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Abstract A new mechanistic model to predict the natural separation efficiency in vertical pumped wells has been developed. The model is based on the combined phase momentum equations and a general slip closure relationship. New drag coefficient correlations have been developed corresponding to the bubbly (i.e. undistorted particle) and churn-turbulent flow regimes. The model indicates that the natural separation efficiency depends strongly on geometry, void fraction and in-situ gas flow rate. Introduction Natural phase separation within the tubing-casing annulus is an integral part of the overall bottomhole separation process for pumped wells. For ESP systems, natural separation determines the amount of free gas entering the pump and thereby influences the overall pumping efficiency. Alhanati developed a theoretical model to predict the natural separation efficiency for ESP systems utilizing a rotary gas separator. The model demonstrates good agreement with experimental data gathered by Alhanati and Sambangi utilizing water and air as the pumped fluids, and by Lackner utilizing hydrocarbon and air as the pumped fluids. The experimental data cover GLR values ranging from 50 to 300 scf/STB, pressure values up to 300 psi and liquid flow rates up to 3600 BPD. The equivalent in-situ uniform annulus void fractions range from 25 to 70 percent. However, as successful as this model was for their situation, the model fails to match the data taken by Serrano. The Serrano4 data set has void fractions ranging from 5 to 15 percent. As a result, Serrano extended Alhanati's model by developing an empirical correlation that is capable of predicting the local void fraction for the region in front of the pump inlet ports. However, this model continues to utilize the no-slip assumption. The model was based on water-air experimental data, where the in-situ void fraction around the motor section ranges up to 20 percent, and for inclination angles of 30, 60 and 90 degrees from horizontal. The correlation was developed for both the bubbly and slug flow regimes. Due to the nature of how the correlation was developed, Serrano's model cannot be utilized in situations where the void fraction is greater than 20 percent. The objective of this work is to develop a more comprehensive model for natural gas separation in vertical wells. The model will cover the full range of void fractions as well as supplying a physical explanation about the natural separation process in vertical pumped wells. The new model is based on the combined-phase momentum equations and a general slip closure relationship, applied to a single control volume situated in front of the pump intake ports. Literature Review Lea and Bearden performed experimental studies of electrical submersible pump performance as free gas is introduced into the pumped fluid. Since their main objective was to investigate pump head degradation due to the presence of free gas, a detailed discussion regarding the natural separation process was absent. Their experimental data indicate that the annulus separation efficiency increases as more free gas is fed into the system and decreases as the liquid flow rate increases. Schmidt and Doty as well as Podio et al. discussed the natural separation process in conjunction with utilizing a gas anchor in beam pumping installations. However, there is no detail theoretical explanation that is directly applicable to the modeling development in this study.
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
- Production and Well Operations > Artificial Lift Systems > Beam and related pumping techniques (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (1.00)
Summary A new mechanistic model to predict natural separation efficiency in vertical pumped wells has been developed. The model is based on the combined phase momentum equations and a general slipclosure relationship. New drag-coefficient correlations have been developed that correspond to bubbly (i.e., undistorted particle) and churn-turbulent flow regimes. The model indicates that natural separation efficiency depends strongly on geometry, void fraction, and in-situ gas flow rate. Introduction Natural phase separation within a tubing-casing annulus is an integral part of the overall bottomhole separation process for pumped wells. For electrical submersible pump (ESP) systems, natural separation determines the amount of free gas entering the pump, which, in turn, influences the overall pumping efficiency. Alhanati developed a theoretical model to predict the natural separation efficiency of ESP systems with a rotary gas separator. The model demonstrated good agreement with the experimental data gathered by Alhanati and Sambangi that used water and air as the pumped fluids and by Lackner, who employed hydrocarbon and air as the pumped fluids. The experimental data cover the gas/liquid ratio (GLR) values, which ranged from 50 to 300 scf/ STB, pressure values up to 300 psi, and liquid flow rates up to 3,600 B/D. The equivalent in-situ uniform annulus void fraction's range was from 25 to 70%. However, as successful as this model was for their situation, the model failed to match the data taken by Serrano, which had void fractions ranging from 5 to 15%. As a result, Serrano extended Alhanati's model by developing an empirical correlation capable of predicting the local void fraction for the region in front of the pump inlet ports. However, this model continued to use the no-slip assumption in the radial direction. The model was