Liquid Loading In Gas Wells Research Articles

Mitigating Liquid Loading in Gas Wells Using Thermochemical Fluid Injection: An Experimental and Simulation Study.

Liquid loading significantly hinders gas production in unconventional shale wells, restricting flow and causing productivity decline. This study presents a novel approach to address this challenge, utilizing thermochemical fluids to generate in situ pressure and heat and effectively mitigating liquid loading issues. Laboratory experiments were conducted using a specially designed flow loop system to evaluate the performance of thermochemical fluids in alleviating liquid loading. The key treatment parameters such as thermochemical volumes, injection rate, number of cycles, and optimum injection time were optimized to improve the removal efficiency. In addition, PIPESIM software (pipe simulation program) was used to validate the effectiveness of the thermochemical approach for removing the liquid loading issue. Both laboratory results and PIPESIM outcomes confirmed the efficiency of thermochemical fluids in handling liquid loading. Removal efficiency of more than 90% can be achieved using thermochemical injection. The liquid removal efficiency increases with the number of cycles due to the generation of more pressure and heat at later injection cycles. Increasing injection cycles from 1 to 3 resulted in liquid removal efficiency rising from 17 to 95%. Also, PIPESIM results indicated that the gas production rate can be improved by around 74% after applying thermochemical treatment. Overall, this study introduces an effective treatment for liquid loading mitigation with significant potential to enhance gas production. The proposed method offers several advantages, including ease of application and extended well life.

A fully coupled compositional wellbore/reservoir model for predicting liquid loading in vertical and inclined gas wells

Liquid loading presents a formidable challenge for mature gas wells, often resulting in substantial economic losses. Traditional research has predominantly centered on the analysis of gas-liquid two-phase flow within the wellbore to predict critical gas velocity or rate, aiding in identifying the onset of liquid loading. This study introduces a fully coupled compositional wellbore-reservoir simulator designed to detect liquid loading in both vertical and inclined gas wells. Leveraging the drift-flux model to evaluate flow pattern transitions, this simulator employs pressure or rate constraints at the wellhead as boundary conditions. It comprehensively captures the flow dynamics in both the wellbore and reservoir, unveiling significant changes in gas production rate, water production rate, gas velocity, flow regime, and the reserved position of the liquid film under liquid-loaded conditions. Moreover, the accumulation of liquid at the bottom hole leads to increased reservoir pressure and gas saturation near the wellbore. The simulator predicts a typical unstable production period, emphasizing its crucial role in implementing effective strategies to mitigate liquid loading. This paper investigates the capability of the coupled wellbore-reservoir model to characterize transient liquid loading phenomena from a systematic perspective. The proposed model can function as a real-time tool for predicting the status of liquid loading in gas wells.

Experimental and modeling studies on continuous liquid removal in horizontal gas wells

The potential risks of liquid-loading can be significantly decreased by precisely calculating the minimum gas flowrate required for continuous liquid removal in gas wells and using suitable deliquification technology beforehand. Due to lack of comparative studies with liquid-loading characteristics, existing prediction models are not very adaptable in the course of the application. So as to investigate the flowing behavior of liquid film under different conditions, visual experiment was conducted. The findings indicate that as the inclined angle increases, the liquid-film-reversal gas velocity increases initially before decreasing. The maximum velocity of liquid-film-reversal is around 55°. The liquid-film-reversing gas velocity increases linearly along with the rise in superficial liquid velocities. The liquid-film-reversal gas velocity likewise increases linearly as the superficial liquid velocities. The analysis findings also indicate that several dynamic liquid-loading symptoms of the gas well are inconsistent with the liquid-film-reversal criterion, meaning that the gas well does not instantly follow the liquid-film-reversal. On the basis of our experimental findings, a new liquid-loading commencement criteria was then developed. As a result, this research suggests a novel model for evaluating liquid-loading in gas wells. The model’s accuracy was found to be as high as 85.7% by looking at 14 gas wells and perform better than other models in the Coleman dataset, which can theoretically enable the prediction of liquid-loading in gas wells.

