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Abstract With the progression of many shale gas wells in the Sichuan-Chongqing region of China into the middle and late stages of exploitation, the problem of sand production in these wells is a primary factor influencing production. Failure to implement measures to remove sand from the gas wells will lead to a sharp decline in production after a certain period of exploitation. Moreover, As the amount of sand produced in the well increases, the production layer will be potentially buried by sand. To boost the production of shale gas wells in the Sichuan-Chongqing region and improve production efficiency, a novel downhole jet sand-washing device has been developed. Upon analyzing the device's overall structure, it is revealed that the device adopts a structural design integrating a jet pump with an efficient sand- washing nozzle, providing dual capabilities for jet sand- washing and sand conveying via negative pressure. To enhance the sand- washing and unblocking performance of the device, various sand- washing fluids and the structures of different sand- washing nozzles are compared for selection, aiming to elevate the device's sand- washing and unblocking performance from a macro perspective. Subsequently, drawing on simulation and internal flow field analysis of the device's sand- washing and unblocking process through CFD and the control variable method, it is ultimately found that the length diameter ratio of the cylindrical segment of the nozzle outlet, the outlet diameter, and the contraction angle of the nozzle greatly influence the device's sand- washing and unblocking performance. And the optimum ranges for the length-diameter ratio of the cylindrical segment of the nozzle outlet, the outlet diameter, the contraction angle of the nozzle, and the inlet diameter are 2 to 4, 6 mm to 10 mm, 12° to 16°, and 18 mm and 22 mm, respectively. The findings of the research not only provide new insights into existing sand removal processes but also offer a novel structure for current downhole sand removal devices and a specific range for the optimal size of the nozzle.

Considering the current limitations and restricted scope of existing experiments, as well as the absence of corresponding numerical simulation verifications and comparisons, and the lack of actual case studies of variable mass flow calculation and comparison, this study focuses on high production oilfields in the Mideast and South China Sea. The objective is to investigate single-phase and multiphase variable mass flow through numerical and experimental simulations. The study develops linear regression equations to establish the relationship between the mixture pressure drop caused by side flow and the velocities of the main flow, as well as the ratio between side and main flow velocities. Actual calculations using these equations are provided. The comprehensive analysis reveals that, for a fixed total flow rate, an increase in the side versus main injection velocity ratio leads to an increase in pressure loss before and after the injection hole. In single-phase flow, the friction factor for side hole flow is generally higher than that for only axial main flow, with the same total flow rate. In multiphase flow, when the gas-liquid ratio (GLR) is relatively large, the side flow has minimal impact on pressure drop, while at lower GLR values, the side flow significantly increases the pressure drops. When predicting the pressure drop for single-phase variable mass flow in horizontal wellbores, it is appropriate to consider only the mixture pressure drop caused by the closest hole to the calculation section, assuming the injection hole flow rates are approximately equal. In terms of predicting the productivity of single-phase variable mass flow, it is crucial to consider the mixture pressure drop. Neglecting the mixture pressure drop can lead to relatively larger productivity prediction results, with potential production rate errors exceeding 50%. The accuracy of the prediction is influenced by the ratio of mixture pressure drop to production pressure differential, and the pressure along the external zone of the screen pipe is higher when considering the mixture pressure drop compared to when it is neglected. Additionally, the flow rate along the external zone of the screen pipe becomes more non-uniform when the mixture pressure drop is considered. Furthermore, the findings from the single-phase and multiphase flow experiments suggest that significant deviations in production rates may occur in scenarios with low gas-liquid ratio (GLR), highlighting the need for further investigation in this area.