based on water-air experimental data, in which the in-situ void fraction around the motor section varied between 0 and 20% for inclination angles of 30, 60, and 90° from horizontal. The correlation was developed for both bubbly and slug flow regimes. Because of how the correlation was developed, Serrano's model cannot be used in situations in which the void fraction is greater than 20%. The objective of the work presented here is to develop a more comprehensive model for natural gas separation in vertical wells. The model covers the full range of void fractions and supplies an analytical explanation about the natural separation process in vertical pumped wells. The new model is based on the combinedphase momentum equations and a general slip-closure relationship applied to a single control volume situated in front of the pump intake ports. Literature Review Lea and Bearden performed experimental studies to determine the effect of free gas introduced into the pumped fluid on the performance of an ESP. Because their main objective was to investigate pump head degradation caused by the presence of free gas, a detailed discussion regarding the natural separation process was not included. Their experimental data indicated that the annulus separation efficiency increases as more free gas is fed into the system and decreases as the liquid flow rate increases. Schmidt and Doty as well as Podio et al. discussed the natural separation process in conjunction with using a gas anchor in beampumping installations. However, there is no detailed theoretical explanation directly applicable to the model developed in this study. Alhanati developed a mechanistic model to predict the efficiency of an ESP rotary gas separator. As part of the model, he produced a simple model to predict the natural separation efficiency of ESP systems. The main assumptions in this model are that a uniform void fraction exists within the region surrounding the motor section up to the gas outlet ports and that a no-slip condition exists between the gas and liquid phases for the region in front of the gas separator's intake ports. Based on these assumptions, the annulus efficiency can be calculated with the following formula. Equation 1 in which vsl=the liquid superficial velocity and v8 =the terminal bubble rise velocity expressed by Harmathy as Equation 2 Alhanati gathered some experimental data with a full-scale water-air experimental facility. The facility incorporated an ESP assembly with a 4.5-in. motor housing located inside a 6.3-in. casing. This model demonstrated reasonable agreement with his experimental data for gas void fractions ranging between 20 and 70%. Sambangi gathered additional data on a water-air system to further validate the Alhanati model. No significant modifications to the model were required by the new data set. Lackner investigated the effects of fluid properties (mainly viscosity) on the separation efficiency of an ESP rotary gas separator. Some experimental data were gathered from a field-scale hydrocarbon-air system in which mineral oils with viscosities of approximately 18 to 50 cp at 60°F were used as the liquid phase. Verification of the Alhanati model by Lackner's experimental data indicates that the model can be applied to viscous fluids when viscosity values fall within the range used in the investigation. Serrano studied the effect of the ESP system's inclination angle on its natural separation efficiency. Using a full-scale water air ESP experimental facility with a 3.75-in. outer diameter (OD) motor housing located inside a 5-in. inside diameter (ID) casing, Serrano gathered 36 data points for vertical flow with void fractions as high as 15%. Based on his experimental work, Serrano found that the void fraction across the annulus is different from the void fraction that enters the pump. He developed some empirical correlations to calculate the void fraction going into the pump (ap) as a function of the void fraction within the annulus (ai) and the inclination angle (?) for two different flow regimes (i.e., bubbly and churn).
- North America > United States (0.46)
- South America > Venezuela (0.28)
- South America > Brazil (0.28)
- North America > Mexico > Veracruz > Tampico-Misantla Basin > San Andres Field (0.99)
- North America > United States > Oklahoma > Bearden Field (0.89)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (1.00)
Abstract Downhole Natural Gas Separation Efficiency (NGSE) is flow regime dependent, and current analytical models in certain conditions lack accuracy. Downhole NGSE was investigated through 3D Computational Fluid Dynamics (CFD) transient simulations for pumping wells in the Churn flow regime. The Volume of Fluid (VOF) multiphase model was considered along with the k – ε turbulence model for most simulations. A mesh independence study was performed, and the final model results validated against experimental data, showing an average error of less than 6 %. Numerical simulation results showed that the steady state assumption used by current mathematical models for churn flow can be inaccurate. Several key parameters affecting the NGSE were identified, and suggestions for key improvements to the widely used mathematical formulations for viscous flow provided. Sensitivity studies were conducted on fluid/geometric parameters and operating conditions, to gain a better understanding of the influence of each parameter on NGSE. These are important results as they equip the ESP engineer with additional knowledge to maximise the NGSE from design stage to pumping operations.