Experimental study on the effect of liquid properties on fluid behavior and liquid loading in vertical natural gas wells

Liquid loading is one of the major challenges for natural gas wells, as it can decrease and eventually cease the production of hydrocarbons. Characterizing liquid loading in gas wells and quantifying flow dynamics throughout this process is crucial. The literature shows a lack of experiments for oil-air low liquid loading flow, especially in vertical pipes. This demonstrates a lack of experimental data to comprehend the effect of liquid properties on two-phase flow behavior. In order to simulate a vertical natural gas well, oil-air tests were carried out in this work in a vertical pipe with a 0.0508-m ID (Inner-Diameter) under low liquid loading conditions. The aim of this study is to better comprehend the effect of liquid characteristics on flow behavior and the onset of liquid loading.The results of the experiments reveal that changing the liquid phase from water to oil reduces pressure loss, liquid holdup, and the surface gas velocity (vSg) at which liquid loading occurs. Liquid holdup and pressure loss of the water-air and oil-air flow with medium gas rates show notable variances within the churn flow. Additionally, compared to the minimum-pressure drop technique, the positive pressure technique offers considerably more reliable predictions for the start of liquid loading.Two models—the unified Tulsa University Fluid Flow Projects (TUFFP) and OLGA—are used to investigate the flow pattern, liquid holdup, and pressure loss predictions. The liquid film reverse, liquid droplet models, and the inflection point technique were compared to experimental data for similar liquid loading onset models by Alsanea et al. (2022). For the data in this investigation, the OLGA model and Coleman's correlation perform the best at predicting the onset of liquid loading. Given that both the unified model and OLGA use slug flow models, the results show that a separate model must be created for churn flow to accurately estimate the pressure drop and liquid holdup.

Evaluation of Liquid Loading in Gas Wells Using Machine Learning

The inevitable result that gas wells witness during their life production is the liquid loading problem. The liquids that come with gas block the production tubing if the gas velocity supplied by the reservoir pressure is not enough to carry them to surface. Researchers used different theories to solve the problem naming, droplet fallback theory, liquid film reversal theory, characteristic velocity, transient simulations, and others. While there is no definitive answer on what theory is the most valid or the one that performs the best in all cases. This paper comes to involve a different approach, a combination between physics-based modeling and statistical analysis of what is known as Machine Learning (ML). The authors used a refined ML algorithm named XGBoost (extreme gradient boosting) to develop a novel full procedure on how to diagnose the well with liquid loading issues and predict the critical gas velocity at which it starts to load if not loaded already. The novel procedure includes a combination of a classification problem where a well will be evaluated based on some completion and fluid properties (diameter, liquid density, gas density, liquid viscosity, gas viscosity, angle of inclination from horizontal (alpha), superficial liquid velocity, and the interfacial tension) as a “Liquid Loaded” or “Unloaded”. The second practice is to determine the critical gas velocity, and this is done by a regression method using the same inputs. Since the procedure is a data-driven approach, a considerable amount of data (247 well and lab measurements) collected from literatures has been used. Convenient ML technics have been applied from dividing the data to scaling, modeling and assessment. The results showed that a wellconstructed XGBoost model with an optimized hyperparameters is efficient in diagnosing the wells with the correct status and in predicting the onset of liquid loading by estimating the critical gas velocity. The assessment of the model was done relatively to existing correlations in literature. In the classification problem, the model showed a better performance with an F-1 score of 0.947 (correctly classified 46 cases from 50 used for testing). In contrast, the next best model was the one by Barnea with an F-1 score of 0.81 (correctly classified 37 from 50 cases). In the regression problem, the model showed an R2 of 0.959. In contrast, the second best model was the one by Shekhar with an R2 of 0.84. The results shown here prove that the model and the procedure developed give better results in diagnosing the well correctly if properly used by engineers.

