A. Shakirov, E. Nikonov, Yaroslav Alexeev, S. Suheil
For decades standard V-belt transmission with an asynchronous motor has been a traditional method to drive beam pumping units. This study describes a new approach based on the use of a Permanent Magnet Motor with no transmission. Non-transmission drive integrates a permanent magnet motor (PMM) and smart variable frequency drive. Since rotor is mounted directly on the gearbox input shaft, with stator being mechanically attached to the gearbox housing, the technology eliminates the need for conventional V-belt transmission between the motor and the gearbox. Variable Speed Drive (VSD) can provide a more advanced control for the permanent magnet motor, embedding mathematical models with a number of options for motor speed and rod load control, operation monitoring, failure risk mitigation, and production optimization. Application results revealed unique features of the system, that cannot be reached with a standard application. Elimination of V-belt transmission allows for safe and environmentally friendly operation with enhanced reliability and reduced non-productive time as no maintenance is required. High-efficient PM Motor (with no losses in the transmission) improves power consumption and practically demonstrate total power savings of 15-35 % if compared to the previously installed systems. The PMM system is easy to install, with installation time being less than 1 hour. PM Motor principles of operation provide a number of options for its control through smart VSD algorithms requiring no additional sensors. Real-time up-stroke / down-stroke speed adjustment, torque control, operating trips detection and many other features can potentially improve production and expected runlife of downhole and surface equipment. The results of this study are intended to demonstrate an effective and efficient alternative for oil production with Sucker-Rod Pumps (SRP). Application of the new type of surface drive has proved its high potential for production optimization and power consumption improvement with minimized risk of failures.
{"title":"Application of Surface PM Motor Drive for Sucker Rod Pumps","authors":"A. Shakirov, E. Nikonov, Yaroslav Alexeev, S. Suheil","doi":"10.2118/209725-ms","DOIUrl":"https://doi.org/10.2118/209725-ms","url":null,"abstract":"\u0000 For decades standard V-belt transmission with an asynchronous motor has been a traditional method to drive beam pumping units. This study describes a new approach based on the use of a Permanent Magnet Motor with no transmission.\u0000 Non-transmission drive integrates a permanent magnet motor (PMM) and smart variable frequency drive. Since rotor is mounted directly on the gearbox input shaft, with stator being mechanically attached to the gearbox housing, the technology eliminates the need for conventional V-belt transmission between the motor and the gearbox. Variable Speed Drive (VSD) can provide a more advanced control for the permanent magnet motor, embedding mathematical models with a number of options for motor speed and rod load control, operation monitoring, failure risk mitigation, and production optimization.\u0000 Application results revealed unique features of the system, that cannot be reached with a standard application. Elimination of V-belt transmission allows for safe and environmentally friendly operation with enhanced reliability and reduced non-productive time as no maintenance is required. High-efficient PM Motor (with no losses in the transmission) improves power consumption and practically demonstrate total power savings of 15-35 % if compared to the previously installed systems. The PMM system is easy to install, with installation time being less than 1 hour.\u0000 PM Motor principles of operation provide a number of options for its control through smart VSD algorithms requiring no additional sensors. Real-time up-stroke / down-stroke speed adjustment, torque control, operating trips detection and many other features can potentially improve production and expected runlife of downhole and surface equipment.\u0000 The results of this study are intended to demonstrate an effective and efficient alternative for oil production with Sucker-Rod Pumps (SRP). Application of the new type of surface drive has proved its high potential for production optimization and power consumption improvement with minimized risk of failures.","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"20 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121208500","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Electrical submersible pumps (ESPs) must handle two-phase flow (liquid and gas) conditions in production wells. Pump stages are designed for liquid handling, and the pump performance is significantly affected by the presence of gas. ESPs are tested in two-phase flow conditions, and performance is measured stage by stage to improve the understanding of gas, its limitations, and its effects. ESPs are tested in a high-pressure, two-phase flow loop. Pumps are instrumented across stages for pressure measurements. Pumps are tested at intake pressures between 50 and 250 psi, with gas percentages of 0 to 95% maximum, and at different flow rates ranging from 40 to 70 Hz for complete performance mapping. The flow loop is capable of up to 80+% gas and 250 psi intake pressure at the pump intake, running up to 60 Hz, 300 HP, and 18,000 bpd of fluid. Pump performance is evaluated for the various gas conditions at various speeds and intake pressures. Pump performance is significantly affected in two-phase applications. The performance deteriorates with an increase in the gas percentage and improves with an increase in the speed and the intake pressure. Mixed flow pumps handle gas better than radial flow pumps. Larger diameter pumps have higher gas handling capabilities than smaller diameter pumps. Sizing taper pumps operating in a flow range higher than the BEP flow range and additional pump stages in the sizing provides longer life, higher reliability, and more efficient operation in gassy applications. Pump performance under various downhole conditions was investigated, and a new technique was developed for the sizing of ESPs in two-phase flow applications.
