Bellows are mechanical devices used to compensate linear, thermal, or angular movement/expansion. Said bellows can be manufactured in different shapes, sizes, using different materials. One typical example of bellows application is in pipelines to compensate for thermal expansion between solid points. In oil and gas industry, among other applications, bellows are used in gas lift valves as a slidable seal between Nitrogen charged in valve dome section and injection pressure. Currently, only two nominal bellow sizes are used in gas lift application, one Inch and one and a half Inch. Examples of gas lift valves using one-and three-quarter Inch were manufactured but are not widely used. However, as manufactured bellows having very thin walls are not well suited for pressures higher than 200 PSI, depending on bellow size, shape and material used. To withstand much higher pressures bellows are being crimped, method that compresses bellow to shorter length which increases bellow overall mechanical toughness. In addition, bellows in gas lift valves must be pressure balanced inside and outside as much as possible to withstand high pressure up to 2500 PSI. By design bellows used in typical gas lift valves feature internal seal that is engaged once valve is in fully open position and bellow is expanded trapping "noncompressible" fluid usually silicone oil of different density. Nitrogen in gas lift valve is in direct contact with silicone oil and penetrates/dissolves into oil in form of bubbles. Being so called permanent gas Nitrogen never liquifies and always remain in gaseous state at any pressure no matter how high. This renders so called "noncompressible" fluid compressible and it does not prevent bellow damage when exposed to extremely high injection pressures. This theory used for decades in oil and gas industry is wrong resulting in premature bellow failures. This paper analyses existing gas lift designs and offers solution for problems specified herein.
{"title":"Gas Lift Valve Bellow Protection from High Injection and Dome Pressure","authors":"Zlatko Salihbegovic","doi":"10.2118/209732-ms","DOIUrl":"https://doi.org/10.2118/209732-ms","url":null,"abstract":"\u0000 Bellows are mechanical devices used to compensate linear, thermal, or angular movement/expansion. Said bellows can be manufactured in different shapes, sizes, using different materials. One typical example of bellows application is in pipelines to compensate for thermal expansion between solid points. In oil and gas industry, among other applications, bellows are used in gas lift valves as a slidable seal between Nitrogen charged in valve dome section and injection pressure. Currently, only two nominal bellow sizes are used in gas lift application, one Inch and one and a half Inch. Examples of gas lift valves using one-and three-quarter Inch were manufactured but are not widely used. However, as manufactured bellows having very thin walls are not well suited for pressures higher than 200 PSI, depending on bellow size, shape and material used. To withstand much higher pressures bellows are being crimped, method that compresses bellow to shorter length which increases bellow overall mechanical toughness. In addition, bellows in gas lift valves must be pressure balanced inside and outside as much as possible to withstand high pressure up to 2500 PSI. By design bellows used in typical gas lift valves feature internal seal that is engaged once valve is in fully open position and bellow is expanded trapping \"noncompressible\" fluid usually silicone oil of different density. Nitrogen in gas lift valve is in direct contact with silicone oil and penetrates/dissolves into oil in form of bubbles. Being so called permanent gas Nitrogen never liquifies and always remain in gaseous state at any pressure no matter how high. This renders so called \"noncompressible\" fluid compressible and it does not prevent bellow damage when exposed to extremely high injection pressures. This theory used for decades in oil and gas industry is wrong resulting in premature bellow failures. This paper analyses existing gas lift designs and offers solution for problems specified herein.","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"14 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":"117270735","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}
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 re
{"title":"Accurate Gas-To-Pump Calculation in Pumping Oil Wells from Surface Data Using Combined Analytical Modeling of Gaseous Static Liquids Gradient: Part 1","authors":"A. Nagoo, L. Harms, W. Hearn","doi":"10.2118/209729-ms","DOIUrl":"https://doi.org/10.2118/209729-ms","url":null,"abstract":"\u0000 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.\u0000 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.\u0000 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.\u0000 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 re","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"132 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":"115081497","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}