Liquid Loading of Horizontal Gas Wells in Changbei Gas Field

The Changbei gas field, which initially exhibited high gas-production performance, is dominated by large-displacement horizontal wells. With the decrease in reservoir pressure, the liquid loading in the gas well is currently severe, and production has been rapidly decreasing. Thus, recognizing the gas-well liquid loading to maintain stable gas-well production is necessary. A method was established to identify the water source of the liquid loading in the Changbei gas field. First, formation water and condensate water were identified based on the mineralization of the recovered water and the mass concentration of Cl− and K+ + Na+, and then the condensate content of the water produced in the gas well was qualitatively evaluated. The water–gas ratio curve for the gas well was plotted to determine whether the produced water was edge-bottom water, pore water, or condensate. Then a method was established to distinguish the start time of liquid loading in the gas well using a curve depicting a decrease in production; the method was also used to estimate the depth of the gas well where liquid loading occurs, according to the bottomhole pressure. First, based on the available production data, the Arps decline model was applied to fit the production curve for the entire production phase; the resulting curve was compared with the actual production curve of the gas well, and the two curves diverged when fluid accumulation began in the gas well. Finally, the liquid-loading depth of the gas well was estimated based on the bottomhole pressure. This method can be used to determine the fluid accumulation and calculate the liquid-loading depth of gas wells with unconnected oil jackets. The analysis revealed that in the Changbei gas field, condensate was the type of water primarily produced in 35 gas wells, accounting for 62.5% of the total number of gas wells. Edge-bottom water was the type of water primarily produced in 16 gas wells, accounting for 28.6% of the total number of gas wells. In the remainder of the gas wells, pore water was the water primarily produced; the calculations of accumulation time and accumulation volume of typical gas wells in the block revealed that some gas wells started to accumulate liquid after 45–50 months, and the amount of accumulation could reach several tens of meters, while others were in good production condition. The method established in this paper could enhance our understanding of liquid loading in gas wells in the Changbei gas field and lay a foundation for the development of gas-well deliquification techniques.

Velocity String Drainage Technology for Horizontal Gas Wells in Changbei

The Changbei gas field is dominated by wells with large horizontal displacement, which have exhibited high gas production performance at an early stage of development. With the decrease in reservoir pressure, the liquid loading in the gas well is relatively high and gas production rapidly decreases. Therefore, suitable drainage measures are required to maintain stable gas production. Based on the characteristics of the unconnected oil jacket of gas wells in Changbei, a velocity string was used for drainage. A critical liquid-carrying model was established to determine the location of liquid loading in horizontal gas wells in Changbei. First, the coefficients of the liquid-carrying model were determined through theoretical analysis of the characteristics of the gas well formation. Then, the depth setting of the velocity string was analyzed. The critical liquid-carrying model was employed to calculate the liquid-carrying flow rate of each section; the calculated flow rates were compared with the actual flow rates to determine whether fluid accumulation occurred in each section of the gas well. Thereafter, with the help of the oil and casing position, the suitable setting position of the velocity string was determined. The formation fluid was driven from the tubing into the casing owing to the increase in the overflow area, based on the principle of reducer fluid mechanics. The fluid velocity in the larger overflow cross-section decreased, thereby reducing the drainage capacity of the gas well and resulting in liquid loading. Finally, a timing analysis was performed. After the formation pressure decreased, the well production and flow rate changes were analyzed by placing two velocity strings of different sizes at different wellhead pressures in the gas well with fluid accumulation. The results indicated that although the velocity string was set at a position suitable for fluid drainage, fluid accumulation still occurred after a production period, thus necessitating replacement deliquification.

Mechanism of liquid unloading by single flowing plunger lift in gas wells

The plunger lift is one of the main methods to release liquid loading in gas wells. Due to the leakage in the process of moving for plunger, the efficiency of liquid unloading is decreased. In recent years, the single flowing plunger was invented and has been used in many gas fields. However, the mechanism of enhanced liquid unloading is still unclear. In this paper, a full-size visible plunger lift equipment was built to study the process of single flowing plunger lift (SFPL) and normal plunger lift (NPL). Moreover, a transient model was built to simulate SFPL and NPL in different situation. Results show that the SFPL can prevent the liquid from dropping, decrease the bottom-hole pressure, and enhance gas production. The SFPL performs well in a certain range, and the SFPL would be out of operation first. A plate has been built to help engineers optimize the SFPL. The paper helps clear the situation of SFPL and provides the theoretical basis for researchers.