Summary Electrical submersible pump (ESP) installations are commonly used in the oil industry to aid fluid flow from the reservoir to the surface. As with any pump, the presence of free gas at the pump intake can adversely affect the operation of an ESP. One method of reducing the amount of free gas the pump has to process is to install a rotary gas separator. In this work, the effect of viscosity on the separator's performance is investigated. New experimental data were gathered that covered a broad range of operational conditions in terms of pressures, liquid flow rates, gas-liquid ratios (GLRs), and rotational speeds. The experiments were conducted on a field-scale experimental facility with a commercially available separator. The working fluids were water, two mineral oils, and air. An existing mechanistic model (based on physical principles) predicting the bottomhole gas-separation efficiency in ESP installations was then evaluated with the data. Based on this investigation, improvements were implemented in the model to better capture the influence of viscosity on the downhole gas-separation process. The results of the study indicate that there are two regions of separation efficiency with a pronounced transition between them: one region in which the rotary gas separator is very effective (separation efficiencies between 80 and 100%), and the other in which it is not effective at all (separation efficiencies between 30 and 55%). The transition location depends on the fluid physical properties, operational conditions, and geometry of the separator. The mechanistic model can predict this behavior and agrees well with the data that are obtained during this investigation. Fluid viscosity in the range of investigation (1 to 50 cp at 100°F) is found to have only little influence on gas-separation efficiency. This may indicate that the effects of turbulence at high rotational speeds dominate the behavior of flow inside the separator. Introduction When the pressure in an oil well is insufficient to push the liquid to the surface or to sustain the flow at an adequate rate, an artificial lift system must aid the natural flow. Such a method supplements the natural driving force of the reservoir and increases the production rate by reducing the flowing bottomhole pressure. From the available artificial lift methods, the oil industry commonly chooses electrical submersible pumps (ESP). A typical ESP installation is depicted in Fig. 1; operational details are described elsewhere. The desire for an extended period of maximum production without creating unfavorable operating conditions governs the design of an ESP installation. To avoid low efficiency and operational problems, one parameter that needs to be monitored is the presence of free gas at the pump intake. As with any pump, an ESP is only able to handle a certain percentage of free gas. Ref. 4 established a critical value of 10% free gas by volume that an ESP can handle without a problem. Beyond this value, action has to be taken to avoid shutdowns and improve ESP performance. Several options are available to improve ESP performance in gassy oil wells. One is to install a gas separation device ahead of the ESP, preferably a rotary gas separator (see Fig. 2). The question remains of how effective the rotary gas separator is for different operational conditions. The literature gives an extensive performance overview for these separators under field conditions. Some work has been done to study them in the laboratory; however, no quantitative modeling effort whatsoever has been reported, except for one study. Most authors indicate that fluid physical properties influence the performance of the separator, but this issue has never been examined. In summary, until recently, bottomhole gas separation was poorly understood because no available and reliable quantitative model for gas-separation efficiency existed. Ref. 14 for the first time presented a mathematical model, based on fundamental physical principles, to predict bottom-hole gas separation efficiency. A relationship was developed that predicts the efficiency of the separator as a function of the amount of produced gas and liquid, operational conditions, and downhole geometry. Experimental data taken on a field-scale test facility, with air and water as working fluids, matched the theoretical findings. The result of the study indicates that there are two distinct regions of separation efficiency divided by a sharp transition (see Fig. 3). In one region, the separation efficiencies are between 80 and 100%, while in the other, they are between 30 and 55%. The location of the transition region depends on fluid physical properties, operational conditions, and geometry. The only limitations to the applicability of the model cited in this study were the well inclination angle and liquid viscosity. The final result is a practical design tool in determining rotary gas separator efficiencies that are applicable to the majority of field conditions. In light of the previous study and the available information, the goal of this study was to extend and improve the existing model, focusing on viscosity and turbulence effects. Specifically, the goals for this work include:Modification of an existing experimental facility to gather new data with different fluids. Obtain a full set of data using a fluid with a viscosity of at least one order of magnitude greater than water. Investigate the turbulent two-phase phenomena associated with the separation process. Study the effect of liquid viscosity on the separation process. Implement the experimental and theoretical findings into the model. The Downhole Gas-Separation Process To properly study the bottomhole gas separation process both experimentally and theoretically, one must understand the mechanisms involved. First, some of the produced gas will always be separated because of annulus ventilation. This phenomenon, commonly called annulus or natural gas separation, is caused by gravity. The remaining free gas and the liquid are sucked into the rotary gas separator (see Fig. 2). Upon entering the equipment, the fluid mixture is pressurized in the inducer section and separated inside the separation chamber by centrifugal forces and density differences. The centrifugal forces push denser liquid to the outside, while the less dense gas accumulates near the center. Finally, the crossover section feeds the pump with the heavier fluid and expels the lighter fluid back into the annulus.