{"title":"Improve ESP Pump Sizing Through Enhanced Performance Prediction of ESP Stages in Two-Phase Flow Applications","authors":"K. Sheth, Donn J. Brown, Trevor Alan Kopecky","doi":"10.2118/209737-ms","DOIUrl":"https://doi.org/10.2118/209737-ms","url":null,"abstract":"\u0000 Electrical submersible pumps (ESPs) must handle two-phase flow (liquid and gas) conditions in production wells. Pump stages are designed for liquid handling, and the pump performance is significantly affected by the presence of gas. ESPs are tested in two-phase flow conditions, and performance is measured stage by stage to improve the understanding of gas, its limitations, and its effects.\u0000 ESPs are tested in a high-pressure, two-phase flow loop. Pumps are instrumented across stages for pressure measurements. Pumps are tested at intake pressures between 50 and 250 psi, with gas percentages of 0 to 95% maximum, and at different flow rates ranging from 40 to 70 Hz for complete performance mapping. The flow loop is capable of up to 80+% gas and 250 psi intake pressure at the pump intake, running up to 60 Hz, 300 HP, and 18,000 bpd of fluid. Pump performance is evaluated for the various gas conditions at various speeds and intake pressures.\u0000 Pump performance is significantly affected in two-phase applications. The performance deteriorates with an increase in the gas percentage and improves with an increase in the speed and the intake pressure. Mixed flow pumps handle gas better than radial flow pumps. Larger diameter pumps have higher gas handling capabilities than smaller diameter pumps.\u0000 Sizing taper pumps operating in a flow range higher than the BEP flow range and additional pump stages in the sizing provides longer life, higher reliability, and more efficient operation in gassy applications. Pump performance under various downhole conditions was investigated, and a new technique was developed for the sizing of ESPs in two-phase flow applications.","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"516 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116226825","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Carbon dioxide (CO2) is commonly used for enhanced oil recovery (EOR) in the Permian Basin and is gaining interest for Carbon Capture, Utilization & Storage. A study was conducted to develop candidate selection criteria, pilot test the design, and optimize CO2 gas lift to stabilize production on intermittently flowing wells in one of these EOR fields. The initial CO2 gas lift design was installed in 2019 using a capillary string, downhole check valve, gas lift mandrel, and packer. A 34-day bottomhole pressure and temperature survey was evaluated to assess the success of the pilot and improve the equipment design for future installations. The phase changes of CO2 were accounted for when evaluating the pilot, modeling gas lift, and improving equipment design. Carbon dioxide is a complex fluid at the bottomhole pressures (BHP) and temperatures (BHT) observed during the pilot. These pressures and temperatures were plotted on the CO2 phase diagram, which showed phase changes between vapor and liquid at higher gas lift injection rates. Further analysis revealed the CO2 changed phase from a liquid to a vapor across the downhole check valve. The Joule-Thompson (JT) effect across the check valve at the tubing entry point dropped the temperature of the produced fluids so much that the CO2 changed phase from a vapor back to a liquid. This increased the hydrostatic pressure and therefore, the bottomhole flowing pressure. These CO2 phase changes in the tubing occurred in cycles comprising five distinct stages: (1) BHT cooling forced CO2 from the vapor to liquid phase and increased BHP; (2) BHT remained fairly steady as BHP increased due to liquid loading; (3) BHT started warming at a faster rate as BHP rose due to the decreasing pressure drop across the downhole check valve; (4) the tubing unloaded as CO2 flashed in a chain reaction down the tubing, resulting in an influx of warmer reservoir fluid; and (5) BHT remained steady as BHP decreased and the annular packer fluid restarted the cooling process. Results from this initial pilot were used successfully to optimize CO2 gas lift for subsequent installations. CO2 gas lift can be an effective artificial lift method to stabilize production if the equipment is designed correctly to maximize the CO2 gas fraction at the tubing entry point. A poorly designed CO2 gas lift installation may result in unstable production from liquid loading events caused by the cyclic JT effect. CO2 gas lift is a valuable artificial lift method to reduce failure frequency and operating costs in EOR fields with readily available CO2.