As the second part of this series, we apply our much improved understanding of gas flow through static recirculating liquid columns and analytical countercurrent multiphase flow modeling to both conventional and unconventional horizontal gas well liquids loading and a deep dive of the process of wellbore liquids flow reversal post-loading. This part of our work focuses on a step change in understanding the aspect of multiphase flow that is most pertinent to artificial lift - countercurrent liquids loading and gas flow through liquid columns. It is shown that traditional concurrent flow principles and flow pattern maps used in prior commonly used flowing bottom hole pressure correlations do not apply and cannot explain the changing dual pressure gradient profiles in loaded gas wells as a result of flow reversal. Therefore, this work lays the foundation for a change in conversation and focus among the artificial lift community towards countercurrent and static liquid column multiphase flow behaviors prevalent in all liquids-producing gas wells. We show and field-validate a new computational ability to perform multiphase countercurrent liquids loading calculations that dynamically loads a gas well tubing/casing and the calculations of total pressure gradient that varies with the increasing gas holdup along the static liquid columns of these wells. Additionally, we analyze the process of countercurrent flow and put forward a redefinition of onset of liquids flow reversal in the proper context of prior studies in this field. Our results are used to simulate the liquid levels in loaded gas wells from only basic surface field data. This represents an advance towards low-cost, low-carbon gas well production optimization and the opportunity of simulation-based real-time downhole diagnostics to determine digital liquid levels and reliably accurate FBHP in loaded gas wells without the high-carbon costs of wellsite visits and equipment runs. In terms of reliable digital twin applications for gas wells producing liquids, our new method can be performed in an autonomous way on a wellhead - a sort of "gas well liquid level digital sensor" - a solution that takes advantage of available SCADA surface data and converts it to automated calculations of downhole pressures, flow rates and well liquid levels in response to dynamic well operating conditions. For the first time in the industry, we present in this work a simultaneous calculation of loaded gas well FBHP and gaseous liquids level from only surface data. In either cases of liquids loaded gas wells or pumping oil wells with gaseous liquid columns above them, the significant pressure gradient (delta-P) that gaseous liquid columns impose on the formation is of great importance in correctly understanding and analyzing well supply capacity and enhancing downhole production rates during production operations.
{"title":"Liquids Level Calculation in Loaded Gas Wells from Surface Data Using Combined Analytical Modeling of Gaseous Static Liquids Gradient: Part 2","authors":"A. Nagoo, L. Harms, W. Hearn","doi":"10.2118/209727-ms","DOIUrl":"https://doi.org/10.2118/209727-ms","url":null,"abstract":"\u0000 As the second part of this series, we apply our much improved understanding of gas flow through static recirculating liquid columns and analytical countercurrent multiphase flow modeling to both conventional and unconventional horizontal gas well liquids loading and a deep dive of the process of wellbore liquids flow reversal post-loading.\u0000 This part of our work focuses on a step change in understanding the aspect of multiphase flow that is most pertinent to artificial lift - countercurrent liquids loading and gas flow through liquid columns. It is shown that traditional concurrent flow principles and flow pattern maps used in prior commonly used flowing bottom hole pressure correlations do not apply and cannot explain the changing dual pressure gradient profiles in loaded gas wells as a result of flow reversal. Therefore, this work lays the foundation for a change in conversation and focus among the artificial lift community towards countercurrent and static liquid column multiphase flow behaviors prevalent in all liquids-producing gas wells.\u0000 We show and field-validate a new computational ability to perform multiphase countercurrent liquids loading calculations that dynamically loads a gas well tubing/casing and the calculations of total pressure gradient that varies with the increasing gas holdup along the static liquid columns of these wells. Additionally, we analyze the process of countercurrent flow and put forward a redefinition of onset of liquids flow reversal in the proper context of prior studies in this field. Our results are used to simulate the liquid levels in loaded gas wells from only basic surface field data. This represents an advance towards low-cost, low-carbon gas well production optimization and the opportunity of simulation-based real-time downhole diagnostics to determine digital liquid levels and reliably accurate FBHP in loaded gas wells without the high-carbon costs of wellsite visits and equipment runs. In terms of reliable digital twin applications for gas wells producing liquids, our new method can be performed in an autonomous way on a wellhead - a sort of \"gas well liquid level digital sensor\" - a solution that takes advantage of available SCADA surface data and converts it to automated calculations of downhole pressures, flow rates and well liquid levels in response to dynamic well operating conditions.\u0000 For the first time in the industry, we present in this work a simultaneous calculation of loaded gas well FBHP and gaseous liquids level from only surface data. In either cases of liquids loaded gas wells or pumping oil wells with gaseous liquid columns above them, the significant pressure gradient (delta-P) that gaseous liquid columns impose on the formation is of great importance in correctly understanding and analyzing well supply capacity and enhancing downhole production rates during production operations.","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":"129322637","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}
