38
4.07

Saturation pressure (−20°C)
/
/
3.79
1.89

Saturation pressure (−10°C)
/
/
1.97
1.87

Saturation pressure (0°C)
/
/
/
2.12

Table 6: Binary interaction parameters () and mixing rules for the model proposed in this study.

Components
CO₂
N₂
C₁
C₂
C₃
iC₄
nC₄
iC₅
nC₅
C₆

CO₂
0
−0.02
0.103
0.130
0.135
0.130
0.130
0.125
0.125
0.150

N₂
−0.02
0
0.031
0.042
0.091
0.095
0.095
0.095
0.095
0.120

C₁
0.103
0.031
0
0.003
0.009
0.016
0.015
0.021
0.021
0.025

C₂
0.13
0.042
0.003
0
0.002
0.005
0.005
0.009
0.009
0.012

C₃
0.135
0.091
0.009
0.002
0
0.001
0.001
0.003
0.003
0.005

iC₄
0.13
0.095
0.016
0.005
0.001
0
0.000
0.000
0.000
0.001

nC₄
0.13
0.095
0.015
0.005
0.001
0.000
0
0.001
0.001
0.001

iC₅
0.125
0.095
0.021
0.009
0.003
0.000
0.001
0
0.000
0.000

nC₅
0.125
0.095
0.021
0.009
0.003
0.000
0.001
0.000
0
0.000

C₆
0.15
0.12
0.025
0.012
0.005
0.001
0.001
0.000
0.000
zero

Table 7: The critical parameters (critical temperature and critical pressure) of C₆.

Sample
Critical temperature, °C
Critical pressure, MPa

Gas1
235.95
2.934

YP9
242.45
2.889

Gas2
255.65
2.776

Gas3
268.95
2.740

- diagrams and critical points of different CO₂ content natural gases in the gas-liquid two-phase region were drawn using (1) to (7); the calculated results are shown in Figures 13 and 14. And - diagrams and critical points of pure methane and pure CO₂ in Figures 13 and 14 refer to the experimental data from the literature [33, 34]. In Figure 13, the vapor-liquid critical locus exits in the pure CH₄ critical point extending continuously toward the CO₂ critical point [35]. Three-phase loci originating from triple-point of pure CO₂ ends in the triple-point of CH₄ [35]. Here, we only consider the gas-liquid two-phase region, because it is found in the process of calculation that the model proposed in this study is only applied to calculate the gas-liquid phase equilibrium, while it is not applied to calculate the gas-solid, liquid-solid, and gas-liquid-solid phase equilibrium. We can draw the conclusion from Figures 13 and 14 that as CO₂ content in natural gas increases, the two-phase envelope moves right and two-phase region becomes narrower. And critical point of natural gas moves to upper right (reaching a maximum), and finally it moves to lower right. The maximum critical pressure is 8.49 MPa when CO₂ is about 55.535 mol%. The closer the distribution ratio of CH₄ and CO₂, the larger the two-phase region. Furthermore, comparing the contents of CH₄ and CO₂, as one component becomes more predominant, the - diagram tends to approach the vapor pressure curve (- diagram of one component) of the major component. The critical pressure of natural gas with high CO₂ content increases with increasing CO₂ content in natural gas when CO₂ content in natural gas is below 55.535 mol%, while the critical pressure of high CO₂ content natural gas decreases with increasing CO₂ content in natural gas when CO₂ content in natural gas is above 55.523 mol%. But the critical temperature constantly increases with increasing CO₂ content in natural gas.

Figure 13: Calculated - phase diagrams and measured saturation pressure of natural gas with different CO₂ contents.

Figure 14: Variation curve of the critical points of natural gas with different CO₂ contents.

4.3. Phase Transition Observation Experiment

It can be seen from Section 4.2 that the critical temperature increases with increasing CO₂ content in natural gas. And in order to facilitate reducing the temperature, we chose the gas sample with CO₂ content of 75.323 mol% as the research object. The result of phase transition observation experiment is shown in Figures 15 and 16. We can draw the conclusion that phase transition of gas sample with CO₂ content of 75.323 mol% does not take place as pressure decreases from 42.34 MPa to 5 MPa at 35°C isothermal conditions, while phase transition of gas sample with CO₂ content of 75.323 mol% takes place as pressure decreases from 42.34 MPa to 5 MPa at −10°C isothermal conditions. The phase transition process is shown in the red dotted line part in Figure 16. The state of natural gas changes from the original transparent state into the mist. The testing results of phase transition observation experiment consist with the calculation results and testing results in Section 4.2 and, for the four gas samples, no phase transitions will take place at temperatures greater than 35°C. It also suggests that phase transition does not also take place at 75°C isothermal conditions and at 125°C isothermal conditions. It is illustrated that in the four gas samples no gas-liquid phase transition happens from bottom hole to well head.

Figure 15: Phase transition of high CO₂ content natural gas samples (75.323 mol%) in the process of pressure drawdown at 35°C.

Figure 16: Phase transition of high CO₂ content natural gas sample (75.323 mol%) in the process of pressure drawdown at −10°C.