Slug flow is one of the most common flow patterns in the petrochemical industry. It will affect the normal operation of oil well surface pipelines and connected equipment, especially gas well multiphase flowmeters. The extant slug flow traps are complex in structure and limited in application sites. To reduce the influence of slug flow on gas-liquid two-phase measurement, a slug flow elimination device is designed based on the kinetic energy conversion method. The gas-liquid two-phase flow law inside the device and its energy loss are investigated using a combination of indoor experiments and numerical simulations. This study evaluates the device’s working performance, including the flow pattern, pressure fluctuation, velocity distribution, and energy loss. The results show that the flow rate and pressure fluctuation of the gas-liquid two-phase flow are weakened after the device. And the flow pattern changes from intermittent slug flow to gas-liquid continuous flow. The pressure drop calculation method for the device is developed based on the share of different structures in the total pressure drop, with a prediction error of 20%. The slug elimination device is designed to provide a flow pattern basis for metering equipment, improve metering accuracy, and further promote the development of multiphase metering technology.

Since the structure of horizontal gas wells is more intricate than that of vertical wells, there is a lack of consistency in the form of liquid-carrying in different portions. Applying the commonly utilized liquid-carrying hypothesis of vertical gas wells into horizontal gas wells is therefore challenging. The maximum liquid volume that the gas flow could raise, the gas flow rate, and the maximum amount of energy that could be produced from a specific amount of gas flow should all be considered when determining the liquid volume that the gas flow could lift. This study is the first to integrate theoretical analysis with laboratory testing to analyze the gas–liquid flow law of drainage stability at varied tubing depths. The impact of gas drainage stability is then verified through the laboratory experiments. The novel model of various tubing depths, which is based on the energy of inflow and outflow from the horizontal well, is cleverly built. According to the study, the fluctuation is typically less when the tubing reaches the heel of the horizontal section than it is in the other sections, and the relative error of the new model, which is validated using laboratory tests, is typically less than 10%. The research showed that for horizontal gas wells with a normal structure, the gas flow and liquid discharge are most stable when the tubing reaches the heel of the horizontal section. Instead of depending exclusively on crucial liquid-carrying gas flow rates, the new model uses the combination of gas and liquid flow rates to make decisions concerning liquid loading and to quantify the liquid removal in real time, which is more realistic. The research illustrates how the study could provide a factual basis for assessing the capacity of horizontal gas wells to raise the liquid.

Conventional conductivity methods for measuring the void fraction in gas-liquid multiphase systems are typically affected by accuracy problems due to the presence of fluid flow and salinity. This study presents a novel approach for determining the void fraction based on a reciprocating dynamic conductivity probe used to measure the liquid film thickness under forced annular-flow conditions. The measurement system comprises a cyclone, a conductivity probe, a probe reciprocating device, and a data acquisition and processing system. This method ensures that the flow pattern is adjusted to a forced annular flow, thereby minimizing the influence of complex and variable gas-liquid flow patterns on the measurement results; Moreover, it determines the liquid film thickness solely according to circuit connectivity rather than specific conductivity values, thereby mitigating the impact of salinity. The reliability of the measurement system is demonstrated through laboratory experiments. The experimental results indicate that, in a range of gas phase superficial velocities 5–20 m/s and liquid phase superficial velocities 0.079–0.48 m/s, the maximum measurement deviation for the void fraction is 4.23%. [ABSTRACT FROM AUTHOR]

Concurrent flow of gas with a mixture of oil and water in production equipment is common necessitating the need for additional investigations to gain more insight and development of more accurate correlations for prediction of flow characteristics including pressure drop. In this study, an experimental study was conducted using air-water and air-water-oil mixtures in a 0.075-m diameter pipe. Superficial gas and liquid velocities ranged from 0.03 to 0.13 m/s and 1.26 to 41.58 m/s respectively. Slug flow was the main flow pattern observed. In addition, transition to annular and annular flow were also observed. Due to the homogeneous nature of the oil-water-air mixture, the three-phase flow was evaluated as a pseudo-two-phase mixture. An Artificial Neural Network (ANN) model developed for the prediction of two- and three- phase pressure drop performed better than all models considered during the evaluation. Generally, it is found that the accuracies for pressure drop were considered adequate.

