A Gas Separation Model for a Downhole Gravitational Separator
Abstract: Summary Pumping systems reduce their efficiency and lifetime when working with free gas at the pump inlet. Downhole gas separators are usually installed upstream of the pump in oil production wells to avoid free gas, but they cannot handle high void fraction. Studies on the so-calledinverted-shroud gravitational separator indicate that it is possible to achieve gas separation efficiencies (GSEs) higher than 97%, even in the presence of very high void fraction. Gas separation inside this kind of … Show more
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Cited by 3 publications
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Accurate Gas-To-Pump Calculation in Pumping Oil Wells from Surface Data Using Combined Analytical Modeling of Gaseous Static Liquids Gradient: Part 1
Among the many available methods for determining pump intake pressure and flowing bottom hole pressure in pumping wells, there remains the practical need to both reduce the input field data modeling requirements (carbon and cost reduction) and to combine the different but related concurrent, countercurrent and column multiphase flow phenomena governing the calculation (accuracy improvement). This paper furnishes both lab- and field-validated analytical multiphase modeling methods showing the various ways the discovered triangular interrelationship between pump intake pressure, gaseous static liquid level and downhole gas separation efficiency changes in response to different sensitivities. The pressure distribution along the entire multiphase flow path of the pumping oil well, including between the pump intake pressure and flowing bottomhole pressure at reservoir depths, is also modeled in detail. A notable difference in this work in reference to prior works of pump intake pressure and gas-to-pump (i.e., gas holdup at pump intake region) modeling is a more detailed physics-based understanding of how gas holdup changes and develops along the gaseous static liquid column above the downhole packer-less pump. In this way, using an easy-to-compute, zero-cost, independently reproducible, published model for bubbly to churn flow in combination with a cutting edge commercial analytical multiphase flow simulator, we first validate the simulator results with published lab datasets of developing gas flow through static liquid columns under carefully controlled conditions. Then, several published field datasets of producing oil wells with liquid levels are simulated to confirm the extensibility of our model to actual field wells and currently-active production operations. In these field validations, the transient countercurrent liquids loading feature of the simulator is utilized to determine the prevailing liquid level. We then additionally perform several important sensitivities showing the various ways that pump intake pressure, flowing bottomhole pressure, gaseous static liquid level, and downhole gas separation efficiency changes in response to different hydraulic diameters, flowing areas, casing-annulus clearances (e.g., ESP versus rod pump), liquid column flow patterns, axial developing flow lengths, and wellbore inclination. Regarding our liquid level buildup simulations, we demonstrate the effect that liquid levels have on dictating the possible operating limits on highest and lowest downhole gas separation efficiencies. This work represents a step change in our understanding of the aspect of multiphase flows that is most pertinent to artificial lift: accurate critical gas velocity prediction leading to reliable modeling of countercurrent multiphase liquid loading and gas flow along static liquid columns. We lay the foundation for a change in conversation among the artificial lift community for paying much more practical attention as well as research interest into the multiphase countercurrent and gaseous static liquid column flow behaviors prevalent in the majority pumping oil wells and liquids loaded gas wells. To this end, a new industry digital computing capability is presented and comprehensively validated in both this paper and the part-2 paper of this paper series (Nagoo et al., 2022a): the ability to perform multiphase countercurrent liquid loading simulations that dynamically loads a pumping oil well casing-annulus or gas well tubing/casing, and the reliable calculations of the total pressure gradient that varies with the increasing gas holdup along the static liquid column of these wells. This means that for pumping oil wells (SRP, ESP, PCP, etc.), the pump intake pressure, flowing bottomhole pressure at reservoir depths, downhole gas separation efficiency and static gaseous liquid level above the pump can now be simultaneously simulated from only basic surface field data. For the part-2 paper, our new method is used to calculate the static gaseous liquid levels in liquid loaded gas wells from only basic surface field data. In terms of digital twin applications for the oilfield, our new methods can be performed in real-time in an autonomous way on an IIOT-enabled (IIOT = industrial internet of things) wellhead device to continuously optimize production to create value at scale. We term this device a "wellbore liquid level digital sensor": a solution that takes in real-time SCADA (supervisory control and data acquisition) surface data and converts it to automated calculations of pump intake pressure, flowing bottomhole pressure, downhole gas separation efficiency, gaseous static liquid column height and gas holdup profile along the static liquid column. This is an industry-first, at-scale, digital oilfield solution purpose built for low-carbon downhole diagnostics and real-time autonomous production optimization calculations. Such calculations are used to drive the real-time production operations decisions needed for minimizing lifting costs and minimizing unplanned shut-downs and pump/equipment failures. Indeed, a net-zero future for the oil and gas industry on a whole relies on the digital innovations like those provided in this large body of work to empower energy transformation, and to manage/harness the immense amount of asset data in ways that was not possible before. Incorporating novel digital solutions in day-to-day oil and gas production operations will improve engineer productivity (higher value creation) as well as corporate profitability (safer, lower-carbon operations) by streamlining downhole calculations, analyses, operational performance indicators, and cutting costs for better decision-making support.