- South America > Venezuela > Zulia > Maracaibo Basin > Ayacucho Blocks > Boscan Field > Rob-l Formation (0.99)
- South America > Venezuela > Zulia > Maracaibo Basin > Ayacucho Blocks > Boscan Field > Misoa Formation (0.99)
- South America > Venezuela > Zulia > Maracaibo Basin > Ayacucho Blocks > Boscan Field > Icotea Formation (0.99)
- (2 more...)
Abstract An improved model is presented capable of predicting the separation efficiency of a rotary gas separator in ESP systems. The model incorporates a new two-phase flow inducer model capable of calculating the inducer head. The inducer head generated by a rotary gas separator has been identified as a key parameter that distinguishes between a separator's high and low efficiency regions. This information was previously determined empirically, but now can be calculated. The new model predicts more accurately the liquid rate at which a rotary gas separator should be installed. A comparison of the model's predictions with water-air and hydrocarbon-air experimental data indicates that the improved model performs better than earlier models. Introduction In designing ESP systems for gassy oil wells, a rotary gas separator (RGS) is still one of the most commonly used gas handling devices capable of minimizing the amount of free gas going into the ESP pump section (Fig. 1). The basic components of an RGS consist of intake ports, an inducer section, a centrifuge chamber as well as cross-over and outlet ports (Fig. 2). After entering the RGS through the intake ports, the gas and liquid phases are pressurized by the inducer section, and then separated in the centrifuge chamber by centrifugal force. Due to centrifugation, the liquid, as the heavier component, is pushed toward the outer wall while the gas, as the lighter component, accumulates at the center. The crossover re-directs the liquid phase back to the center thereby allowing it to continue its path toward the ESP pump section. Meanwhile, the gas is re-directed toward the outer wall and is expelled back into to the annulus through the outlet ports. An ESP system design for gassy oil wells should address two important questions:how much free gas can an RGS separate, and at what maximum liquid rate, if any, should the RGS be installed? The importance of answering these questions is two fold. First, the amount of remaining free gas exiting the RSG corresponds to the amount of free gas that the ESP must ultimately handle, which in turn affects the pump's performance. Second, ESP system mechanical integrity must be guaranteed. Since one of the main issues related to ESP operation is vibration, this sets an additional guideline of whether or not to install an RGS. In an attempt to answer the above questions, Alhanati developed a mechanistic model to predict the separation efficiency of an RGS. Based on his model, the separation process in an RGS system occurs in two distinct flow domains; i.e., within the tubing-casing annulus and within the centrifuge chamber inside the RGS (Fig. 3). The separation process will take place, as long as the inducer can provide enough head (?P+) to compensate for the pressure drop across the outlet ports (?P-). A typical separation efficiency curve, as predicted by the Alhanati model, shows three distinct efficiency regions (high, transition and low) as a function of the liquid flow rate (Fig. 4). The high efficiency region reflects the combined separation efficiency occurring within both the tubing-casing annulus and the centrifuge chamber. The transition region corresponds to the flow rates where the inducer is overloaded, and is no longer able to provide enough head to compensate for the pressure drop across the outlet ports. Under these conditions, some of the gas separated within the centrifuge chamber will not be expelled back into the casing. The low efficiency region corresponds to a situation where none of the free gas entering the RSG is expelled back into the casing. Under these conditions, the separation efficiency of the RGS is reduced to the natural separation efficiency occurring within the tubing-casing annulus. The Alhanati model has been verified by experimental data gathered by Sambangi and him for water-air systems, and by Lackner for hydrocarbon-air systems.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)