{"title":"Production Optimization Using CO2 Gas Lift in EOR Fields: A Permian Basin Case Study","authors":"Melanie Brewer, Derek Andel, P. Bandyopadhyay","doi":"10.2118/209728-ms","DOIUrl":"https://doi.org/10.2118/209728-ms","url":null,"abstract":"\u0000 Carbon dioxide (CO2) is commonly used for enhanced oil recovery (EOR) in the Permian Basin and is gaining interest for Carbon Capture, Utilization & Storage. A study was conducted to develop candidate selection criteria, pilot test the design, and optimize CO2 gas lift to stabilize production on intermittently flowing wells in one of these EOR fields.\u0000 The initial CO2 gas lift design was installed in 2019 using a capillary string, downhole check valve, gas lift mandrel, and packer. A 34-day bottomhole pressure and temperature survey was evaluated to assess the success of the pilot and improve the equipment design for future installations. The phase changes of CO2 were accounted for when evaluating the pilot, modeling gas lift, and improving equipment design.\u0000 Carbon dioxide is a complex fluid at the bottomhole pressures (BHP) and temperatures (BHT) observed during the pilot. These pressures and temperatures were plotted on the CO2 phase diagram, which showed phase changes between vapor and liquid at higher gas lift injection rates. Further analysis revealed the CO2 changed phase from a liquid to a vapor across the downhole check valve. The Joule-Thompson (JT) effect across the check valve at the tubing entry point dropped the temperature of the produced fluids so much that the CO2 changed phase from a vapor back to a liquid. This increased the hydrostatic pressure and therefore, the bottomhole flowing pressure.\u0000 These CO2 phase changes in the tubing occurred in cycles comprising five distinct stages: (1) BHT cooling forced CO2 from the vapor to liquid phase and increased BHP; (2) BHT remained fairly steady as BHP increased due to liquid loading; (3) BHT started warming at a faster rate as BHP rose due to the decreasing pressure drop across the downhole check valve; (4) the tubing unloaded as CO2 flashed in a chain reaction down the tubing, resulting in an influx of warmer reservoir fluid; and (5) BHT remained steady as BHP decreased and the annular packer fluid restarted the cooling process. Results from this initial pilot were used successfully to optimize CO2 gas lift for subsequent installations.\u0000 CO2 gas lift can be an effective artificial lift method to stabilize production if the equipment is designed correctly to maximize the CO2 gas fraction at the tubing entry point. A poorly designed CO2 gas lift installation may result in unstable production from liquid loading events caused by the cyclic JT effect. CO2 gas lift is a valuable artificial lift method to reduce failure frequency and operating costs in EOR fields with readily available CO2.","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"54 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123500905","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Eduardo Teixeira da Silva, H. T. Rodrigues, André Luiz Guedes Maricato, Galileu Paulo Henke Alves De Oliveira, Giovanna de Castro, L. Guerra, Ricardo S. Fraga, G. Ribeiro
This paper presents the results obtained in an extensive Gas Lift Valves (GLVs)flow trials, which were performed in an experimental liquid flow test loop. The objective was to evaluate GLVs performance with respect to their back flow retention condition, after being exposed to large volumes of flowing liquids. In case of a check valve failure, remediation strategies were also presented and evaluated. Four different GLVs were subjected to brine flow. The tests consisted of a minimum of 15 flow cycles comprising a volume of 150 m3 (942 bbl) each, at a flowrate of 0.32 m3/min (2 bbl/min). In between cycles, the GLV was tested for back flow. The check valve test was performed with the GLV installed in its original position at the flow test loop (i.e., no need to disassemble the GLV and move it to another facility). In case of back flow failure detection, remediation strategies, such as flushing with industrial water and cycles of pressurization and depressurization, were tested. None of the four GLVs tested completed the minimum of 15 cycles without any failure. After flushing the system with industrial water, three GLVs regained its back flow retention capabilities and the other still presented the back flow failure. In some cases, the check valve presented failure when tested inside the flow loop, but did not present the same failure when moved to the Nitrogen/calibration test bench. This event has indicated the importance of testing the back flow retention inside the flow test loop. It was also observed that pressurization and de-pressurization speed can affect the results. Testing of liquid flow through GLVs usually involves a small volume of liquid, which may not be enough to cause problems with the check valve. In this paper we present new tests results with larger liquid volumes of liquid passing through the GLVs. The results are important to understand the condition of GLVs to handle higher flow liquid volumes.