Modelling of liquid loading in gas wells using a software-based approach

Liquid loading is the most common operational problem influencing gas well productivity for the petroleum operator. Liquid loading is defined as an operational constraint that is associated with gas wells where the major driving mechanism for hydrocarbon production is by the associated gas-driven mechanisms. Liquid loading occurs when liquid accumulated in the tubing or casing results in the gas velocity lower than the critical value (the minimum velocity required for gas to push the liquid out of the gas well), which overtime leads to a hydrostatic back pressure greater than the formation pressure of the well, thereby limiting the flow of gas into the well. The continuous build-up of pressure from liquid loading eventually minimizes well productivity and expensive work over operations. However, current mathematical models to predict liquid loading are flawed with varying inaccuracies and depending on the models deployed will ultimately lead to loss of production time and well productivity. In our work we present prediction of liquid loading using a software-based model incorporating the particle swarm optimization algorithm, genetic algorithm, and artificial neural network and Bayesian neural network algorithms applications. The results of our research findings show that artificial neural network software-based model with a simulated accuracy of 93% and 92% for test and trained data, respectively, outperformed the particle swarm optimization data-driven model with a simulated sensitivity accuracy of 92% and 83%, and genetic algorithm data-driven models with a simulated accuracy of 89% and 83%. The Bayesian neural network was postulated as a robust model because of its simplicity shown to have simulated accuracy of 77% and 73% for train and test data, respectively. Thus software-based code environment and data-driven model developed and presented in this paper may resolve many of current deficiencies and gaps in the current technical literature to predict liquid loading with high precision offering saving in millions of dollars to the operators.

An Improved Model for the Prediction of Liquid Loading in gas Wells using Firefly and Particle Swarm Optimization Algorithms

Liquid loading is an undesired phenomenon in gas wells that occurs when producing wells attain a flow rate below which liquid will not be able to flow to the surface. The inability of the energy from the gas to transport the liquid to the surface causes back flow and eventual accumulation of liquid at the wellbore. This is characterised by intermittent flow, which, if left unchecked, can eventually kill the well. An effective and reliable predictive method must therefore, be employed. In this study, improved models based on data set from condensate/water in a gas well were developed by applying firefly (FA) and particle swarm optimisation (PSO) algorithms. The results showed that the model developed out perform many of the existing models. The models predicted liquid loading in gas well at 86% level of accuracy compared to the 81% highest possible from published models. Although, the FA and PSO models predicted liquid loading at higher accuracy compared with Turner and Coleman models for higher wellhead pressure systems, the Coleman model appeared to perform better in the prediction of critical gas rate for low-pressure systems. However, the developed model can significantly improve the prediction of liquid loading in gas wells at a higher reliability and accuracy levels. Thus, the proposed models can be a veritable tool for accurately predicting liquid loading in gas wells.

Prediction of critical liquid loading time for water-producing gas wells: Effect of liquid drop rotation

After more than 20 years of continuous development, part of the wells in the Moxilei-1 gas reservoir located at the Sichuan Basin have entered the middle–later production stage. With the continuous decline in formation pressure and production rates, some of the gas wells have entered the potential period of liquid loading, while some have already suffered water plugging. Currently, the field engineers usually carry out some corresponding drainage measures after the occurrence of liquid loading in the gas well, which will first affect the production progress of the gas field, then increase the difficulty in drainage and reduce the drainage effect afterward. On the basis of Pan’s model for evaluating critical liquid-carrying flow rate, the influence of liquid drop rotation was considered in the new model. Further, combined with the Arps production decline equation, a prediction model of liquid loading timing was deduced. Taking a typical well in the Moxilei-1 gas reservoir as an example, based on the early-stage production data of the gas well, the model was used to predict the liquid loading timing accurately. The model can predict the possibility and timing of liquid loading in gas wells at different production stages. It can check the gas wells with potential liquid loading, so as to reduce the workload for field workers. Furthermore, it can predict the potential liquid accumulation and its timing in advance, so as to guide the field workers to prepare for drainage in advance.

