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Volume 2019 |Article ID 8627698 | https://doi.org/10.1155/2019/8627698

Rui Deng, Chengsheng Chen, Shuyong Shi, Yunpeng Wang, "Fluid Phase Simulation and Evolution of a Condensate Gas Reservoir in the Tazhong Uplift, Tarim Basin", Geofluids, vol. 2019, Article ID 8627698, 15 pages, 2019. https://doi.org/10.1155/2019/8627698

Fluid Phase Simulation and Evolution of a Condensate Gas Reservoir in the Tazhong Uplift, Tarim Basin

Academic Editor: Julien Bourdet
Received30 Jan 2019
Revised01 May 2019
Accepted27 May 2019
Published13 Jun 2019

Abstract

The fluid phase and the evolution of the condensate gas reservoir in the Lianglitage Formation (O3), Well ZG7-5, Tazhong Uplift, were studied by integrating the PVTsim and the PetroMod software. The fluid phase was successfully simulated, and the burial, temperature, pressure, and pressure coefficient histories were reconstructed. The evolution of the fluid phase and its properties (density, viscosity, and gas-oil ratio) under the ideal and gas washing conditions was also explored. The simulated pressure-temperature () phase diagram confirms that the reservoir fluid is in the condensate gas phase at present, with an order of critical point-cricondenbar-cricondentherm (). The temperature and pressure show an overall increasing trend considering the entirety of geological evolution. Under ideal conditions, fluid transition from coexisting gas and liquid phases to a single condensate gas phase occurred during the Late Cretaceous (80 Ma, , and ). The density and viscosity of the liquid phase decreased gradually while the density and viscosity of the gas phase and the solution gas-oil ratio increased during geological processes. With the consideration of gas washing, the critical phase transition time points for 100% and 50% gas washing fluid are 394 Ma, 383 Ma, 331 Ma, and 23 Ma, as well as 266 Ma and 23 Ma, respectively. The average liquid phase density, gas phase density, and liquid phase viscosity under 100% gas washing are larger than those under 50% gas washing before 23 Ma (Miocene), while the gas phase viscosity values are similar for both cases. This study visually suggests that the temperature and pressure histories, which are controlled by the burial history and heat flow evolution, and gas washing have significant impacts on the formation of the condensate gas reservoirs and evolution of the fluid phase and its features in the Tazhong Uplift.

1. Introduction

The Tazhong Uplift is the most important oil and gas bearing area in the Tarim Basin of China. In recent decades, many different types of petroleum reservoirs have been discovered in the Tazhong Uplift, and the phase states of reservoir fluids vary among sand tar, super heavy oil, heavy oil, black oil, normal oil, light oil, condensate gas, and natural gas [1]. The condensate gas reservoirs serve as highly valued resources for energy supply, and their characteristic phase transitions during the accumulation and exploitation processes make them valuable for research [2].

Knowledge of the phase state and pressure-volume-temperature (PVT) properties of reservoir fluids is critical to the exploration and development of the reservoirs and, therefore, of interest in petroleum engineering studies [3, 4]. For all conventional and unconventional petroleum reservoirs, it is essential to reconstruct the phase evolution history and the changes in the gas-oil ratio (GOR) and physical properties of the fluid over time, which are all closely related to the burial and thermal histories of the fluid [5]. In many previous works, phase simulation experiments have been conducted under high temperature and pressure using PVT-based methods to obtain PVT properties and determine the phase types of reservoir fluids; however, such experiments are complicated, time-consuming, and difficult to conduct [610]. In addition, the fluid phase and evolution of condensate gas reservoirs in the Tazhong Uplift have not been intensively studied; there is a lack of systematic studies on the temperature and pressure recoveries for condensate gas reservoirs in the area, as well as a lack of the combination with PVT simulation and basin modeling. Therefore, the purpose of this study was to explore the fluid phase and evolution of a typical condensate gas reservoir, Well ZG7-5, in the Tazhong Uplift. We first simulated the phase envelope and PVT properties of the fluids by using the PVTsim software, which is an easy-to-use and widely used software for the phase simulation of reservoir fluids. We then reconstructed the burial, temperature, pressure, and pressure coefficient evolution histories of the target reservoir using the PetroMod software. Finally, we studied the evolution of the fluid phase and its features (density, viscosity, and solution GOR) under ideal and gas washing conditions considering the entirety of geological evolution, by integrating the results of the PVTsim and the PetroMod software.