{"title":"Long Term Testing of Liquid Flow Through Gas Lift Valves","authors":"Eduardo Teixeira da Silva, H. T. Rodrigues, André Luiz Guedes Maricato, Galileu Paulo Henke Alves De Oliveira, Giovanna de Castro, L. Guerra, Ricardo S. Fraga, G. Ribeiro","doi":"10.2118/209726-ms","DOIUrl":"https://doi.org/10.2118/209726-ms","url":null,"abstract":"\u0000 This paper presents the results obtained in an extensive Gas Lift Valves (GLVs)flow trials, which were performed in an experimental liquid flow test loop. The objective was to evaluate GLVs performance with respect to their back flow retention condition, after being exposed to large volumes of flowing liquids. In case of a check valve failure, remediation strategies were also presented and evaluated.\u0000 Four different GLVs were subjected to brine flow. The tests consisted of a minimum of 15 flow cycles comprising a volume of 150 m3 (942 bbl) each, at a flowrate of 0.32 m3/min (2 bbl/min). In between cycles, the GLV was tested for back flow. The check valve test was performed with the GLV installed in its original position at the flow test loop (i.e., no need to disassemble the GLV and move it to another facility). In case of back flow failure detection, remediation strategies, such as flushing with industrial water and cycles of pressurization and depressurization, were tested.\u0000 None of the four GLVs tested completed the minimum of 15 cycles without any failure. After flushing the system with industrial water, three GLVs regained its back flow retention capabilities and the other still presented the back flow failure. In some cases, the check valve presented failure when tested inside the flow loop, but did not present the same failure when moved to the Nitrogen/calibration test bench. This event has indicated the importance of testing the back flow retention inside the flow test loop. It was also observed that pressurization and de-pressurization speed can affect the results.\u0000 Testing of liquid flow through GLVs usually involves a small volume of liquid, which may not be enough to cause problems with the check valve. In this paper we present new tests results with larger liquid volumes of liquid passing through the GLVs. The results are important to understand the condition of GLVs to handle higher flow liquid volumes.","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130893289","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
G. González, L. Guanacas, C. Portilla, Neil Johnson Vazhappilly
A revolutionary packer-type gas separator was designed to improve downhole gas separation efficiency. A deep analysis of gas separation methods was done to understand the process's nature and design a tool that could generate enhanced conditions for the gas separation phenomenon. During the research stages where data from Permian fields were analyzed to develop this new design of gas separator, the engineering team found three main challenges in downhole gas separation. First, the wells were converted from Electrical Submersible Pump (ESP) to Rod Pumps earlier, forcing the downhole gas separators to handle more production. Second, the small production casing size usually is 5.5" casing, which significantly reduces the annulus area, which is vital to get an effective gas separation efficiency, and third the gas slugging behavior, which in high proportion can lead to a gas lock-in sucker rod pump system. A packer-type gas separator was designed, built, and tested in multiple wells following the requirements and limitations. This gas separator has an outlet section of 1.89" O.D., which means the design maximizes the gas separation area where it really matters at the fluid outlet point. The revolutionary fluid exit slots design creates a linear flow path allowing gas to separate and flow upward the casing annulus in a natural way. Additionally, a valve below the cup packer was included to eliminate surging. This valve prevents surging by holding the fluid in the vertical section, thus avoiding backflow when the gas slug leaves liquids behind. A calculator was developed to estimate the gas separation efficiency downhole and compare the gas separation efficiency among different gas separators to evaluate the new design. After the implementation of this design in 5 wells, the results confirmed the high gas separation efficiency obtained with this new gas separator configuration. The novelty of this gas separator design is the outlet section that takes advantage of the gravity force to increase the gas separation efficiency without limiting the tensile strength of the Bottom Hole Assembly (BHA).