Fiberglass rods are mainly used to overcome the design limitations of rod pump equipment when additional lift capacity is required. Economic analyses for new installations or repair jobs must consider the life span of fiberglass rods. This study evaluates the cost-effectiveness of fiberglass rod applications by reviewing their life spans in the Permian Basin. The objective of this project was to build a stress fatigue diagram to help minimize expenses by maximizing the effective life of fiberglass rods. In theory, this diagram would define the allowable stress range that could be applied to fiberglass rods without causing excessive failures. Each data point would consist of one fiberglass rod failure, and all calculations would be performed over the age of the taper, from initial installation to failure. These operating limits would then be applied to field applications. The industry's rule of thumb for the "end of life" for fiberglass rods is 30-40 million rod reversals. However, most failures occurred before the rods reached one-third of their life expectancy, even though the fiberglass rods were operated well within the recommended stress ranges provided by the manufacturers. There was a positive relationship between average fiberglass taper failure frequency and average peak polished rod stress. Failures mainly occurred in the steel connection in the pin. Therefore, failures were not due to tensile stress fatigue in the fiberglass body. Failure frequency was so high in some fields that upsizing the pumping unit made more economic sense than installing a fiberglass taper. The recommendations from this project were to: (1) understand connection failures better through improved root cause failure analysis (RCFA) data collection and manufacturer involvement; (2) reassess and improve operational conditions at failure, such as rod pump design, pump off setpoints, and pump fillage; (3) evaluate switching to a 100% metal string with an upsized pumping unit or installing a different artificial lift method if failure frequency is not reduced by operational changes; and (4) re-evaluate rod string design criteria to maximize value, as current designs are based on tensile loading in the body of the top rod, but actual failures were not due to tensile stress fatigue in the body. Significant cost savings can be achieved if the average life span can be increased to the industry standard of 30-40 million rod reversals. More work needs to be done to understand connection failures.
{"title":"Fiberglass Sucker Rod Cost-Effectiveness: A Case Study from the Permian Basin","authors":"Melanie Brewer, C. Su, Steve Gault","doi":"10.2118/209731-ms","DOIUrl":"https://doi.org/10.2118/209731-ms","url":null,"abstract":"\u0000 Fiberglass rods are mainly used to overcome the design limitations of rod pump equipment when additional lift capacity is required. Economic analyses for new installations or repair jobs must consider the life span of fiberglass rods. This study evaluates the cost-effectiveness of fiberglass rod applications by reviewing their life spans in the Permian Basin.\u0000 The objective of this project was to build a stress fatigue diagram to help minimize expenses by maximizing the effective life of fiberglass rods. In theory, this diagram would define the allowable stress range that could be applied to fiberglass rods without causing excessive failures. Each data point would consist of one fiberglass rod failure, and all calculations would be performed over the age of the taper, from initial installation to failure. These operating limits would then be applied to field applications.\u0000 The industry's rule of thumb for the \"end of life\" for fiberglass rods is 30-40 million rod reversals. However, most failures occurred before the rods reached one-third of their life expectancy, even though the fiberglass rods were operated well within the recommended stress ranges provided by the manufacturers. There was a positive relationship between average fiberglass taper failure frequency and average peak polished rod stress. Failures mainly occurred in the steel connection in the pin. Therefore, failures were not due to tensile stress fatigue in the fiberglass body. Failure frequency was so high in some fields that upsizing the pumping unit made more economic sense than installing a fiberglass taper.\u0000 The recommendations from this project were to: (1) understand connection failures better through improved root cause failure analysis (RCFA) data collection and manufacturer involvement; (2) reassess and improve operational conditions at failure, such as rod pump design, pump off setpoints, and pump fillage; (3) evaluate switching to a 100% metal string with an upsized pumping unit or installing a different artificial lift method if failure frequency is not reduced by operational changes; and (4) re-evaluate rod string design criteria to maximize value, as current designs are based on tensile loading in the body of the top rod, but actual failures were not due to tensile stress fatigue in the body.\u0000 Significant cost savings can be achieved if the average life span can be increased to the industry standard of 30-40 million rod reversals. More work needs to be done to understand connection failures.","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"7 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":"132381945","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}