2. Geological Setting

The Tarim Basin, encompassing an area of 560,000 km2, is the largest petroleum-bearing basin in China and is also one of the most complex superimposed basins in the world [11, 12]. This basin is characterized by thick sediments, multiple cycles of uplift and erosion, and complex distribution of oil and gas accumulations [13]. The Tazhong Uplift is a long-term inherited paleouplift in the central Tarim Basin, which was formed during the Caledonian orogeny and shaped by the Early Hercynian orogeny [14]; its tectonic framework did not significantly change during the subsequent Indosinian-Himalayan orogeny [15]. The oil and gas in the Tazhong Uplift are mainly distributed in the Cambrian, Ordovician, Silurian, and Carboniferous strata, and most condensate gas reservoirs are found in the Ordovician reservoirs originated from the Cambrian-Lower Ordovician strata and the Middle-Upper Ordovician source rocks [16]. The Tazhong Uplift can be subdivided into several belts including the Tazhong no. 1 fault zone, Tazhong no. 10 structural belt, Tazhong central horst belt, and Tazhong 1-8 buried hill belt [17, 18]. Well ZG7-5 is in the Tazhong no. 1 gas field and is located on the north slope of the Tazhong Uplift (Figure 1). The borehole depth of Well ZG7-5 reaches 5718 m, encountering strata from the Quaternary to the Ordovician. The condensate gas reservoir was discovered in the Lianglitage Formation (O3, 5655-5718 m) where there is a daily gas production of 20399 m3 but little oil production (inner report of the Tarim Oil Company, 2016).

3. Materials and Methods

3.1. Fluid Phase Simulation

The PVTsim software by the Calsep Company specializes in the calculation of fluid properties, employing several different equations of state (EOS); it is widely used in oil and gas reservoir studies [20]. The input data for the PVTsim software include well fluid components (C1-C30+, molecular weight), constant mass expansion experimental data, and constant volume depletion experimental data; these were all derived from the PVT analysis report for Well ZG7-5 (inner report of the Tarim Oil Company, 2016) (Tables 1 and 2). The data in the report were measured using a phase analyzer (Schlumberger DBR) and a gas chromatograph (Agilent 7890A, 6890N). The simulation steps are as follows: First, the well fluid components (C1-C30+, molecular weight) listed in Table 1 were input to the PVTsim software. The original phase diagram showing the temperature and pressure of the critical point (), cricondentherm (), and cricondenbar () was obtained after initially simulating with the Peng-Robinson equation of state (Figure 2(a)). Then, the relevant constant mass expansion experimental data and constant volume depletion experimental data listed in Table 2 were used to conduct a regression calculation. Afterward, the simulated values of , , and were tuned to achieve as much consistency as possible with the measured values by altering the parameters of EOS [21]. The final phase model was determined when the simulated phase diagram was close to the measured one after repeated calculation and tuning; this simulated phase diagram was regarded as being representative of the actual fluid in the reservoir (Figure 2(b)). Additionally, the positional order of the critical point (), cricondentherm (), cricondenbar (), and in situ petroleum reservoir conditions (, ) in the phase diagram was used to identify the type of reservoir fluid.


ComponentsMol%Molecular weightComponentsMol%Molecular weight

N24.23228.014C140.334190
CO23.07544.01C150.260206
C183.08316.043C160.177222
C20.36430.07C170.143237
C30.20644.097C180.118251
iC40.07858.124C190.102263
nC40.20358.124C200.091275
iC50.14772.151C210.089291
nC50.17272.151C220.085305
C60.28086.178C230.075318
C70.31596C240.059331
C81.645107C250.054345
C91.374121C260.041359
C101.135134C270.024374
C110.867147C280.014388
C120.624226C290.007402
C130.518175C30+0.011416


WellConstant mass expansion experimentConstant volume depletion experiment
Pressure (MPa)Temperature (°C)Liquid vol% of VdPressure (MPa)Temperature (°C) factor gas

ZG 7-561.46102.60.0056.81142.61.374
59.16122.60.00
56.81142.60.00

Dew point pressure.
3.2. One-Dimensional Basin Modeling
3.2.1. One-Dimensional Basin Modeling Method

The temperature and pressure histories of the Lianglitage Formation (O3), Well ZG7-5, were determined by reconstructing a geological model using the PetroMod 2016 (1D) software by Schlumberger Limited. The input parameters for this purpose include stratigraphy (age, thickness, and lithology), tectonic events (unconformities, erosion time, and erosion thickness), and boundary conditions (heat flow, paleowater depth, and sediment-water interface temperature) [2224]. During the simulation process, the measured temperature and maturity values were used to validate the modeling results. The burial, temperature, pressure, and pressure coefficient evolution histories of the target reservoir were confirmed when the modeled and measured results were consistent.

