Search

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.

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.

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]

An experimental analysis has been conducted to study the process of fluid accumulation for different borehole trajectories. More specifically, five heel angles have been experimentally realized to simulate the borehole trajectory of the sloping section of the formation. The fluid-carrying capacity, pressure drop and fluid discharge volatility have been investigated for these conditions and, accordingly, the relationship between heel angle and wellbore pressure drop fluid-carrying capacity has been determined. The results show that while the reasonable roll angle can increase the pressure loss in the wellbore, it is beneficial to drainage. In terms of pressure loss and liquid-carrying capacity, when the heeling angle is 50°, the latter is increased while the former becomes very high, which indicates that when drilling and completing wells on site, a 50° roll angle should be avoided. It is found that the main reason for the increase of the total pressure drop in the wellbore is the increase of the local pressure loss in the inclined section. From the perspective of drainage stability, when there is heeling in the inclined section of the horizontal well, the fluctuation of the wellbore drainage tends to be enhanced. Through the comparison of the Beggs-Brill (B-B) and Mukherjee-Brill liquid holdup methods, it is found that B-B method better predicts liquid holdup. A new method for calculating the pressure drop in the inclined section in the presence of lateral inclination is obtained by taking into account the pressure drop in the curved section. Through comparison with experimental data, it is found that the error is within 20%, and the prediction accuracy is high. [ABSTRACT FROM AUTHOR]

A flow is observed in the pipe for the horizontal section of slotted screen completion and inflow control device (ICD) completion, and an annulus flow exists between the pipe and the borehole wall. Based on the principles of mass conservation and momentum conservation, a model for variable mass flow in an oil reservoir to simulate wellbore–annulus–reservoir state in the horizontal section of slotted screen completion and ICD completion is proposed. Consequently, based on the newly established formation transient seepage model and wellbore and annulus variable mass flow model, an accurate prediction of the production rate of a horizontal well and optimized design parameters for slotted screen completion and inflow control device (ICD) completion are achieved. The predicted flow profiles of the established model are confirmed using the simulation software from Computer Modeling Group Ltd. When external casing packers are not considered, findings show that the predicted production rates of both slotted screen completion and ICD completion, which are obtained using the variable mass flow models without annulus flow modeling, are higher than the rates obtained using the variable mass flow models with annulus flow modeling. Both models show that the pressure profile and flow profile of the borehole wall are more uniform in wellbore–annulus–reservoir in horizontal wells. The flow model for horizontal wells with annulus flow modeling should be established to improve the accuracy of the predicted production. [ABSTRACT FROM AUTHOR]

In the process of gas lift design and condition diagnosis, the accuracy and timeliness of wellbore multiphase flow model prediction results are the basis for all subsequent work. However, for the commonly used wellbore multiphase flow pressure drop prediction models, there is a big deviation between the predicted value and the measured one, and the optimization based on the measured data is time-consuming, and it is difficult to obtain the optimal parameters of the model. Therefore, based on the well bore pressure distribution data measured quickly in area R of an oil field in Kazakhstan, a better prediction model of multiphase flow in the well bore was selected at first. Then, the simultaneous perturbation stochastic approximation (SPSA) algorithm was incorporated in the wellbore multiphase flow model to optimize the liquid holdup, which is the leading factor in the model. After repeated single well optimization and greedy selection, the optimal parameters suitable for the whole block were obtained. The example shows that the optimization speed is 10 times faster than that of Particle Swarm Optimization (PSO). After that, the optimized model was used to predict the wellbore pressure distribution, and it was found that the relative error between the measured value and the predicted one was less than 15%. [ABSTRACT FROM AUTHOR]

