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A multiphase flow model is an important foundation for well control simulation. In this paper, a multiphase variable mass flow model considering sudden density change was developed for variable gradient managed pressure drilling (MPD) and it was solved by finite difference method (FDM). Further, the model was used to simulate the whole process of well control based on constant bottom-hole pressure for variable gradient MPD. In this way, the advantages of the new gas kick detection method compared with the mud pit increment detection method and the variation laws of key parameters in the whole well control process were investigated. The results indicate that under the condition of small gas rate, the new gas kick detection method is better than the mud pit increment detection method because of its time savings. In the process of gas discharge, the wellbore pressure fluctuates due to the influence of gas expansion, sudden density changes at the separator position and annulus diameter changes at the casing shoe and mud line. The time when the back pressure reaches the maximum lags behind the time when the gas front reaches the wellhead. The mud pit increment increase rate when the gas front reaches the separator position is significantly higher than that in the early stage of gas kick detection.

In deep unconventional oil and gas development, the problem faced is that PDC bits are eroded by solid-liquid high-speed fluids, resulting in damage. It has led to serious damage to the stability of the drill bit, a decrease in the service life of the drill bit, and an increase in the difficulty in efficient drilling. The essence is that the surface hardness and erosion resistance of the drill bit are not strong enough. Therefore, improving the stability of drill bits is a crucial and urgent problem to be solved. In this paper, Ni60A + 20% WC + 0.3% graphene composite coatings were prepared on a Q235 steel substrate, which is a new type of high hardness coating. Moreover, the effects of microstructure and microhardness of the composite coatings at different laser powers (800 W, 1200 W, 1600 W, and 2000 W) were investigated. The results show that the laser power can significantly affect the microstructure of the coating. The phase composition of the composite coatings is essentially the same at different laser powers. However, there are significant differences in the content of each phase. When the laser power is higher than 1200W, the content of M23C6, Cr3C2 and Fe3C in the composite coating increases and the microhardness of the coating decreases. When the laser power is below 1200 W, the dilution rate of the substrate is low and a metallurgical bond cannot be formed between the composite coating and the substrate.

Among the existing gas storage facilities, salt cavern gas storage has the advantages of high injection production efficiency, low gas cushion volume, safety, flexibility, etc. It is of great significance to speed up the construction of underground gas storage by transforming abandoned salt caverns of salt industry into underground gas storage. However, old salt cavern wells cannot be directly converted into gas storage injection and production wells, so the old wellbore must be plugged to ensure the effectiveness of plugging. Therefore, a set of plugging optimization technology for salt cavern gas storage wells is urgently needed. In this paper, a 3D finite element model of the cement plug-formation system based on cohesive element method is established for the milling and plugging of the old well in the salt cavern gas storage section. The results show that under the condition of constant gas storage pressure, a certain degree of small deformation will occur at the bottom of the cement plug after compression, resulting in the shear direction deformation of the cement plug formation cementation interface, and peeling will occur after accumulation to a certain extent. With the increase of simulation time, the length of stripping section gradually increases and tends to be stable, and reaches the limit of stripping failure length. In the process of research, the factors and laws affecting the stripping failure length were also analyzed. It was found that the stripping failure length of cement plug formation cementation interface was related to the maximum operating pressure of gas storage, cement plug length, cement plug diameter, elastic modulus, Poisson’s ratio and other factors. The research results are helpful to judge whether the milling and plugging length of the old well section is sufficient, and provide theoretical guidance for ensuring the long-term safe operation of the gas storage.

Dual-gradient drilling technology is being increasingly used in formations with narrow pressure margins. For dual-gradient drilling based on downhole separation, hollow spheres are separated into the annulus at the separator position, resulting in variable mass flow in the wellbore. Thus, existing heat transfer models are no longer suitable for describing wellbore temperature profiles in dual-gradient drilling. This study focused on developing a wellbore heat transfer model that fully considers separated hollow spheres entering the annulus, complex casing programs, and heat sources, for dual-gradient drilling based on downhole separation. The model was solved using an iterative method. Then, the accuracy of the model was verified using temperature data measured from two wells. Finally, the difference in the annular temperature distributions between dual-gradient drilling and conventional single-gradient drilling were investigated, as were the wellbore heat transfer characteristics for dual-gradient drilling. The following major conclusions were drawn: (1) for dual-gradient drilling based on downhole separation, at the separator location, the annular fluid temperature does not decrease, but rather increase in the flow direction because of the inflow of hollow spheres; (2) a clear inflection point exists in the annular fluid temperature curve at the location where the separator would be; (3) the magnitude of the mutation of the temperature curve at the inflection point is considerably affected by the heat capacities of the hollow spheres and the pure drilling fluid; (4) under the same change in separation efficiency, distance between the bit and separator, flow rate, and thermal conductivity of formation, the variation range of the fluid temperature at the bottom hole is greater than that at the wellhead.