3.2.2. Input Data for One-Dimensional Basin Modeling

Erosion events have a significant influence on both the burial and thermal histories. The modeled stratigraphic succession of Well ZG7-5 starts from the Quaternary and continues down to the Lianglitage Formation (Ordovician), excluding the Jurassic, Devonian, and Upper Silurian strata which show the effects of multiple tectonic events. The concrete values of erosion thickness and erosion time were collected from Zhang et al. [25], Pang et al. [26], and Qi and Liu [27]. The main deposition and erosion events are listed in Table 3. The data for stratigraphy (age, thickness, and lithology) were gathered from the logging report from the Tarim Oil Company.


Age (Ma)StrataDepth (m)Erosion thickness (m)Lithology

0Top N+Q0Sandstone, shale
23Top E1200Sandstone
66Top K1834Sandstone, shale
144Erosion J-150
163Top J150Sandstone, shale
201Top T2390Shale, siltstone, conglomerate
247Erosion P-150
254Top P2906150Shale, siltstone, conglomerate
298.9Top C3562Shale, sandstone, limestone
358Erosion D-700
387Top D700Sandstone
417.6Erosion S-100
427.4Top S4140100Sandstone, shale, siltstone
442Erosion O3s-900
443Top O3s4482900Shale
453.4Top O3l1-25333Limestone, sandstone
454.9Target layer5457Limestone
458Erosion O1ys-250
459.9Erosion O2yif-100
460.7Erosion O2t-50
461Top O2t50Limestone
464.7Top O2yjf100Limestone
470Top O1ys5711250Limestone, dolomite
479.5Top O1p6261Dolomite, limestone
485.4Base6761

In terms of the boundary conditions, the heat flow values are vital to unearthing the reservoir thermal maturity history. Values of heat flow were derived from Qiu et al. [28], Wang et al. [29], and Feng et al. [30]. The values of the paleowater depth (PWD) were estimated by sedimentary facies type and lithology, which are closely related to variations in the global sea level. The sediment-water interface temperatures (SWIT) were calculated using the PetroMod software upon identification of the location of the well. The plots for the concrete boundary conditions are presented in Figure 3. The temperature and maturity values measured for calibration were taken from the logging report and laboratory measurements by the Tarim Oil Company.

Finally, evolution of the fluid phase and its features (density, viscosity, and solution GOR) under ideal and gas washing conditions was studied by integrating the phase diagram from running the PVTsim software and the temperature-pressure values at each critical geological event point, derived by the PetroMod software.

4. Results and Discussion

4.1. P-T Phase Diagram for the Fluid

As mentioned above, the final phase diagram for the fluid was arrived at after several rounds of calculation and tuning, and the corresponding fluid features were calculated. Table 4 presents a comparison between the simulated and measured values of the fluid features of Well ZG7-5. The modeled features are consistent with the measured results. Further, the modeled density of oil on the ground and the solution GOR show relatively large errors because oil density was measured with the loss of some light fractions, and the produced GOR, which slightly differs from the solution GOR, was measured. These comparisons illustrate that the modeling results are valid and the method is effective. The simulated phase diagram for the fluids in the Lianglitage reservoir (O3) is displayed in Figure 4. It can be seen that the temperature and pressure of the critical point () are -83.8°C and 30.25 MPa, respectively, and the cricondentherm () and cricondenbar () are 397.67°C and 58.95 MPa, respectively. Furthermore, the phase diagram is divided into the liquid phase zone, the condensate gas phase zone, the gas phase zone, and the coexistence phase zone for gas and liquid, by the positional order of the critical point (), cricondentherm (), and cricondenbar (). Based on the phase zone distribution of the diagram and the in situ reservoir conditions (, ), the in situ reservoir fluid was classified as being of the condensate gas phase type. Under the conditions of normal temperature and pressure (20°C, 0.101 MPa), the fluid returns from the condensate gas phase to two separate phases of gas and liquid, which coincides with the current product type and macro compositions.