5. Conclusions

Conclusions are as follows:

(1)For the four high CO₂ content gas samples, no phase transitions will take place at temperatures greater than 35°C. It is illustrated that in the four gas samples no gas-liquid phase transition happens from bottom hole to well head.(2)Relative volume and formation volume factor of four gas samples in this paper decrease with increasing pressure at isothermal conditions, while densities of four gas samples increase with increasing pressure at isothermal conditions. At isothermal conditions -factors of four gas samples decrease with increasing pressure at lower pressure range, that is, less than 18 MPa, while they increase with increasing pressure at higher pressure range, that is, higher than 18 MPa.(3)Relative volumes, formation volume factors, and -factors of four gas samples increase with increasing temperature at constant pressure conditions, while densities of four gas samples decrease with increasing temperature at constant pressure.(4)Formation volume factors and -factors of four gas samples decrease with increasing CO₂ content in natural gas at isothermal and constant pressure conditions, but relative volumes and volume factors do not change insignificantly. And densities of four gas samples increase with increasing CO₂ content in natural gas at isothermal and constant pressure conditions.(5)The deviations between the saturation pressure calculated by using the model proposed in this paper and experimental measured saturation pressure are very small; the average relative error is only 2.86%. Thus, the model can be used to predict the saturation pressure of high CO₂ content natural gas.(6)In the gas-liquid two-phase region, as CO₂ content in natural gas increases, the two-phase envelope moves right and two-phase region becomes narrower. And critical point of natural gas proposed in this paper moves to upper right (reaching a maximum) and then moves to lower right. The maximum critical pressure is 8.49 MPa when CO₂ content is about 55.535 mol%.

Conflict of Interests

Here, all the authors solemnly declare that there is no conflict of interests regarding the publication of this paper.

Acknowledgments

The authors wish to acknowledge anonymous reviewers for constructive comments and suggestions for improving this paper. The authors also wish to thank the anonymous Associate Editor for his handling of the paper and additional suggestions. This work was supported by National Science and Technology Major Project of China (no. 2011ZX05016-005-2) and a grant from the National Natural Science Foundation of China (no. 50604011).

References

Y. Hu, J. F. Du, P. Guo et al., “Experimental study on Z-factor of high CO₂ content natural gas,” Journal of Southern Yangtze University (Natural Science), vol. 6, no. 2, pp. 192–194, 2009.

H. Anping, D. Jinxing, Y. Chun, Z. Qinghua, and N. Yunyan, “Geochemical characteristics and distribution of CO₂ gas fields in Bohai Bay Basin,” Petroleum Exploration and Development, vol. 36, no. 2, pp. 181–189, 2009.

T. J. Hughes, M. E. Kandil, B. F. Graham, and E. F. May, “Simulating the capture of CO₂ from natural gas: new data and improved models for methane + carbon dioxide + methanol,” International Journal of Greenhouse Gas Control, vol. 31, pp. 121–127, 2014.

H. Sriyanta, M. A. Malek, M. A. Zulhairi et al., “Operational challenges in managing high CO₂ content gas production in Peninsular Malaysia operations,” in Proceedings of the International Petroleum Technology Conference, SPE 17082, Beijing, China, March 2013.

S. I. Putu and P. T. Pertamina, “Producing high CO₂ gas content reservoirs in Pertamina Indonesia using multi stage cryogenic process,” in Proceedings of the SPE Asia Pacific Oil and Gas Conference and Exhibition, SPE 134278, Brisbane, Australia, October 2010.

S. L. Li and Y. Hua, Condensate Gas Exploration and Development Technology, Sichuan Science and Technology Press, Chengdu, China, 2000.

X. Q. Bian, Z. M. Du, and Y. Tang, “Experimental determination and prediction of the compressibility factor of high CO₂ content natural gas with and without water vapor,” Journal of Natural Gas Chemistry, vol. 20, no. 4, pp. 364–371, 2011.

Y. Su, Y. Tang, Y. Xiao, H. Song, and X. Zhang, “Impacts of CO₂ content on the development indexes of volcanic gas reservoirs,” Natural Gas Industry, vol. 31, no. 8, pp. 69–72, 2011.

X. Q. Bian and Z. M. Du, “Experimental study on the phase behavior and fluid physical parameters of high CO₂-content natural gas,” Xinjiang Petroleum Geology, vol. 34, no. 1, pp. 63–65, 2013.

X. Bian, Z. Du, and Y. Tang, “Experimental determination and prediction of the compressibility factor of high CO₂ content natural gas with and without water vapor,” Journal of Natural Gas Chemistry, vol. 20, no. 4, pp. 364–371, 2011.

A. Jarrahian and E. Heidaryan, “A new cubic equation of state for sweet and sour natural gases even when composition is unknown,” Fuel, vol. 134, pp. 333–342, 2014.

M. Gazzani, E. Macchi, and G. Manzolini, “CO₂ capture in natural gas combined cycle with SEWGS. Part A. Thermodynamic performances,” International Journal of Greenhouse Gas Control, vol. 12, pp. 493–501, 2013.