{"title":"A Revolutionary Packer Type Gas Separator that Involves Gravity Force to Exceed Traditional Gas Separation Efficiency in Oil and Gas Wells","authors":"G. González, L. Guanacas, C. Portilla, Neil Johnson Vazhappilly","doi":"10.2118/209749-ms","DOIUrl":"https://doi.org/10.2118/209749-ms","url":null,"abstract":"\u0000 A revolutionary packer-type gas separator was designed to improve downhole gas separation efficiency. A deep analysis of gas separation methods was done to understand the process's nature and design a tool that could generate enhanced conditions for the gas separation phenomenon. During the research stages where data from Permian fields were analyzed to develop this new design of gas separator, the engineering team found three main challenges in downhole gas separation. First, the wells were converted from Electrical Submersible Pump (ESP) to Rod Pumps earlier, forcing the downhole gas separators to handle more production. Second, the small production casing size usually is 5.5\" casing, which significantly reduces the annulus area, which is vital to get an effective gas separation efficiency, and third the gas slugging behavior, which in high proportion can lead to a gas lock-in sucker rod pump system. A packer-type gas separator was designed, built, and tested in multiple wells following the requirements and limitations. This gas separator has an outlet section of 1.89\" O.D., which means the design maximizes the gas separation area where it really matters at the fluid outlet point. The revolutionary fluid exit slots design creates a linear flow path allowing gas to separate and flow upward the casing annulus in a natural way. Additionally, a valve below the cup packer was included to eliminate surging. This valve prevents surging by holding the fluid in the vertical section, thus avoiding backflow when the gas slug leaves liquids behind. A calculator was developed to estimate the gas separation efficiency downhole and compare the gas separation efficiency among different gas separators to evaluate the new design. After the implementation of this design in 5 wells, the results confirmed the high gas separation efficiency obtained with this new gas separator configuration. The novelty of this gas separator design is the outlet section that takes advantage of the gravity force to increase the gas separation efficiency without limiting the tensile strength of the Bottom Hole Assembly (BHA).","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128960542","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The sucker rod joint is designed to be made up to a given preload stress level in order to prevent separation between the pin shoulder and the coupling face during operation. As long as the connection is correctly made up, non-failures are expected to occur working within the fatigue limit of the design. Nevertheless, sucker rods joint failures occur constantly in oil fields around the world. It has been observed these failures both in loose joints and in properly made up connections. When the connection is loose, additional loads appear on the threads, not only adding more tensile stresses but also some flexion components that increase the risk of fatigue both in the pin and the coupling (in both cases in the last engaged thread, the most stressed). These failures can occur with equal probability in either the pin or the coupling. Once initiated, the failure growths by fatigue mechanism. But in several cases, coupling failures with the same apparent pattern as in a loose connection have been observed in properly made up ones at the failure moment. A common element detected in all these failures was the operation in corrosive environments. The goal of this work is to assess the performance of different threads and materials having the same manufacturing method (cold rolled threads) under stress corrosion conditions. Comparative tests were performed in different sucker rod coupling grades. Modified NACE TM0177 Method A Tensile Tests (Proof Ring) as well as full scale fatigue tests under corrosive environments were performed. The results show that the performance of a Sour Service steel (widely use in OCTG), cold rolled, is better than an 8630M rolled material and even better than the same steel with cut threaded element.