ItemsSimulated valuesMeasured values

Critical temperature (°C)-83.80-77.80
Critical pressure (MPa)30.2529.25
Cricondentherm (°C)397.67386.30
Cricondenbar (MPa)58.9557.71
Dew point pressure(142.6°C) (MPa)58.0056.81
Oil density at ground(20°C) (g/cm3)0.720.80
Solution gas-oil ratio (GOR) (m3/m3)883823

Measured with some loss of volatile fractions. Produced GOR.
4.2. Histories of Burial, Temperature, Pressure, and Pressure Coefficient

As can be seen from Figure 5, the measured and modeled values of temperature and vitrinite reflectance (Ro) fit well, indicating the reliability of burial, temperature, pressure, and pressure coefficient histories modeled using the PetroMod software.

The burial history overlaying with the thermal maturity history of Well ZG7-5 is shown in Figure 6, which indicates that the Tazhong Uplift has experienced multiple stages of uplift and erosion caused by multiple orogenies. Among all these orogenies, the Caledonian and Hercynian orogenies had the most crucial impact on the study area. The Tarim Basin experienced a period of stable platform development during the Cambrian-Early Ordovician and encountered a slight erosion during the Late Middle Ordovician. Subsequently, the rapid subsidence and the following strong erosion of strata caused by the Middle Caledonian orogeny were the significant features of the Late Ordovician. This orogeny was also characterized by the strongest uplift and erosion (900 m) during the entire geological evolution history in the study area. During the Late Devonian, the Hercynian orogeny caused another strong uplift and erosion (700 m). The combined Caledonian and Hercynian orogenies caused an erosion thickness of more than 2000 m, and the Ordovician strata reached high-mature states (1.3-2.0%Ro) at the beginning of the Permian period. The orogeny events following this period had little impacts on the maturity. Currently, the Ordovician strata are buried to the maximum depth of over 6000 m.

Figure 7 shows the temperature and pressure histories of the Lianglitage Formation (O3) in Well ZG7-5. The temperature history is significantly linked with the heat flow evolution and the burial history, while the pressure history is correlated with the burial history and lithology. Both the temperature and pressure histories depict overall increasing trends from the Ordovician to the present; however, decreasing trends caused by erosion events, heat flow changes, or lithology variations were also observed. Moreover, the pressure coefficients throughout the evolution history were also calculated by the results derived from PetroMod (Figure 8). During the early stages, the reservoir was in normal pressure condition; these conditions changed to the state of overpressure () during the Middle Permian (265 Ma) due to the deepening of the burial depth. After the Miocene, the pressure coefficient increased rapidly.

4.3. The Evolution of the Fluid Phase and Features
4.3.1. Ideal Conditions

Under ideal conditions, we assumed that the reservoir was formed without any destruction or change and the composition of the reservoir fluid was constant during the entire geological process. The simulated phase envelope and the modeled temperature-pressure values (labeled as the line) at each time point of a critical geological event were overlapped in the same plot to investigate the reservoir evolution processes (Figure 9). The figure clearly shows that the line goes across the coexisting phase zone of the gas and liquid to the condensate gas phase zone and the turning point (135.7°C, 58.19 MPa) corresponding to the age of 80 Ma (Late Cretaceous) appears at the point of intersection of the two lines. This suggests that the Lianglitage Formation (O3) existed in the two-phase states of gas and liquid from Ordovician to 80 Ma (Late Cretaceous) but, thereafter, turned to the condensate gas phase. This phenomenon clearly indicates that the condensate gas reservoir was formed after 80 Ma (Late Cretaceous) due to the changes in temperature and pressure conditions, which, in turn, were the result of the combined effect of multiple orogenies (the change of burial depth), as well as the heat flow evolution.