C. W. Park, S. Y. Won, C. G. Kim, and Y. Choi, “Effect of mixing CO₂ with natural gas-hydrogen blends on combustion in heavy-duty spark ignition engine,” Fuel, vol. 102, no. 12, pp. 299–304, 2012.

T. H. Wong, M. Rahim, P. J. Anthony et al., “Challenges in determination of water content and condensed water in a multi-stacked sour gas field containing high CO₂ content offshore Malaysia,” in Proceedings of the International Petroleum Technology Conference, SPE 14413, Bangkok, Thailand, November 2011.

C. Q. Li, G. Q. Xue, M. Li et al., “Application of gas well production decline prediction methods to CO₂ gas reservoir,” Xinjiang Petroleum Geology, vol. 29, no. 5, pp. 613–615, 2008.

B. D. Al-Anazi, G. R. Pazuki, M. Nikookar, and A. F. Al-Anazi, “The prediction of the compressibility factor of sour and natural gas by an artificial neural network system,” Petroleum Science and Technology, vol. 29, no. 4, pp. 325–336, 2011.

J. A. Rushing, K. E. Newsham, K. C. van Fraassen et al., “Natural gas z-factors at HP/HT reservoir conditions: comparing laboratory measurements with industry-standard correlations for a dry gas,” in Proceedings of the CIPC/SPE Gas Technology Symposium Joint Conference, SPE 114518, Calgary, Canada, June 2008.

E. Heidaryan, J. Moghadasi, and M. Rahimi, “New correlations to predict natural gas viscosity and compressibility factor,” Journal of Petroleum Science and Engineering, vol. 73, no. 1-2, pp. 67–72, 2010.

F. Tabasinejad, R. G. Moore, S. A. Mehta, Y. Barzin, J. A. Rushing, and K. Edward, “Density of high pressure and temperature gas reservoirs: effect of non-hydrocarbon contaminants on density of natural gas mixtures,” in Proceedings of the SPE Western Regional Meeting, SPE 133595, Anaheim, Calif, USA, May 2010.

D.-Y. Peng and D. B. Robinson, “A new two-constant equation of state,” Industrial & Engineering Chemistry Fundamentals, vol. 15, no. 1, pp. 59–64, 1976.

W. A. Fouad and A. S. Berrouk, “Phase behavior of sour natural gas systems using classical and statistical thermodynamic equations of states,” Fluid Phase Equilibria, vol. 356, pp. 136–145, 2013.

M. Spiegel, S. Lipschutz, and J. Liu, Schaum's Outline of Mathematical Handbook of Formulas and Tables, McGraw-Hill, New York, NY, USA, 3rd edition, 2008.

H. Saffari and A. Zahedi, “A new alpha-function for the Peng-Robinson equation of state: application to natural gas,” Chinese Journal of Chemical Engineering, vol. 21, no. 10, pp. 1155–1161, 2013.

B. E. Poling, J. M. Prausnitz, and J. P. O’Connell, The Properties of Gases and Liquids, McGraw-Hill, New York, NY, USA, 2001.

C. L. Yaws, Chemical Properties Handbook, McGraw-Hill, New York, NY, USA, 1999.

B. D. Smith and R. Srivastava, Thermodynamic Data for Pure Compounds, Part A: Hydrocarbons and Ketones, Elsevier, Amsterdam, The Netherlands, 1986.

China National Oil and Gas Industry Standards, SY/T 6434-2000. Analysis for Natural Gas Reservoir Fluids Physical Properties, China National Oil and Gas Industry Standards, 2000.

R. C. Reid, J. M. Prausnitz, and B. E. Poling, The Properties of Gases and Liquids, McGraw-Hill, New York, NY, USA, 4th edition, 1987.

U. Setzmann and W. Wagner, “A new equation of state and tables of thermodynamic properties for methane covering the range from the melting line to 625 K at pressures up to 100 MPa,” Journal of Physical and Chemical Reference Data, vol. 20, no. 6, p. 1061, 1991.

C. R. Zhang and S. Y. Yu, The Test and Evaluation Methods of Carbon Dioxide Gas Well, Petroleum Industry Press, Beijing, China, 1999.

P. Shen, K. Luo, X. Zheng et al., “Experimental study of near-critical behavior of rich gas condensate systems,” in Proceedings of the SPE Production and Operations Symposium, SPE 67285, Oklahoma City, Okla, USA, March 2001.

Z. J. Lu, H. Tang, C. Q. Li et al., “Material balance equation for CO₂ gas reservoir considering phase state change,” Xinjiang Petroleum Geology, vol. 31, no. 6, pp. 617–620, 2010.

L. N. He, Carbon Dioxide Chemistry, Science Press, Beijing, China, 2013.

S. L. Li, Q. Z. Zhang, X. Q. Ran et al., Enhanced Oil Recovery Technology by Gas Injection, Sichuan Science and Technology Press, Chengdu, China, 2001.

M. Riva, M. Campestrini, J. Toubassy, D. Clodic, and P. Stringari, “Solid–liquid–vapor equilibrium models for cryogenic biogas upgrading,” Industrial & Engineering Chemistry Research, vol. 53, no. 44, pp. 17506–17514, 2014.