Technology Focus: Unconventional and Tight Reservoirs (July 2021)

As unconventional oil and gas fields mature, operators and service providers are looking toward, and collaborating on, creative and alternative methods for enhancing production from existing wells, especially in the absence of, or at least the reduction of, new well activity. While oil and gas price environments remain uncertain, recent price-improvement trends are supporting greater field testing and implementation of innovative applications, albeit with caution and with cost savings in mind. Not only is cost-effectiveness a requirement, but cost-reducing applications and solutions can be, too. Of particular interest are applications addressing challenging well-production needs such as reducing or eliminating liquid loading in gas wells; restimulating existing, underperforming wells, including as an alternative to new well drilling and completion; and remediating water blocking and condensate buildup, both of which can impair production from gas wells severely. The three papers featured this month represent a variety of applications relevant to these particular well-production needs. The first paper presents a technology and method for liquid removal to improve gas production and reserves recovery in unconventional, liquid-rich reservoirs using subsurface wet-gas compression. Liquid loading, a recurring issue downhole, can severely reduce gas production and be costly to remediate repeatedly, which can be required. This paper discusses the full technology application process and the supportive results of the first field trial conducted in an unconventional shale gas well. The second paper discusses the application of the fishbone stimulation system and technique in a tight carbonate oil-bearing formation. Fishbone stimulation has been around for several years now, but its best applications and potential have not necessarily been fully understood in the well-stimulation community. This paper summarizes a successful pilot application resulting in a multifold increase in oil-production rate and walks the reader through the details of the pilot candidate selection, completion design, operational challenges, and lessons learned. The third paper introduces and proposes a chemical treatment to alleviate phase trapping in tight carbonate gas reservoirs. Phase trapping can be in the form of water blocking or increasing condensate buildup from near the wellbore and extending deeper into the formation over time. Both can reduce relative permeability to gas severely. Water blocks can be a one-time occurrence from drilling, completion, workover, or stimulation operations and can often be treated effectively with solvent plus proper additive solutions. Similar treatments for condensate banking in gas wells, however, can provide only temporary alleviation, if they are even effective. This paper proposes a technique for longer-term remediation of phase trapping in tight carbonate gas reservoirs using a unique, slowly reactive fluid system. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200345 - Insights Into Field Application of Enhanced-Oil-Recovery Techniques From Modeling of Tight Reservoirs With Complex High-Density Fracture Network by Geng Niu, CGG, et al. SPE 201413 - Diagnostic Fracture Injection Test Analysis and Simulation: A Utica Shale Field Study by Jeffery Hildebrand, The University of Texas at Austin, et al.

Research on Critical Liquid-Carrying Model in Wellbore and Laboratory Experimental Verification

Liquid loading in gas wells may slash production rates, shorten production life, or even stop production. In order to reveal the mechanism of liquid loading in gas wells and predict its critical flowrates, theoretical research and laboratory experiments were conducted in this work. A new model of liquid-film reversal was established based on Newton’s law of internal friction and gas–liquid two-phase force balance, with the critical reverse point obtained using the minimum gas–liquid interface shear force method. In this model, the influences of the pipe angle on the liquid film thickness were considered, and the friction coefficient of the gas–liquid interface was refined based on the experimental data. The results showed that the interfacial shear force increases by increasing the liquid superficial velocity, which leads first to an increase of the critical liquid-carrying gas velocity and then to a decrease, and the critical production also decreases. With 0° as the vertical position of the pipeline and an increase of the inclination angle, the critical liquid-carrying velocity first increases and then decreases, and the maximum liquid-carrying velocity appears in the range of 30–40°. In addition, the critical liquid-carrying gas velocity is positively correlated with the pipe diameter. Compared with the previous model, the model in this work performed better considering its prediction discrepancy with experiment data was less than 10%, which shows that the model can be used to calculate the critical liquid-carrying flow rate of gas wells. The outcome of this work provides better understanding of the liquid-loading mechanism. Furthermore, the prediction model proposed can provide guidance in field design to prevent liquid loading.

