Dali Hou

Due to the harsh operating environment of gas turbines, their performance status will degrade with the growth of service life, which can even lead to unscheduled downtime in severe cases. The purpose of building the model is to provide guidance for the operation optimization and maintenance decision of the unit, and to improve the safety and reliability of equipment operation as much as possible. This paper uses BP neural network algorithm to establish a gas turbine health status assessment model, and verifies the accuracy of the model assessment through example analysis and research. The findings indicate that the model has demonstrated good evaluation performance and holds a certain level of practical significance in gas turbine health status assessment.

Low-permeability near-critical volatile reservoirs are characterized by light oil, complex fluid phase, and strong reservoir inhomogeneity, etc. Purely injecting CO₂ will create a series of problems, such as serious gas channeling, low sweep efficiency, and low oil recovery. Therefore, in this paper, through a combination of experiments and simulations and in the process of studying the problem from simple to complex, we carried out phase equilibrium experiments for CO₂-near-critical volatile oil and CO₂-near-critical volatile oil-formation water, as well as experiments for minimum miscible pressure of slim-tube with pure CO₂ and CO₂–water co-injection to the comparative study of the miscible characteristics and displacement oil efficiency between pure CO₂ injection and CO₂–water co-injection. It provides an important reference for improving oil recovery by CO₂–water co-injection in low-permeability near-critical volatile reservoir. The results of CO₂-near-critical volatile oil/CO₂-near-critical volatile oil-formation water phase equilibrium experiments show that the saturation pressure, density, and gas–oil ratio of the system increase, and the viscosity decreases with the increase in CO₂ injection. In the three-phase system of CO₂-near-critical volatile oil-formation water, the CO₂ content in the flash gas of crude oil, gas–oil ratio, and gas–water ratio are negatively correlated with the water saturation. The results of slim-tube experiments and simulations on the miscible characteristics and displacement oil efficiency of pure CO₂ injection and CO₂–water co-injection show that the recovery degree of crude oil under CO₂–water co-injection is higher than that of pure CO₂ injection, and the CO₂ dissolved transition section in oil and gas is shorter and the gas breakthrough time is later under CO₂–water co-injection, which effectively increases the sweep efficiency and improves the degree recovery of crude oil. When CO₂–water co-injection, the ratio of water is higher, the later the gas–oil ratio rises, the later the CO₂ breakthrough, and the higher the degree of crude oil recovery. It indicates that when CO₂–water co-injection, the ratio of water is higher, the more CO₂ is dissolved in water, which effectively inhibits the occurrence of gas channeling and increases the sweep area, thus improving the degree recovery of crude oil. The research results of this paper provide an experimental basis and theoretical foundation for CO₂–water co-injection for enhanced crude oil recovery in low-permeability near-critical volatile reservoirs.

The main source of production in the middle and late stages of shale gas extraction is the adsorbed gas in shale, and the adsorbed gas in shale mainly comes from organic matter casein and clay minerals in shale; therefore, this paper uses sodium-based montmorillonite to characterize the clay minerals in shale and study the CH₄ adsorption law in clay minerals, and this study has certain guiding significance for shale gas extraction. In addition, this paper also conducts a study on the competitive adsorption law of CH₄ and CO₂, and at the same time, predicts the theoretical sequestration of CO₂ in shale clay minerals, which is a reference value for the study of CO₂ burial in shale and is beneficial to the early realization of carbon neutral. In this paper, the slit model of sodium-based montmorillonite and the fluid model of CH₄ and CO₂ were constructed using Materials Studio software, and the following two aspects were studied based on the Monte Carlo method: Firstly, the microscopic adsorption behavior of CH₄ in sodium-based montmorillonite was studied, and the simulations showed that the adsorption capacity of montmorillonite decreases with increasing temperature, increases and then decreases with increasing pressure, and decreases with increasing pore size. CH₄ has two states of adsorption and free state in the slit. The adsorption type of CH₄ in montmorillonite is physical adsorption. Secondly, the competitive adsorption of CH₄ and CO₂ in sodium-based montmorillonite was studied, and the simulations showed that the CO₂ repulsion efficiency increased with increasing CO₂ injection pressure, and the CO₂/CH₄ competitive adsorption ratio decreased with increasing pressure. The amount of CO₂ storage decreased with increasing temperature and increased with increasing CO₂ injection pressure.