The changes in temperature and pressure controlled by heat flow evolution and multiple orogenies also affected fluid features. The evolutions of density, viscosity, and solution GOR during the entire geological processes are presented in Figure 10. From Ordovician to 80 Ma (Late Cretaceous), the fluid in the reservoir was composed of coexisting gas and liquid phases. The density of the liquid phase decreased gradually, while that of the gas fluctuated greatly and generally increased. On the contrary, the viscosity of the liquid phase fluctuated greatly, showing an overall decreasing trend and that of gas gradually increased. The fluctuations in density and viscosity are synchronized with the wave of burial depth. After 80 Ma (Late Cretaceous), the fluid turned into the condensate gas phase with increasing temperature and pressure. At the same time, the density and viscosity of the gas continually increased to reach the present values of 0.44 g/cm3 and 0.0693 cP, respectively (Figures 10(a) and 10(b)). In the solution GOR, the amount of gas increased continuously; an increasing number of liquid hydrocarbons underwent the retrograde evaporation processes with continuous deep burial. This led the solution GOR to depict an overall increasing trend throughout the well-formation history; its value eventually reached 883 m3/m3 (Figure 10(c)). As mentioned above, after the Middle Permian (265 Ma), the overpressure state dominated the reservoir environment and the pressure coefficient increased rapidly after the Miocene. It is believed that the fluid expansion caused by retrograde evaporation is the main reason for the formation of overpressure. Moreover, the changes in pressure coefficient are also indirectly related with the alterations in GOR.

4.3.2. Gas Washing Conditions

From previous studies, it is known that oil charging occurred mainly in the Late Caledonian and Late Hercynian periods and that the gas filling that occurred mostly during the Late Himalayan period is one of the formation mechanisms of the condensate gas reservoirs in the Tazhong area [31]. In this context, it is hypothesized that the condensate gas reservoir of Well ZG7-5 was formed due to gas washing during the Late Himalayan. This assumes two different gas washing conditions: one, that the initial methane content is 0% (before being normalized) and that all the methane was a product of gas washing; therefore, the degree of gas washing can be set to 100%; the other is that half the methane (before being normalized) was from gas washing, and therefore, the gas washing degree can be set to 50%. The specific fluid components (C1-C30+) for these two cases are listed in Table 5 (only the amount of methane was varied; the other components were kept constant). We also assumed that 23 Ma (Late Himalayan) was the time at which the gas washing occurred, based on previous studies [32, 33]. The methods described above were then used to study the process of evolution with gas washing. The fluid phase evolution diagram of the Lianglitage Formation (O3) in Well ZG7-5, considering gas washing, is shown in Figure 11. The phase diagram in Figure 4 was also plotted in Figure 11 to represent the final phase diagram of the gas-washed fluid.


Gas washing degreeComponents (%) (after normalized)

100%N2CO2C1C2C3iC4nC4iC5nC5C6C7C8C9C10C11C12C13
25.01318.1750.0002.1511.2180.4611.2000.8691.0171.6551.8629.7238.1216.7085.1243.6883.062
C14C15C16C17C18C19C20C21C22C23C24C25C26C27C28C29C30+
1.9741.5371.0460.8450.6970.6030.5380.5260.5020.4430.3490.3190.2420.1420.0830.0410.065
50%N2CO2C1C2C3iC4nC4iC5nC5C6C7C8C9C10C11C12C13
7.2505.26871.0140.6240.3530.1340.3480.2520.2950.4800.5402.8182.3541.9451.4851.0690.887
C14C15C16C17C18C19C20C21C22C23C24C25C26C27C28C29C30+
0.5720.4450.3030.2450.2020.1750.1560.1520.1460.1280.1010.0930.0700.0410.0240.0120.019

In the 100% gas washing case, its initial phase diagram stayed in the high temperature and low pressure area because of the limited gas content and its critical point is 344.19°C and 11.79 MPa (Figure 11(a)). The fluid clearly existed as two phases, gas and liquid, from the Ordovician to the Middle Devonian (394 Ma). The fluid then transitioned quickly to the liquid phase before 383 Ma (Middle Devonian) and returned to the two-phase state again due to the changes in temperature and pressure conditions. After 331 Ma (Early Carboniferous), the fluid stayed in the liquid phase but turned into the condensate gas phase with gas washing in 23 Ma (Miocene) (Figure 11(a)).

There are some differences in the phase transition of the fluid when 50% of the gas was washed compared to when 100% of the gas was washed. The initial phase diagram of the former is in a lower temperature and higher pressure area compared to the latter because of its higher gas content, and its critical point is 149.09°C and 40.59 MPa (Figure 11(b)). The phase of the fluid remained in the two-state phase from the Ordovician to the Middle Permian (266 Ma), lasting longer than in the 100% gas washing case. Then, from 266 to 247 Ma (Middle Permian-Early Triassic), the fluid stayed in the liquid phase, with only a brief transition to the two-state phase. Finally, the fluid transitioned from the liquid phase to the condensate gas phase after gas washing in 23 Ma (Miocene). The occurrence time of the gas phase in the 50% gas washing case is longer than the 100% gas washing case. Thus, the critical phase turning time points for the 100% and 50% gas-washed fluid are 394, 383, 331, and 23 Ma, as well as 266 and 23 Ma, respectively.