Accurate Gas-To-Pump Calculation in Pumping Oil Wells from Surface Data Using Combined Analytical Modeling of Gaseous Static Liquids Gradient: Part 1
Among the many available methods for determining pump intake pressure and flowing bottom hole pressure in pumping wells, there remains the practical need to both reduce the input field data modeling requirements (carbon and cost reduction) and to combine the different but related concurrent, countercurrent and column multiphase flow phenomena governing the calculation (accuracy improvement). This paper furnishes both lab- and field-validated analytical multiphase modeling methods showing the various ways the discovered triangular interrelationship between pump intake pressure, gaseous static liquid level and downhole gas separation efficiency changes in response to different sensitivities. The pressure distribution along the entire multiphase flow path of the pumping oil well, including between the pump intake pressure and flowing bottomhole pressure at reservoir depths, is also modeled in detail. A notable difference in this work in reference to prior works of pump intake pressure and gas-to-pump (i.e., gas holdup at pump intake region) modeling is a more detailed physics-based understanding of how gas holdup changes and develops along the gaseous static liquid column above the downhole packer-less pump. In this way, using an easy-to-compute, zero-cost, independently reproducible, published model for bubbly to churn flow in combination with a cutting edge commercial analytical multiphase flow simulator, we first validate the simulator results with published lab datasets of developing gas flow through static liquid columns under carefully controlled conditions. Then, several published field datasets of producing oil wells with liquid levels are simulated to confirm the extensibility of our model to actual field wells and currently-active production operations. In these field validations, the transient countercurrent liquids loading feature of the simulator is utilized to determine the prevailing liquid level. We then additionally perform several important sensitivities showing the various ways that pump intake pressure, flowing bottomhole pressure, gaseous static liquid level, and downhole gas separation efficiency changes in response to different hydraulic diameters, flowing areas, casing-annulus clearances (e.g., ESP versus rod pump), liquid column flow patterns, axial developing flow lengths, and wellbore inclination. Regarding our liquid level buildup simulations, we demonstrate the effect that liquid levels have on dictating the possible operating limits on highest and lowest downhole gas separation efficiencies. This work represents a step change in our understanding of the aspect of multiphase flows that is most pertinent to artificial lift: accurate critical gas velocity prediction leading to reliable modeling of countercurrent multiphase liquid loading and gas flow along static liquid columns. We lay the foundation for a change in conversation among the artificial lift community for paying much more practical attention as well as research interest into the multiphase countercurrent and gaseous static liquid column flow behaviors prevalent in the majority pumping oil wells and liquids loaded gas wells. To this end, a new industry digital computing capability is presented and comprehensively validated in both this paper and the part-2 paper of this paper series (Nagoo et al., 2022a): the ability to perform multiphase countercurrent liquid loading simulations that dynamically loads a pumping oil well casing-annulus or gas well tubing/casing, and the reliable calculations of the total pressure gradient that varies with the increasing gas holdup along the static liquid column of these wells. This means that for pumping oil wells (SRP, ESP, PCP, etc.), the pump intake pressure, flowing bottomhole pressure at reservoir depths, downhole gas separation efficiency and static gaseous liquid level above the pump can now be simultaneously simulated from only basic surface field data. For the part-2 paper, our new method is used to calculate the static gaseous liquid levels in liquid loaded gas wells from only basic surface field data. In terms of digital twin applications for the oilfield, our new methods can be performed in real-time in an autonomous way on an IIOT-enabled (IIOT = industrial internet of things) wellhead device to continuously optimize production to create value at scale. We term this device a "wellbore liquid level digital sensor": a solution that takes in real-time SCADA (supervisory control and data acquisition) surface data and converts it to automated calculations of pump intake pressure, flowing bottomhole pressure, downhole gas separation efficiency, gaseous static liquid column height and gas holdup profile along the static liquid column. This is an industry-first, at-scale, digital oilfield solution purpose built for low-carbon downhole diagnostics and real-time autonomous production optimization calculations. Such calculations are used to drive the real-time production operations decisions needed for minimizing lifting costs and minimizing unplanned shut-downs and pump/equipment failures. Indeed, a net-zero future for the oil and gas industry on a whole relies on the digital innovations like those provided in this large body of work to empower energy transformation, and to manage/harness the immense amount of asset data in ways that was not possible before. Incorporating novel digital solutions in day-to-day oil and gas production operations will improve engineer productivity (higher value creation) as well as corporate profitability (safer, lower-carbon operations) by streamlining downhole calculations, analyses, operational performance indicators, and cutting costs for better decision-making support.