During underbalance drilling, completion and workover wells, plugging channeling, blocking preformation and plugging formation water are inevitable problems. Gel is one of the most effective and convenient method to solve the problem. In this study, modified starch gel is synthesized, investigated experimentally and improved for efficient oil and gas field applications. The gel slurry is composed of starch (3.6 wt.%), initiator (0.02 wt.%), acrylamide (14.4 wt.%), cross-linking agent (4.7 wt.%), all of the components are mixed together with water at pH 10 – 11 which viscosity is as low as 35 – 82 mPa.s and desired to form gel. Here the effects of the components, reaction temperature and pH on gelation time and gel viscosity are systematically investigated, and the results showed that the gelation can be controlled in a wide range 30 – 120 min efficiently by pH and initiator. Fourier Transform Infrared Spectroscopy (FTIR) and Scanning Electron Microscope (SEM) are employed to study the molecular structure and microstructure of the gel, respectively. A compact three-dimensional network structure was formed in the gel, which contribute to a good adhesion. The gel has been successfully used in shale gas field which provides a reference for sealing other similar high formation pressure under unbalanced workover treatment. DOI: http://dx.doi.org/10.5755/j01.ms.24.4.18565

Churn flow commonly exists in the pipe of heavy oil, and the characteristics of churn flow should be widely understood. In this paper, we carried out air and viscous oil two-phase flow experiments, and the diameter of the test section is 60 mm. The viscosity range of the oil was 100~480 mPa·s. Based on the measured liquid holdup and pressure drop data of churn flow, it can be concluded that, due to the existence of liquid film backflow, positive and negative frictional pressure drop can be found and the change of frictional pressure drop with the superficial gas velocity is related to superficial liquid velocity. With the increase of viscosity, the change rate of frictional pressure drop increases with the increase of the superficial gas velocity. Combining our previous work and the Taitel model, we proposed a new pressure drop model for viscous oil-air two-phase churn flow in vertical pipes. By comparing the predicted values of existing models with the measured pressure drop data, the proposed model has better performance in predicting the pressure drop.

To explore the pressure drop variation with the viscosity of heavy oil gas-liquid two-phase flow, experiments with different viscosity gas-liquid two-phase flows are carried out. The experimental results show that the total pressure drop increases with increasing liquid viscosity when the superficial gas and liquid flow rates are the same. The liquid superficial velocity is 0.52 m/s, and the superficial gas velocity is 12 m/s in the vertical and inclined pipes, as there is a negative friction pressure drop when the superficial gas and liquid velocities are small. Additionally, the increased range of the total pressure drop decreases with increasing liquid viscosity. Considering the heavy oil gas-liquid two-phase flow, a prediction model of the pressure drop in high-viscosity liquid-gas two-phase flow is established. The new model is verified by experimental data and compared with existing models. The new model has the smallest error, basically within 15%. Based on the prediction of the wellbore pressure distribution of four wells in the BeiA oilfield, the new model prediction results are closer to the measured results, and the error is the smallest. The new model can be used to predict pressure drops in high-viscosity gas-liquid two-phase flow.

Hydraulic fracturing is an important means of developing unconventional oil and gas layers. The fracture conductivity of tight sandstone reservoirs after fracture is affected by many factors, such as the interaction between the fracturing fluid, water, and rocks; the fracturing materials; and the construction parameters. This paper improves the experimental process of the long-term conductivity test and provides insight into conductivity prediction and optimization based on the response surface test method. The test process is conducted in the following manner: (1) inject nitrogen to evaluate the fracture conductivity before fracturing fluid damage; (2) inject fracturing fluid to simulate shut-in; and (3) inject nitrogen again to evaluate fracture conductivity after the damage ability of the fracturing fluid. The single factor test results show that the lower the sand concentration is, the higher the fracturing fluid viscosity will be, and the longer the fracturing fluid retention time is, the greater the damage to the conductivity of the fracturing fluid will be. The response surface test results show that the order of factors affecting the retention of conductivity is fracturing fluid viscosity > sand concentration > fracturing fluid retention time. There is a certain interaction between sand concentration and fluid viscosity, and there is also a certain interaction between fluid viscosity and fluid retention time, but these interactions are not significant; when the fracturing fluid retention time is longer, there will be an interaction between the sand concentration and the fracturing fluid retention time. In addition, based on the model used to optimize the fracturing construction parameters from the perspective of proppant conductivity damage, the optimal solution is when the viscosity of the fracturing fluid is 1 mPa.s, the paved-sand content is 8.49 kg/m2, and the retention time of the fracturing fluid is 10 h. The maximum retention rate of the flow conductivity is 63.19%.