In the pipeline system for slurry, local erosion wear failure has become the main damage mechanism of pipe in the fracturing operations of oil-gas engineering. Computational Fluid Dynamics simulation is performed to determine the evolutionary process of erosion wear in tubing connector, which is the resistance of pipeline system, and a new way to predict the pipeline longevity is provided. Based on the Euler equation, solid particle concentration in the slurry and interphase momentum exchange are included in the liquid flow equations due to the influence of dense particle on slurry (slurry is a two-phase flow), and the particle trajectory was calculated in the Lagrange frame by analyzing the forces from the interaction of liquid and particle and particles impact. With the erosion damage model, the erosion rate/depth in the connector was calculated to reconstruct the mesh model of shoulder with 5 tori. Torus 1 is closest to axis while torus 5 is on the outmost wall of the connector. During the erosion event, greatest erosion and hence surface deformation occurs on tori 1 and 2, and this affects the surrounding flow and particle movement. After 10 hours of erosion, there was a dramatic drop in the maximum erosion rate, which illustrated a conservative prediction for pipeline service life if the initial erosion rate was used. An erosion experimental setup was also performed to identify the weight loss and erosion characteristic of the inner surface with erosion time of 55 hours. It was observed that the erosion simulations provided relative errors within 18% for erosion length and weight loss compared to the experimental values, and a closed form equation for the erosion rate was proposed to predict the erosion life of tubing connector. [ABSTRACT FROM AUTHOR]

Compared with experimental data of pressure drop of gas-liquid two-phase upward flow with low gas-liquid ratio in vertical pipe, the mean relative error of pressure drop predicted by Orkiszewski's model is 63.62%, the maximum relative error of the model is 98.07%. This paper first introduces the process of acquiring experimental data, then, combined with the experimental data, it is pointed out that the Orkiszewski's model has a small error in predicting the annular-mist flow pattern, but a large error in predicting the slug flow pattern and annular-slug transition flow pattern. The author analyzes the structure of Orkiszewski's model and points out that the formula of liquid distribution coefficient in slug flow pattern is complex and very important. In this paper, a new threshold value of liquid distribution coefficient is proposed and an improved Orkiszewski's model is obtained by particle swarm optimization. The calculated results of experimental data show that the average relative error of the new model is reduced to 25.28%, and the average relative error of the new model can be reduced from 76.17% to 17.21% for the slug flow pattern with continuous oil phase and total flow velocity greater than or equal to 3.048m/s. [ABSTRACT FROM AUTHOR]

Direct reinjection and discharge of water mixed with oil leads to environmental pollution and exhaust heat waste. Of the various methods used to treat wastewater, the mechanical vapor recompression (MVR) evaporation method has obvious advantages in energy consumption and environmental protection. In this paper, the use of MVR for water recovery from water co-produced with oil was studied and analyzed through experimentation. Based on the design calculations for the MVR system, the MVR rig was set up and a series of experimental studies were conducted. The results show that when keeping the suction pressure constant at 0.035 MPa, the compressor power increases with the increase of discharge pressure. The experimental value of the compressor power was slightly greater than the theoretical value, with a deviation of less than 5%. The amount of distilled water produced rose slightly when the compressor discharge pressure was increased. The power consumption for producing 1 m³ of distilled water increased with the increase of discharge pressure, which is also in accordance with the design condition. The experimental value of the power consumption per unit of distilled water is larger than the theoretical value, but the deviation is within 10%. [ABSTRACT FROM AUTHOR]

This paper attempts to determine the time delay between the sequence of system behaviors and that of influencing factors on system behaviors. Firstly, a new concept was coined called the representative subsequence (RS), and the RSs of influencing factors were selected. Next, a new geometric similarity grey relational grade (GRG) model was set up to compute the time delay of each influencing factor RS relative to the sequence of system behaviors. On this basis, the time-delay corresponding to the maximum GRG was taken as the desired time-delay. The verification on actual data shows that the concept and extraction rule of the RS are feasible, and our geometric similarity GRG model outperforms the conventional model in predicting time delay. The research findings lay the basis for grey prediction modelling of time sequences and optimizing the prediction effect of grey prediction models. [ABSTRACT FROM AUTHOR]