{"title":"Sucker Rod Couplings: Fatigue Failures and Stress Cracking Under Corrosive Environment","authors":"Martine Bühler, E. Lopez, E. Oliva","doi":"10.2118/209752-ms","DOIUrl":"https://doi.org/10.2118/209752-ms","url":null,"abstract":"\u0000 The sucker rod joint is designed to be made up to a given preload stress level in order to prevent separation between the pin shoulder and the coupling face during operation. As long as the connection is correctly made up, non-failures are expected to occur working within the fatigue limit of the design. Nevertheless, sucker rods joint failures occur constantly in oil fields around the world. It has been observed these failures both in loose joints and in properly made up connections. When the connection is loose, additional loads appear on the threads, not only adding more tensile stresses but also some flexion components that increase the risk of fatigue both in the pin and the coupling (in both cases in the last engaged thread, the most stressed). These failures can occur with equal probability in either the pin or the coupling. Once initiated, the failure growths by fatigue mechanism. But in several cases, coupling failures with the same apparent pattern as in a loose connection have been observed in properly made up ones at the failure moment. A common element detected in all these failures was the operation in corrosive environments.\u0000 The goal of this work is to assess the performance of different threads and materials having the same manufacturing method (cold rolled threads) under stress corrosion conditions. Comparative tests were performed in different sucker rod coupling grades. Modified NACE TM0177 Method A Tensile Tests (Proof Ring) as well as full scale fatigue tests under corrosive environments were performed.\u0000 The results show that the performance of a Sour Service steel (widely use in OCTG), cold rolled, is better than an 8630M rolled material and even better than the same steel with cut threaded element.","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"134 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123587459","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Longer laterals, better perforations and larger frac jobs have all enabled increased production capabilities. However, production optimization practices, which were developed decades ago, are still in use today, and severely limit the ability to aggressively draw wells down. The data provided in the most common fluid level processes does not meet the challenges generated by fluctuating well dynamics and conditions. The irregularity and inconsistency of current fluid level measurement systems and downhole cards provide an incomplete snapshot of the well conditions when a more complete solution is needed for optimization. Moreover, pump-off controller technology cannot discern gas interference from pumped-off scenarios resulting in unplanned shutdown and lost production. A growing number of wells being produced on sucker rod pump are offering high PIP and high fluid levels above pump, yet production is being limited due to gas interference caused by reservoir dynamics. Pumping through these ever-changing scenarios more aggressively is often the solution, yet this change in optimization practices cannot take place without ensuring the system is not overloaded and rod buckling is not taking place. To have this conversation, casing gas rates, accurate PIP and fluid levels must be acquired and automatically analyzed at a much higher frequency. With a permanent, automated fluid level system, reservoir and fluid data is continuously attained. Paired with properly tuned algorithms and current optimization practices, these data points give a clearer and more complete story of what rod pumped wells experience continuously throughout the day. Additionally, more information about the reservoir is produced than previously available. This paper offers insight on current shortcomings in optimization logic for highly dynamic unconventional wells and introduces a proposed methodology to improve runtimes in high gas interference and high fluid level scenarios while extending the life of the installation and equipment. Results showing the methodology's effectiveness at improving production and enhancing drawdown over time are presented.
