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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]

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]

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]

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]

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]

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]

Foam drainage technology has been widely used to remove the liquid out of pipe in loading gas wells and keep the well normally producing. Still, it has some limitations in application, especially for the wells in low temperature and remote areas, in which the pipe blocking disasters easily occur. Moreover, these wells are usually protected by the attemperator and ethylene glycol injection in the wellhead, which further hinders the application of this technology. Faced with these limitations, we propose a new method, which has the following advantages: (1) it keeps the original devices, avoiding the complex wellhead operation; (2) it solves the problem of hard dissolvability of originally injecting ethylene glycol and newly injecting defoamer. Additionally, it makes use of the ethylene glycol injecting equipment as co-defoaming process. It not only keeps the ethylene glycol injecting effectively, but also solves the big problem of defoaming in foam drainage; (3) for the mixed liquid of ethylene glycol and defoamer, the abilities of anti-freezing and defoaming are maintained in the new method, which is the base of application; (4) the main costs of the new method are the expense of necessary chemical agents, making the method quite economical. Further, the new method was applied into the severely loading gas well. It turned out that there was no block and no foam in the wellhead and the well had been brought back to life. Besides, the frequency of shut-in was reduced by a large extent. Our study suggests that the new method could be popularized in remote and low temperature gas wells if suitable foamer, defoamer, and emulsifier could be obtained. [ABSTRACT FROM AUTHOR]

This paper develops a water holdup calculation model based on flow characteristics for no-slip oil-water two-phase flow. The model is constructed in consideration of two flow patterns: the stratified flow (ST) and the stratified flow with some mixing at the interface (ST&MI). The predicted values obtained by the model are compared with the test data on white oil-water flow. The results show that the model can accurately predict the water holdup of no-slip oil-water two-phase flow, which is of great significance for the determination of the working parameters in oilfields. [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]

In the previously published studies, the calculations of critical liquid-carrying gas velocity in a horizontal well were based on conventional calculation models of a droplet in a vertical well and do not consider the influence of the inclination angle of the well on the liquid-carrying ability of gas. Horizontal wells are currently widely used in the gas fields, while the traditional critical liquid-carrying velocity models cannot be applied to evaluate gas flow characteristics in the inclined sections of horizontal wells. In this paper, based on experimental results, we established that the critical liquid-carrying conditions in an inclined well occur when the inclination angle is 55°. Considering the flow characteristics of the liquid phase in a gas well, we obtained the flow mode of the liquid film in the pipeline. The established liquid-film model provides a calculation method of the critical liquid-carrying velocity for different inclination angles. The accuracy of the new method has been verified by the field data. [ABSTRACT FROM AUTHOR]

To identify the accurate gas volume to carry liquid in horizontal gas well, this paper simulates the gas-liquid two-phase flow in a single pipe on the platform of multiphase pipe flow. Through indoor experiments on gas-liquid two-phase flow, it is confirmed that the inclined section (inclined angle: 45°~ 60°) is mostly likely to suffer from liquid loading in horizontal gas well. Then, a new critical liquid-carrying model was built after fitting the liquid holdup calculation formula at different inclined angles, considering the actual liquid-carrying phenomenon. The proposed model was proved accurate enough for engineering application through verification by indoor experiments. [ABSTRACT FROM AUTHOR]

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]

In view of the limited conditions of the previous inclined multiphase pipe flow experiments (diameter and flow) with no reliable adaptability of multiphase pipe flow calculation method which is obtained from this experimental conditions when the using conditions are beyond the scope of the experiment (such as a middle to large diameter and large flow), the gas-liquid two-phase flow experiment was carried out using air and water as the medium with different inclined angles 0°, 15°, 30°. 45°, 60°, 75° and 90° in this paper. The analysis of variation of liquid holdup and pressure drop with different gas and liquid quantities and inclination angles was obtained. The calculation method applicability of liquid holdup and pressure drop were verified and selected from the experimental data, and the error variation law of the calculation methods w ere analysed. The applicability of the calculation method was compared with its applicability to liquid holdup and pressure drop as verified by the field test data. According to the analysis of the comparative results, the applicability conditions of the existing pressure calculation methods were obtained and they provided the guidance for the selection of the inclined multiphase pipe flow calculation methods under the condition of middle and high production rates. [ABSTRACT FROM AUTHOR]