Efficiency of an Inverted-Shroud Gravitational Gas Separator: Effect of the Liquid Viscosity and Inclination
Summary Gas-liquid separation is a typical process in many applications. For instance, gas separation is critical for the proper operation of electrical submergible pumps in the oil and gas industry as the pumps’ performance and lifetime are severely reduced when working with high gas/oil ratios. Gas-liquid separators are installed in oil production wells to reduce the void fraction at the pump inlet. The inverted-shroud gravitational separator stands out due to its efficiencies higher than 97%. This separator performs the gas separation process in two stages. The first is a segregation process related to inversion from liquid to gas continuous flow, whereas the second stage is related to gas entrainment associated with kinetic-energy dissipation process. The latter is more complex to model in the vertical than in the inclined separator’s position. Previous studies revealed that the liquid flow rate and separator’s inclination are relevant parameters for the gas separation efficiency (GSE). However, studies regarding the effect of the liquid viscosity on GSE are scanty. We evaluate the influence of the liquid viscosity and separator’s inclination on the GSE of an inverted-shroud separator (IS-separator) with water-air and oil-air mixtures. Efficiency maps for each inclination and empirical correlations to predict the GSE in the vertical inclination are proposed. New experimental data collected for several liquid flow rates and separator inclinations are offered in this study as a starting point to develop universal GSE maps. Different gas separation phenomena are observed depending on the flow pattern at the inner annular channel (IAC) of the separator and its inclination. The experiments conducted with the water-air mixture indicated turbulent flow, while the oil-air mixture revealed laminar flow for both inclined and vertical positions. The results suggest that the greater the liquid viscosity, the higher the GSE. The efficiency maps indicate that it is possible to reach total gas separation (TGS) for many experimental conditions. In practice, our approach proposes an alternative technology where the variables that influence the production well’s dynamic fluid level are actively controlled. Therefore, the IS-separator can operate under operational field conditions similar to those tested on a laboratory scale. This fact makes the IS-separator a promising tool for industrial applications.
Summary The void fraction is a basic parameter to characterize the two-phase flow. Accurate measurement of its value is of great significance for industrial production. In this study, an optical correction system combined with software and hardware is developed. Stereoscopic particle image velocimetry (SPIV) technology is used to measure the void fraction in gas/liquid two-phase stratified flow. The measurement results are compared with those of 2D particle image velocimetry under the same conditions, and the correction effect appears to be reasonably good. The void fraction value is obtained by the image processing of the corrected image. The accuracy of the measurement results is verified by comparing the experimental liquid-phase volumetric flow rate with that measured through a standard flowmeter. Twenty types of void fraction prediction models are evaluated using the mean absolute relative deviation (MARD), root mean square error (RMSE), and gray correlation analysis methods. The results suggest that the Armand (1946) model has the smallest MARD, RMSE value, the largest correlation degree (Ri) value, and the best prediction performance. On this basis, an improved model is proposed by fitting the relationship between void fraction and gas volume holdup.
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