Abstract In deepwater drilling, accurate prediction of wellbore gas‐liquid two‐phase flow behavior is significant for gas kick detection and well‐control treatment. In this study, a new transient gas‐liquid two‐phase flow model was developed to simulate the wellbore gas‐liquid two‐phase flow during gas kick in deepwater dual‐gradient drilling based on downhole separation. This model accounts for the impact of a sudden change in density on gas‐liquid flow behavior. The transient model was solved using the finite‐difference method. The accuracy and stability of the model were verified using data measured from a full‐scale experimental well. Using this model, the differences in the apparent liquid velocity and the flow rate at the annular outlet during gas kick were compared between deepwater dual‐gradient drilling and conventional single‐gradient drilling. Additionally, the influences of numerous factors on variations in flow rate at the annular outlet were also studied. A new method of early gas kick detection was proposed for deepwater dual‐gradient drilling based on downhole separation.

To ensure safe drilling with narrow pressure margins in deepwater, a new deepwater dual-gradient drilling method based on downhole separation was designed. A laboratory experiment was conducted to verify the effectiveness of downhole separation and the feasibility of realizing dual-gradient in wellbore. The calculation of dynamic wellbore pressure during drilling was conducted. Then, an optimization model for drilling parameters was established for this drilling method, including separator position, separation efficiency, injection volume fraction, density of drilling fluid, wellhead back pressure and displacement. The optimization of drilling parameters under different control parameters and different narrow safe pressure margins is analyzed by case study. The optimization results indicate that the wellbore pressure profile can be optimized to adapt to the narrow pressure margins and achieve greater drilling depth. By using the optimization model, a smaller bottom-hole pressure difference can be obtained, which can increase the rate of penetration (ROP) and protect reservoirs. The dynamic wellbore pressure has been kept within safe pressure margins during optimization process, effectively avoiding the complicated underground situations caused by improper wellbore pressure. Key words: narrow pressure margins, deepwater dual-gradient drilling, drilling parameters, optimization model, maximum drilling depth

The technical focus of drilling operations is changing to oil and gas reservoirs with higher difficulty factors such as low permeability and fracture. During the drilling process, drilling operations in deep complex formations are prone to overflow and leakage complications. Leakage and overflow problems will change the performance of the drilling fluid in the wellbore, impacting the wellbore pressure, and causing complex accidents such as stuck drilling and collapse. In order to improve the level of control over the risk of wellbore overflow and leakage, it is necessary to predict the mud overflow and leakage situation and to arrange and control the risk of leakage and overflow that may occur in advance to ensure the safety of drilling. By using a genetic algorithm to optimize the multi-layer feedforward neural network, this paper establishes a GA-BP Neural Network Drilling overflow and leakage prediction model based on multi-parameter fusion. Through the optimization training of 14 parameters that may affect the occurrence of complex downhole accidents, the mud overflow and leakage are predicted. The prediction results of the model are compared with the prediction results of a conventional BP neural network, and verified by the real drilling data. The results show that the MAE, MSE, and RMSE of the GA-BP neural network model are improved by 2.91%, 4.48%, and 10.93%, respectively, compared with the BP neural network model, and the prediction quality is higher. Moreover, the amount of mud overflow and leakage predicted by using the GA-BP neural network matches well with the pattern of mud overflow and leakage data in real drilling, which proves the effectiveness and accuracy of the GA-BP neural network in overflow and leakage prediction.

Multi-gradient drilling is a new offshore drilling method. The accurate calculation of the related wellbore temperature is of great significance for the prediction of the gas hydrate formation area and the precise control of the wellbore pressure. In this study, a new heat transfer model is proposed by which the variable mass flow is properly taken into account. Using this model, the effects of the main factors influencing the wellbore temperature are analyzed. The results indicate that at the position where the separation injection device is installed, the temperature increase of the fluid in the drill pipe is mitigated due to the inflow/outflow of hollow spheres, and the temperature drop of the fluid in the annulus also decreases. In addition, a lower separation efficiency of the device, a shallower installation depth and a smaller circulating displacement tend to increase the temperature near the bottom of the annulus, thereby helping to reduce the hydrate generation area and playing a positive role in the prevention and control of hydrates in deepwater drilling. [ABSTRACT FROM AUTHOR]