Proper selection and application of interfacial friction factor correlations has a significant impact on prediction of key flow characteristics in gas–liquid two-phase flows. In this study, experimental investigation of gas–liquid flow in a vertical pipeline with internal diameter of 0.060 m is presented. Air and oil (with viscosities ranging from 100–200 mPa s) were used as gas and liquid phases, respectively. Superficial velocities of air ranging from 22.37 to 59.06 m/s and oil ranging from 0.05 to 0.16 m/s were used as a test matrix during the experimental campaign. The influence of estimates obtained from nine interfacial friction factor models on the accuracy of predicting pressure gradient, film thickness and gas void fraction was investigated by utilising a two-fluid model. Results obtained indicate that at liquid viscosity of 100 mPa s, the interfacial friction factor correlation proposed by Belt et al. (2009) performed best for pressure gradient prediction while the Moeck (1970) correlation provided the best prediction of pressure gradient at the liquid viscosity of 200 mPa s. In general, these results indicate that the two-fluid model can accurately predict the flow characteristics for liquid viscosities used in this study when appropriate interfacial friction factor correlations are implemented.

The calculations of friction pressure drop is the most complicated in multiphase flow. Understanding of the friction pressure drop in pipes are of great importance for many industry problems. The existing friction pressure drop models are generally based on low gas and liquid velocities in horizontal and vertical pipes. In this paper, a two-phase flow experiment in inclined pipe was performed. We report the effect of superficial gas and liquid velocities on friction pressure drop, the results indicate that the pressure drop increases with the increase in superficial gas velocity and superficial liquid velocity. According to the experimental analysis and assuming that the fluid in contact with the pipe wall at high velocity is in a liquid phase, we developed a new friction pressure drop model of different flow pattern. This model based on the correlation between the fraction factor and the superficial gas and superficial liquid Reynold numbers. Compared with the previous models, the predictive performance of the present model is good and remains basically stable.

A delayed crosslinked polymer gel was developed for in-depth water control in mature oilfields. The thermal gelation behavior of nonionic polyacrylamide (NPAM) and PEI was investigated, and sodium citrate (NaCit) was selected as a new retarder to prolong the gelation time. The gelation performance of NPAM/PEI gel system can be adjusted by varying NPAM or PEI concentration, and a quadratic model is developed by statistical analysis, which predicts the gelation time of NPAM/PEI gel system. The obtained model shows high significance and good reliability, as suggested by the F-ratio of 175.16 and high adjusted R-square value (0.9732). The addition of NaCit exhibits a good delayed gelation effect on the NPAM/PEI gel system, better than that of NaCl. The decrease of the initial pH value of the gelling solution leads to the weaker gel viscosity and longer gelation time due to the protonation of amine groups on the PEI chains. Increasing temperature results in higher gel viscosity but shorter gelation time. The gel system in the presence of NaCit exhibits good compatibility with injection and formation water. A dense three-dimensional structure was observed in matured NPAM/PEI/NaCit gel, and it could keep stable below 160 °C. The gel system could effectively reduce the permeability (>95%) and restricted the flow of water after matured in natural cores.

Considering the fact that traditional cementing stone lacks toughness., post-production operations in oil wells often cause various forms of stress to cause cementing rings to produce micro-cracks or microcracks that are difficult to repair, which may affect cementing quality and long-term low durability. In response to the above problems, taking the cement slurry system as a starting point, a new type of epoxy resin emulsion modified slurry was prepared. The effects of resin emulsion at 0~20% dosage on the performance of cement slurry and its mechanical properties were studied and analyzed. The results show that when the content of resin emulsion is less than 15%, the bulk density of cement slurry is 1.88±0.04g/cm3 and the rheological properties of the slurry at 20~80°C are satisfied. Under the same temperature and pressure (80°C, 35MPa), the initial consistency can be controlled within 28Bc. The thickening time is 20~70% longer than pure cement, and the filtration loss of cement slurry can be obviously improved. Meanwhile, with the increase of the mixing ratio, the impact strength of the resin emulsion cement stone is increased by 15%, the elastic modulus is decreased by about 47.9%, and the toughness of cement stone is obviously improved.