Experimental Study on Deliquification with Atomizing Nozzle in Gas Well

Gas is a clean energy resource in comparison with oil and coal. Liquid-loading problem is frequently encountered in the process of gas production. It would directly cause the production of gas wells decreasing, even off production. A number of deliquification techniques have been suggested for solving this kind of problem, but the available techniques are not yet widely applicable. Based on the analysis, the method of deliquification with atomizing nozzle in gas wells was put forward. The test bench was designed for studying the atomization of nozzles and the liquid entrainment of gas flow. The size distribution of atomized droplets was measured by Malvern laser grain size analyzer. The Sauter mean diameters of atomized droplets were analysed under different two-phase flow conditions. The results indicate that the designed nozzles have good atomization performances and show potential application for reducing liquid loading in gas wells.

Experimental evaluation of nozzles to mitigate liquid loading in gas wells

An optimally designed nozzle can be used as an efficient artificial lift system to deliquify gas wells. The objective of this work is to determine the most optimum nozzle parameters and geometry that would maximize critical pressure ratio while minimizing pressure drop across the nozzle under two-phase flow conditions. Six optimum nozzle geometries, evaluated under single-phase flow conditions in a previous study, are evaluated in this work. Two separate facilities were used to conduct the two-phase (air and water) experiments: a horizontal facility with 1.5 in. inner diameter (ID) PVC pipelines and a 30 ft long lateral pipeline section, and a vertical facility with 1.5 in. ID PVC pipelines and a 30 ft long vertical pipeline section. The horizontal facility was used to study the effect of introducing water into the system as a second phase, and the vertical facility was used to simulate conditions of a gas well with a nozzle installed as an artificial lift system. Horizontal flow experimental results showed that critical pressure ratio decreases for two-phase flow relative to single-phase flow. The distance of the annular churn flow pattern observed downstream the nozzle may be related to the nozzle performance; significantly lower performance was observed for the LJ nozzle in two phase horizontal testing relative to other nozzles – one characteristic this might be attributed to is the peculiarly longer distance of downstream annular churn flow pattern observed for this particular nozzle compared to other nozzles. Based on data analysis, the ASTAR nozzle group showed the most improved performance, similar to results obtained in single-phase horizontal testing. Based on vertical experimental results, the most optimum nozzle geometry to deliquify a loaded gas well was identified as the ASTAR nozzle 2, a parabolic nozzle geometry. A significant temperature drop downstream the nozzle was observed during these experiments. It is important to account for temperature change while designing a nozzle in order to avoid flow assurance problems, such as gas hydrate formation. The trends observed in relative performance between different nozzle geometries (rankings based on critical pressure ratio and pressure drop) for two-phase vertical experiments were similar to those observed for single-phase horizontal experiments. Therefore, single-phase experiments could be sufficient to evaluate relative nozzle geometry performance based on critical pressure ratio, for the conditions used in this study.

On the Development of a Model for the Prediction of Liquid Loading in Gas Wells with an Inclined Section

The ability to predict liquid loading in horizontal gas wells is of great importance for determining the time of drainage and optimizing the related production technology. In the present work, we describe the outcomes of experiments conducted using air-water mixtures in a horizontal well. The results show that the configuration with an inclined section is the most susceptible to liquid loading. Laboratory experiments in an inclined pipe were also conducted to analyze the variation of the critical gas flow rate under different angles, pressure and liquid volume (taking the equal liquid volume at inlet and outlet as the criterion for judging on the critical state). According to these results, the related angle of the inclined section ranges from 45° to 60°. Finally, a modified approach based on the Belfroid model has been used to predict the critical gas flow rate for the inclined section. After comparison with field data, this modified model shows an accuracy of 96%, indicating that it has better performances with respect to other models used in the past to predict liquid loading.

Title: Li and Turner Modified model for Predicting Liquid Loading in Gas Wells

BackgroundLiquid loading of gas wells causes production difficulty and reduces ultimate recovery from these wells. Several authors proposed different models to predict the onset of liquid loading in gas wells, but the results from the models often show discrepancies. Turner’s et al. (J Pet Technol, 1969) critical model was developed based on the assumption that the droplet is a sphere and remains spherical all through the entire wellbore. On the other hand, Li’s model was developed based on the assumption the liquid droplets are flat in shape and remains same all through the wellbore. However, it is a well-known fact that the droplet alternates between spherical and flat during production operation. Invariably, the Turner’s model and the Li’s model would not be able to predict correctly the critical rate required to lift that droplet which is because the droplet deformation was not taken into account during the development of the models.Materials and methodsIn this work, a new improved model is developed and incorporated into Ms-Excel program to predict liquid loading in gas wells. In the new model, a deformation coefficient “C” is introduced to cater for the deformation of the liquid droplet along the wellbore and in turn be able to predict correctly the critical rate when the droplet varies from the spherical shape to the flat shape.ResultsResults from the analysis carried out revealed 35% error on from Turner’s model, 26% error on Li’s model, whereas the new model yielded 20% error.ConclusionThe new developed software and model proved to be more accurate in predicting onset of liquid loading.