The evolution of fluid density and viscosity in these two cases was also studied using the methods described above, and the results are shown in Figure 12. The figure also clearly shows the change of phase state. In the 100% gas washing case, the density of the liquid phase remained basically the same, fluctuating slightly in the 0.69-0.73 g/cm3 range, while the gas phase existed for a shorter time but had values that changed more obviously (Figure 12(a)). Conversely, there was great fluctuation in the viscosity of the liquid phase but little fluctuation in the gas phase viscosity (Figure 12(b)).

In the 50% gas washing case, the fluctuations in density and viscosity were greater than those of the 100% gas washing case (Figures 12(c) and 12(d)). The density of the liquid phase first fluctuated greatly, with an overall decreasing trend, and then gradually increased. The density of the gas phase shows an increasing trend throughout. The sharp changes between 350 and 266 Ma (Early Carboniferous-Middle Permian) are believed to have been caused by the continuous burial and the high heat flow value during the Carboniferous and Permian (Figure 12(c)) [34, 35]. The viscosity of the liquid phase also changed greatly while the viscosity of the gas phase increased gradually (Figure 12(d)). In general, the average liquid and gas phase densities and the liquid phase viscosity of the 50% gas washing case are smaller than those of the 100% gas washing case before 23 Ma (Miocene), whereas their gas phase viscosity values are similar. These results indicate that the degree of gas washing has a great impact on the fluid phase, phase transition point, and fluid features.

5. Conclusions

The simulated phase diagram confirms that the studied reservoir is presently in the condensate gas phase, in the order . The modeled burial history shows that the Tazhong Uplift experienced multiple stages of uplift and erosion caused by multiple orogenies. The modeled temperature and pressure histories influenced by the burial history and the evolution of the heat flow show an overall increasing trend from the Ordovician to the present. The reservoir experienced overpressure after the Middle Permian (265 Ma) because of the increasing pressure caused by the continuous subsidence; the pressure coefficient also increased rapidly after the Miocene.

Under ideal conditions, the reservoir fluid was assumed to have formed without any destruction or change. The simulated results show that 80 Ma (Late Cretaceous, , ) was a key point in the phase transition from the two-state gas and liquid phases to the single-state condensate gas phase that led to the formation of the present condensate gas reservoir. The density and viscosity of the liquid phase decreased gradually while the density and viscosity of the gas phase increased with the increasing temperature and pressure during geological processes. The solution GOR increased throughout the history of the reservoir and eventually reached 883 m3/m3.

Taking the gas washing into consideration, it is hypothesized that the condensate gas reservoir was formed due to gas washing that occurred in the Late Himalayan (23 Ma). The simulations of gas washing degrees of 100% and 50% were designed to study how the gas washing affected the evolutionary history of the fluid phase. The results show that the critical time points in the change in the 100% and 50% gas washing cases are 394, 383, 331, and 23 Ma, as well as 266 and 23 Ma, respectively. The average liquid and gas phase densities and the liquid phase viscosity of the 100% gas washing case are greater than those of the 50% gas washing case before 23 Ma (Miocene). The gas phase viscosity of the two cases is similar.

The formation of condensate gas reservoirs in the Tazhong Uplift is associated not only with the changes in temperature and pressure controlled by burial history and the evolution of heat flow but also with the gas washing that occurred during the Late Himalayan, which played a critical role in forming the condensate gas reservoirs. This study confirms that both of these processes could result in the formation of condensate gas reservoirs. Moreover, it indicates that the method of integrating the PVTsim and the PetroMod software to study the phase simulations and evolution of a reservoir is useful and effective.

Data Availability

The data used to support the findings of this study are available from the corresponding author upon request.

Conflicts of Interest

The authors declare that there are no conflicts of interest regarding the publication of this paper.

Acknowledgments

This work was supported by the Strategic Priority Research Program of the Chinese Academy of Sciences (XDA14010103), the China National Major S&T Program (2017ZX05008-002-030), the GIG 135 Project (No. 135TP201602), and the NSFC Project (41372137). This is contribution No. IS-2716 from the Guangzhou Institute of Geochemistry, Chinese Academy of Sciences.

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