{"title":"Importance of Real-Time Acquisition of Casing Gas Rate, PIP, and Fluid Level Data on Maximizing Drawdown in Highly Dynamic Horizontally Produced Wells","authors":"Victoria Pons, Robert Hovakimyan","doi":"10.2118/209759-ms","DOIUrl":"https://doi.org/10.2118/209759-ms","url":null,"abstract":"\u0000 Longer laterals, better perforations and larger frac jobs have all enabled increased production capabilities. However, production optimization practices, which were developed decades ago, are still in use today, and severely limit the ability to aggressively draw wells down. The data provided in the most common fluid level processes does not meet the challenges generated by fluctuating well dynamics and conditions. The irregularity and inconsistency of current fluid level measurement systems and downhole cards provide an incomplete snapshot of the well conditions when a more complete solution is needed for optimization. Moreover, pump-off controller technology cannot discern gas interference from pumped-off scenarios resulting in unplanned shutdown and lost production.\u0000 A growing number of wells being produced on sucker rod pump are offering high PIP and high fluid levels above pump, yet production is being limited due to gas interference caused by reservoir dynamics. Pumping through these ever-changing scenarios more aggressively is often the solution, yet this change in optimization practices cannot take place without ensuring the system is not overloaded and rod buckling is not taking place. To have this conversation, casing gas rates, accurate PIP and fluid levels must be acquired and automatically analyzed at a much higher frequency. With a permanent, automated fluid level system, reservoir and fluid data is continuously attained.\u0000 Paired with properly tuned algorithms and current optimization practices, these data points give a clearer and more complete story of what rod pumped wells experience continuously throughout the day. Additionally, more information about the reservoir is produced than previously available.\u0000 This paper offers insight on current shortcomings in optimization logic for highly dynamic unconventional wells and introduces a proposed methodology to improve runtimes in high gas interference and high fluid level scenarios while extending the life of the installation and equipment. Results showing the methodology's effectiveness at improving production and enhancing drawdown over time are presented.","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"232 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132227230","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Accurate gas lift valve (GLV) performance is crucial for precise gas lift system design, but complex and time-consuming testing techniques are required to obtain valve performance correlations. Therefore, this paper presents a modeling approach that aims to reduce the testing effort and obtain the coefficients required for valve performance correlations. Specifically, the model replicates the flow capacity test (FCT) described in the API 11V2 (2001) and API 19G2 (2010) to determine the flow coefficient (Cv) and critical pressure ratio (Rcp) for gas lift valves (GLV). Technically, the FCT requires a modified GLV with an adjustable stem positioning system to obtain flow rate as a function of pressure drop and calculating Cv and Rcp for each stem travel. Among the drawbacks of the FCT are the valve modification itself and the large number of tests necessary. The proposed approach employs a 1D mechanistic model that considers equivalent diameters of the GLV orifice port and the check valve opening area to calculate the gas flow rate. The pressure drop across the restrictions is derived from Bernoulli's equation and used to calculate the flow rate, Cv and Rcp for several stem positions of the gas lift valve. Experimental data from a dynamic flow test (API 11V2) is used to calibrate the model. Simulation results of 12 different valves are compared to the Valve Performance Clearinghouse (VPC) database to validate the modeling approach. The VPC database was created based on GLV flow tests for valves from several manufacturers with different models and configurations. Results of flow capacity using the 1D mechanistic modeling show a consistent agreement with the VPC database. Overall, the error was always below 15% for both Cv and Rcp, which is a positive result considering that the current most accurate method shows errors of up to 25%. Even though the 1D modeling may be oversimplified given the consideration of 3D area changes as equivalent circular diameters, the method predicts Cv and Rcp with considerable accuracy. Moreover, the calibration using only one dynamic flow test result significantly reduces the time required to perform an FCT and eliminates the need to modify a GLV.