Based on the mechanistic model of the two-phase swirling annular flow behavior, a calculation method for the effective distance of vortex tool is obtained by taking Kelvin–Helmholtz instability into account. The rationality of the proposed method is validated by comparing the predicted liquid film thickness and pressure under non-swirling flow with the commonly used correlations. Then, the influences of gas–liquid ratio, helix angle, and hub diameter of vortex tool on the liquid film thickness, pressure drop, and effective distance have been analyzed. Results show that the presence of the vortex tool causes the decrease in the liquid film thickness and increase in the pressure drop. The liquid film thickness increases gradually as the helix angle and the hub diameter increase, and the larger helix angle results in smaller pressure drop. The effective distance increases with an increase in the gas–liquid ratio and decreases with an increase in helix angle and hub diameter. A sudden decrease occurs when the helix angle exceeds 60°. The gas–liquid ratio and helix angle are more dominant factors than the hub diameter on the liquid film thickness, pressure drop, and effective distance.

To overcome the under injection in water-flooding treatment of low permeability reservoir, this paper introduces the grey correlation degree method to the dynamic connectivity between injection and production wells. First, it is proved that Deng’s model, focusing on the proximity between sequences, does not apply to the dynamic connectivity between injection and production wells. Then, the author built a new correlation degree model which reflects the similarity between sequences, and analysed the properties of the model. The new model can reflect the negative correlation between sequences, and outperforms Deng’s model in the simulation. Then, the results of Deng’s model and the new model were compared based on the parameter sequences of the real injection and production wells. The results show that the results of the new model are consistent with the actual production situation. Compared with Deng’s model, the new model reflect the exact difference and connectivity variation between wells.

Pressure drop is an important parameter in the study of gas-liquid two-phase flow (Beggs and Brill, 1973). The phenomenon of negative frictional pressure drop is observed in an experiment. In the process of the experiment, it is necessary to research the law of negative pressure drop. In this paper, the two-phase flow experiment is carried out in a vertical pipe of 60mm in diameter and 8m in length. The apparent liquid velocity is from 0.08 to 0.20 m/s, the apparent gas velocity is from 1 to 19 m/s. Air and mineral oil are used as the working fluids, and the viscosities of the oil are 25, 50, 70, 150, and 200 cp, respectively. The multiphase flow test platform is used to research the negative pressure drop. A criterion is given to judge the phenomenon of negative frictional pressure drop; the smaller the apparent gas-liquid velocity, the greater the influence of viscosity on the negative frictional pressure drop.

According to the abnormal pressure and poor water absorption of the JA reservoir, JA complex acidizing plugging removal system was proposed to improve oil production. The main acid of JA composite acid system was screened by acid sensitivity evaluation experiments. According to the corrosion evaluation experiment, the optimal concentration of HCL, HF and organic mixed acid (mixed by organic acid A and B in 1:1) in JA composite acid system is 15%, 3 % and 10%, respectively. In order to ensure the compatibility of JA composite acid, both preflush and overflush acid were used the mixed solution of 15% HCL and 3% HF. The evaluation of corrosion resistance indicated that the corrosion rate of JA composite acid could be reduced from 11.92 to 1.92 g/(m2•h) when the corrosion inhibitor H was loaded at the concentration of 1%. While 1% ferric ion stabilizer (JYS-1) was added, the stabilization efficiency of JA composite acid could reach 97.20%. The optimal formulation of JA composite acid is 15%HCL + 3%HF + 10% organic mixed acid + 1% corrosion inhibitor H + 1% JYS-1.