In this paper, the DBR all-visible mercury-free high-temperature and high-pressure multifunctional formation fluid PVT analyzer developed and produced by Schlumberger company is used to conduct an experimental study on phase behavior characteristics of one offshore high CO₂ condensate gas wells. The experiments include two-phase flash experiment, constant composition expansion experiment (CCE experiment), and constant volume depletion experiment (CVD experiment). Experimental results show that the higher the CO₂ content in the condensate gas system, the higher the gas-oil ratio of condensate gas, the greater the density of condensate oil, the higher the dew point pressure of condensate gas, the greater the relative volume of condensate gas, the smaller the amount of retrograde condensate oil. And the higher the CO₂ content in the condensate gas system, the phase diagram is shifted to the left and up, the critical point of the phase diagram is shifted to the lower left, the smaller the area of the two-phase envelope, the lighter the condensate gas system, the condensate oil recovery is higher. The above experimental results revealed that CO₂ is well soluble with condensate gas, the expansion capacity of the condensate gas system was slightly enhanced, and because CO₂ has a good extraction capacity, the light components of condensate gas were constantly extracted, the retrograde condensate rate of condensate oil decreases, and the maximum retrograde condensate volume also decreased. However, the condensate oil was produced along with the natural gas, and the higher the CO₂ content, the stronger the extraction, the more condensate oil was produced. It is mainly because CO₂ has the strong gasification and extraction capacity, on the one hand, the retrograde condensation of condensate gas was inhibited, and on the other hand, reverse evaporation of condensate oil was enhanced. The above experimental results indicate the law of the effect of CO₂ on the phase behavior characteristics of condensate gas reservoirs, providing theoretical basis and guidance for the efficient development of condensate gas reservoirs at sea.

Minimum miscibility pressure (MMP), which plays an important role in miscible flooding, is a key parameter in determining whether crude oil and gas are completely miscible. On the basis of 210 groups of CO ₂ ‐crude oil system minimum miscibility pressure data, an improved CO ₂ ‐crude oil system minimum miscibility pressure correlation was built by modified conjugate gradient method and global optimizing method. The new correlation is a uniform empirical correlation to calculate the MMP for both thin oil and heavy oil and is expressed as a function of reservoir temperature, C ₇₊ molecular weight of crude oil, and mole fractions of volatile components (CH ₄ and N ₂ ) and intermediate components (CO ₂ , H ₂ S, and C ₂ ~C ₆ ) of crude oil. Compared to the eleven most popular and relatively high‐accuracy CO ₂ ‐oil system MMP correlations in the previous literature by other nine groups of CO ₂ ‐oil MMP experimental data, which have not been used to develop the new correlation, it is found that the new empirical correlation provides the best reproduction of the nine groups of CO ₂ ‐oil MMP experimental data with a percentage average absolute relative error (%AARE) of 8% and a percentage maximum absolute relative error (%MARE) of 21%, respectively.

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 CO ₂ 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 CO ₂ 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 CO ₂ 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 CO ₂ content natural gas.

When a condensate gas reservoir with gaseous water under high temperature and high pressure condition is producing, the gaseous water and nonequilibrium effect will have great influences on the phase behavior of condensate oil and gas system and the accumulation of condensate liquid near the wellbore area. Therefore, a series of experiments were performed to investigate phase behavior of the condensate gas reservoirs with gaseous water using a PVT cell, in which the constant volume depletion process of nonequilibrium pressure drop and equilibrium pressure drop within near wellbore zone was simulated. And using the modified PR EOS, PR EOS, and nonequilibrium effect theory, the authors calculated the content of condensate oil and condensate liquid of the nonequilibrium pressure drop and equilibrium pressure drop and compared the calculated results with the experimental data. The results show that the modified PR EOS combined with nonequilibrium effect theory is more suitable for representing phase behavior characteristics of the development process of condensate gas reservoir containing gaseous water, with the average relative error of 4.49%. Furthermore, choosing the appropriate exploiting opportunity and properly increasing the nonequilibrium effect are helpful to increase condensate oil and water recovery.