{"title":"A New Method to Significantly Simplify the API Flow Tests for Gas-Lift Valves","authors":"Felipe Simões Maciel, P. Waltrich","doi":"10.2118/209754-ms","DOIUrl":"https://doi.org/10.2118/209754-ms","url":null,"abstract":"\u0000 Accurate gas lift valve (GLV) performance is crucial for precise gas lift system design, but complex and time-consuming testing techniques are required to obtain valve performance correlations. Therefore, this paper presents a modeling approach that aims to reduce the testing effort and obtain the coefficients required for valve performance correlations. Specifically, the model replicates the flow capacity test (FCT) described in the API 11V2 (2001) and API 19G2 (2010) to determine the flow coefficient (Cv) and critical pressure ratio (Rcp) for gas lift valves (GLV). Technically, the FCT requires a modified GLV with an adjustable stem positioning system to obtain flow rate as a function of pressure drop and calculating Cv and Rcp for each stem travel. Among the drawbacks of the FCT are the valve modification itself and the large number of tests necessary. The proposed approach employs a 1D mechanistic model that considers equivalent diameters of the GLV orifice port and the check valve opening area to calculate the gas flow rate. The pressure drop across the restrictions is derived from Bernoulli's equation and used to calculate the flow rate, Cv and Rcp for several stem positions of the gas lift valve. Experimental data from a dynamic flow test (API 11V2) is used to calibrate the model. Simulation results of 12 different valves are compared to the Valve Performance Clearinghouse (VPC) database to validate the modeling approach. The VPC database was created based on GLV flow tests for valves from several manufacturers with different models and configurations. Results of flow capacity using the 1D mechanistic modeling show a consistent agreement with the VPC database. Overall, the error was always below 15% for both Cv and Rcp, which is a positive result considering that the current most accurate method shows errors of up to 25%. Even though the 1D modeling may be oversimplified given the consideration of 3D area changes as equivalent circular diameters, the method predicts Cv and Rcp with considerable accuracy. Moreover, the calibration using only one dynamic flow test result significantly reduces the time required to perform an FCT and eliminates the need to modify a GLV.","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127124780","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Many resource play (shale) reservoirs have been drilled with highly tortuous wells. These wells are difficult to produce in their late life when production rates and pressures decline to the point where positive displacement pumping becomes necessary. Reciprocating rod pump (RRP) systems are expensive to install and operate in these conditions. RRPs’ inherent issues with friction and wear and tear on equipment are exacerbated in these kinds of crooked wells. Gas Pump (GP) is a newly invented artificial lift system that provides the benefits of positive displacement pumping for these kinds of wells without the inherent installation costs and failure risks associated with RRP. GP uses high pressure natural gas to blow liquids out of a bottom hole accumulator chamber into the tubing (like RRP) all while isolating the reservoir from the backpressure of the column of liquid standing in the tubing, thereby enabling maximum reservoir pressure drawdown. This paper will describe the theory behind GP's technical design and mechanical application, relay the practical equipment design and testing processes used to progress the system from concept to prototype, and conclude with GP's prototype performance assessment.
{"title":"Gas Pump – A Gas-Driven Positive Displacement Pump Artificial Lift System","authors":"Stephen W. Turk, Michael Juenke","doi":"10.2118/209748-ms","DOIUrl":"https://doi.org/10.2118/209748-ms","url":null,"abstract":"\u0000 Many resource play (shale) reservoirs have been drilled with highly tortuous wells. These wells are difficult to produce in their late life when production rates and pressures decline to the point where positive displacement pumping becomes necessary. Reciprocating rod pump (RRP) systems are expensive to install and operate in these conditions. RRPs’ inherent issues with friction and wear and tear on equipment are exacerbated in these kinds of crooked wells.\u0000 Gas Pump (GP) is a newly invented artificial lift system that provides the benefits of positive displacement pumping for these kinds of wells without the inherent installation costs and failure risks associated with RRP. GP uses high pressure natural gas to blow liquids out of a bottom hole accumulator chamber into the tubing (like RRP) all while isolating the reservoir from the backpressure of the column of liquid standing in the tubing, thereby enabling maximum reservoir pressure drawdown.\u0000 This paper will describe the theory behind GP's technical design and mechanical application, relay the practical equipment design and testing processes used to progress the system from concept to prototype, and conclude with GP's prototype performance assessment.","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"72 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126258569","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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