This paper attempts to disclose the law of critical gas velocity in the swirling flow field induced by the vortex tools. For this purpose, a critical gas velocity calculation model for vortex drainage gas wells was established based on the axial force balance between the liquid film and the gas core in swirling flow, and modified with the experimental data in previous studies. Then, the effects of helix angle and hub diameter of vortex tool on the reduction amplitude of critical gas velocity were analyzed by comparing the modified model with Turner model. Through experimental verification, it is learned that our new model can predict the critical gas velocity under different production conditions with different vortex tools. The reduction amplitude of critical gas velocity increased with the helix angle and decreased with the growth in hub diameter. The reduction amplitude ranged from 55.03% to 59.35% as the helix angle varied from 15 ° to 75 ° and the hub diameter varied from 34mm to 50 mm. The helix angle has a greater impact than the hub diameter on the reduction amplitude. The research findings shed new light on the design and application of the vortex tools. [ABSTRACT FROM AUTHOR]

On the basis of previous research, the true trajectory of horizontal oil wells with complex structures is considered in this study. A horizontal well is an assembly of a myriad of infinitesimal section lines along the well’s length. Hence, a method to calculate the true horizontal well trajectory potential in a top-closed reservoir with bottom water is achieved. Combined with the formula of pressure drop in a single-phase variable mass flow horizontal well, a new coupled semianalytical model for horizontal well productivity prediction is established. Using a well from an offshore oilfield in China as case study, productivity prediction via calculation and comparison of the horizontal well is conducted. Prediction results show that the new model is more accurate than other models considered. The established model for real 3D well trajectory potential converts the integral solution into even-number segments to avoid the defect of zero denominator when potential calculation is conducted for the self-infinitesimal scenario. In summary, the new coupled semianalytical calculation model of productivity prediction for horizontal wells is built by establishing a calculation model for the true trajectory potential of a horizontal well. This model is proven feasible through actual case calculation. The new model is refined and stable, and productivity prediction under true trajectory conditions can be obtained with the new model. Such productivity prediction reflects the real situation of oil wells and is conducive for the optimal design of well trajectory and parameters. [ABSTRACT FROM AUTHOR]

The gas holdup of oil-gas-water three-phase flow is intimately connected with stream pattern, flow rate and tension. Regarding the deviation problem in the measurement of fiber optic probe gas holdup in oil-gas-water three-phase flow, this paper presents an evaluation method to measure the gas holdup of fiber optic probe based on data fusion. Firstly, the method applies the Grubbs criterion to eliminate the omission errors in the gas holdup data collected by a single fiber optic probe in a period of time. Secondly, it acquires the optimal value of the fiber optic probe in a certain time quantum by estimating the data collected by the fiber optic probe in batches. After obtaining the optimal value of the data collected by the four fiber optic probes in the downhole optical fiber probe array, the author adopts the self-adaptive weighted fusion algorithm, fuses data according to the optimization principle of the total minimum mean squared error and calculates the accurate value of the gas holdup of oil-gas-water three-phase flow in the wellbore in a certain time quantum. The experimental results show that this kind of method can improve the measurement accuracy of gas holdup and achieve more accurate estimate in oil-gas-water three-phase flow. [ABSTRACT FROM AUTHOR]

Copyright of Journal of Engineering Research (2307-1877) is the property of Kuwait University, Academic Publication Council and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

For heavy reservoirs with different rheological fluid, the diverse phenomena may appear in the fluid flow. Based on the rheology experiment, the actual rheological equations are figured out in district A. With the detailed type of fluid, the fundamental formulas about pressure loss and temperature are reasonably selected, by which, the model for production prediction are defined as the basis for the calculation of pressure distribution along the pipe. As Beggs-Brill method has just made a prominent contribution to the slippage area, the wellbore pressure distribution is obtained through basic momentum equations, in which the pressure drop is calculated only based on the average parameters, such as density, viscosity. The impact caused by slippage between steam-liquid phases has yet been neglected. Particularly, when the steam dryness is relatively low, and the slippage does exist, the result is obviously not scientific. Therefore, with some modified parameters, this paper proposes a new process by the involvement of Beggs-Brill method, and describes the process in detail with onsite data to test and verify the feasibility. It turns out that BeggsBrill method is suitable to calculate pressure distribution, where the process and the model for production prediction are also applicable in this district. [ABSTRACT FROM AUTHOR]