A calculation model of critical liquid-carrying velocity of gas wells considering the influence of droplet shapes

To clarify the existence of liquid loading and optimize the production allocation in gas wells, we constructed a model for calculating the critical liquid-carrying velocity based on the equal relationship between the total surface free energy of droplets and the total turbulent kinetic energy of gas and considering the droplet size, droplet deformation and the influence of droplet deformation on surface free energy. Based on the ellipsoid hypothesis and by analyzing the influence of droplet deformation on the surface area and free energy of droplets, the equation for calculation of the maximum diameter of windward surface of droplets was developed. With consideration to the influence of droplet deformation on drags, the expression for the critical liquid-carrying velocity of ellipsoid droplets was clarified. With consideration to the influence of deformation and internal flow of droplets, the drag coefficient of the ellipsoid droplets was determined to be 20% higher than that of the Brauer Model for spheroid. A functional relationship between the deformation parameter K and the critical Weber number Wec was established based on the energy conservation law. In addition, the calculation results were reduced by 10%. During the course, the impacts of gas-well pressure and temperature on surface tension were taken into account. The proposed model was compared with the models developed by Turner, Li Min, Wang Yizhong, Wang Zhibin and Xiong Yu, and on-site verification was conducted in 44 gas wells. The results show that the proposed model provides the prediction results in best coincidence with the actual performance of gas wells. In conclusion, the proposed model can be used to predict liquid loading in gas wells effectively.

Modelling mist flow for investigating liquid loading in gas wells

This paper presents a dynamic simulation approach to investigating liquid loading in gas wells for a fluid flowing in the mist flow regime. Two-component gas-liquid two-phase flow is considered, using coupled thermodynamic and hydrodynamic models as well as constitutive equations that incorporate the Peng-Robinson equation of state and the convex hull algorithm. The behaviour of the flow properties is investigated as phase change occur during flow. The accumulation of liquids is explored by investigating the distribution of the liquid density in the tubing, which is explicitly determined from the flow variables. The calculated phase densities are validated using data obtained from NIST RefProp and the results show good agreement. This procedure can provide substantial benefits in investigating the phenomena of liquid loading in gas wells compared to critical velocity predicting models that determine the stagnation velocity under isothermal conditions.

Liquid loading in gas wells: From core-scale transient measurements to coupled field-scale simulations

Liquid loading is a major operational constraint in mature gas fields around the world. It manifests itself as an increasing back pressure on the reservoir due to a rising liquid column in the well, which initially decreases deliverability, then ultimately causes the gas well to cease production. Theoretically, every gas well will experience this debilitating phenomenon in the latter stages of its producing life.In this paper, both laboratory experiments and numerical simulations are presented to shed more light on the physical process of liquid loading, with a focus on reservoir responses. On the one hand, core-flooding experimental setups of different scales were designed and constructed to investigate back pressure effects on transient flow through the near-wellbore region of the reservoir. On the other hand, the modelling of a gas well undergoing controlled flow and shut-in cycles was performed to validate core-scale observations at reservoir scale, using commercial integrated numerical software that connects a transient wellbore model to a transient reservoir model. The simulated transient characteristics of short-term downhole dynamics (e.g. liquid re-injection and co-current/counter-current flows) supported the U-shaped concept observed in the experiments.The detected temporal distribution of pore fluid pressure within the reservoir medium itself (referred to as the U-shaped pressure profile) was observed both experimentally at the core-scale and numerically at the reservoir-scale. This pressure distribution can be used to explain re-injection of the denser phases into the near-wellbore region of the reservoir.