The gelation process of organically polymer gel was investigated by dynamic thickening measurements. Rheological measurements were used to evaluate the viscosity of the gel. During the gelation process, high temperature resulted in higher rate of crosslinking. Rigid and stable gel was formed in neutral and alkaline media, and the higher of the pH value, the faster of the gelation process. However, gel could not be formed in acid condition. Moreover, the rate of crosslinking increased with the increase of concentration of polymer and crosslinker. The addition of NH4Cl elongated the gelation time significantly, but played a negative role in the gel strength, while a rigid gel was formed in the presence of Sodium acetate or trisodium citrate dehydrate. This paper summarizes the results and discusses how various parameters affect the gelation process of the gel. [ABSTRACT FROM AUTHOR]

The Mukherjee-Brill prediction model of pressure gradient is the common calculation model in oil-gas field development. The laboratory experimental results of multiphase flow show that the average prediction relative error is 35% and the maximum relative error reaches 72%. By comparing the prediction residual of the Mukherjee-Brill model with the test condition parameters, this paper suggests that the predicted residual of Mukherjee-Brill model has a close relationship with the gas-liquid ratio and has no clear correlation with the water content of fluid when the volume flow rate of liquid is constant. This paper first builds a cubic regression model of the prediction residual of the Mukherjee-Brill model regarding the gas-liquid ratio, and subsequently, combining the cubic regression model with the Mukherjee-Brill model, builds a new prediction model of pressure gradient, the MBM model. The results for 90 test groups show that the average prediction relative error of the MBM model is reduced to 7.66%. The MBM model improves the prediction accuracy of the pressure gradient for multiphase flow, and assists in advancing the reliability of the design and analysis of oil and gas wells. [ABSTRACT FROM AUTHOR]

It is crucial for the completion parameter design and production performance detection interpretation to have an accurate pressure gradient. The Aziz prediction model of pressure gradient is a common calculation model in oil-gas field development. The laboratory experiment results of multiphase flow show that the average prediction relative error is 29.62% and the maximum relative error reaches 70.1%. By comparing the prediction residual of the Aziz model with the experiment condition parameters, as the volume flow rate of the liquid phase is constant, this paper considers that the prediction residual of the Aziz model is closely related to the gas liquid ratio and has no clear correlation with the water fraction of fluid phase. Based on unifying the orders of magnitude of the prediction residual and the gas liquid ratio, this paper uses a cubic function of the gas liquid ratio to fit the prediction residual of the model to obtain a new pressure prediction method which is called Aziz-1 model. The results for ninety groups of experimental data show that the average prediction relative error of the Aziz-I model is reduced to 10.82%. Hence, the Aziz-I model improves the prediction accuracy of pressure gradient for multiphase flow. [ABSTRACT FROM AUTHOR]

problem of pressure drop for oil-gas-water three phase vertical flow, the prediction accuracy of the existing prediction model is lower based on the high-accuracy data. This paper displays the predicted pressure drop graphically. Considering the geometrical characteristics of the predicted pressure drop, a new prediction model of pressure drop is built based on the function fitting and interpolation. The new model is suitable for the water content from 0 to 100%. The computed results show that the predicted average relative error is decreased from more than 40% to less than 2.33% under different water content conditions with the experimental data. This paper uses the experimental data with water content 30 and 90% to obtain the pressure drop under water content 60% by interpolation. The average relative error is decreased from 41.5 to 12.00%. [ABSTRACT FROM AUTHOR]