Thuy Chu, T. Nguyen, H. Yoo, Jihoon Wang, D. Vuong
Electrical Submersible Pump (ESP) is one of the most adaptable artificial lift methods that is capable of lifting high fluid volumes from wellbore to surface. Despite that, ESPs are not suitable for wells with high gas liquid ratio. Presence of free gas inside an ESP causes pump performance degradation which may lead to higher motor temperature and/or pump failures during operations. Thus, it is necessary to investigate effects of free gas on pump failures due to the degradation of pump performance under two-phase flow and high motor temperature. This study is one of the first attempts to simulate motor temperature using developed correlations which predict two-phase pump performance under downhole conditions. Field data from two ESP-oil wells were used to confirm the reliability of the developed simulations predicting two-phase ESP performance and motor temperature under downhole conditions. The simulation results show that liquid rate drops significantly due to the degradation of pump performance under two-phase flow, reduces by around 50% when free gas fraction increases from 0 to 0.4. In addition, ESP applications might be feasible in different gassy conditions with up to 0.35 free gas fraction. However, when the pump is run at 3500 RPM, the maximum free gas fraction that an ESP can tolerate is about 0.25 before the pump is overheated and failed. The findings from this study will help operating companies as well as ESP manufacturers to operate ESPs within the recommended range under downhole conditions.
{"title":"Predicting ESP Motor's Overheating Due to High Free Gas Fraction","authors":"Thuy Chu, T. Nguyen, H. Yoo, Jihoon Wang, D. Vuong","doi":"10.2118/209738-ms","DOIUrl":"https://doi.org/10.2118/209738-ms","url":null,"abstract":"\u0000 Electrical Submersible Pump (ESP) is one of the most adaptable artificial lift methods that is capable of lifting high fluid volumes from wellbore to surface. Despite that, ESPs are not suitable for wells with high gas liquid ratio. Presence of free gas inside an ESP causes pump performance degradation which may lead to higher motor temperature and/or pump failures during operations. Thus, it is necessary to investigate effects of free gas on pump failures due to the degradation of pump performance under two-phase flow and high motor temperature. This study is one of the first attempts to simulate motor temperature using developed correlations which predict two-phase pump performance under downhole conditions. Field data from two ESP-oil wells were used to confirm the reliability of the developed simulations predicting two-phase ESP performance and motor temperature under downhole conditions. The simulation results show that liquid rate drops significantly due to the degradation of pump performance under two-phase flow, reduces by around 50% when free gas fraction increases from 0 to 0.4. In addition, ESP applications might be feasible in different gassy conditions with up to 0.35 free gas fraction. However, when the pump is run at 3500 RPM, the maximum free gas fraction that an ESP can tolerate is about 0.25 before the pump is overheated and failed. The findings from this study will help operating companies as well as ESP manufacturers to operate ESPs within the recommended range under downhole conditions.","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"143 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":"131797097","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}
Jordan Anderson, Esteban Oliva, Courtney Richardson, S. Mogus, Dylan Morin
The objective of this study is to detail the improper make up related sucker rod connection failure reduction efforts of two operators in reciprocating rod pump applications. The study will give an overview of a "healthy" sucker rod connection along with their common failure mechanisms and root causes. Failure data will be shown and ultimately a three-pronged approach will be recommended for connection reliability improvement. Failure data will be analyzed using a total sucker rod connection failure metric with one operator in the Permian and another operator in the Bakken. Different forms of the three-pronged approach were carried out over time by both operators, so an analysis of the efficacy of the changes will be made to help understand the necessary operational changes required. A combination of quality assurance/quality control programs, technologies and services were used in efforts to reduce sucker rod connection failures. These efforts will be explained in detail to provide the necessary information to outline the success of the authors. The results revealed that there were three main factors that reduced the failures of the operators: 1) Rigorous QA/QC programs to rig operations, vendor facilities and transportation services of sucker rods, 2) implementing sucker rods specifically designed and manufactured to be ran without traditional thread lubricant, and 3) in-shop services of rod/coupling prep and hand-tight or torqued (buck-on) application. These three factors became the three-pronged approach. The data suggests that their simultaneous implementation is the best strategy to deliver the expected reliability improvement.
{"title":"Sucker Rod Connection Failure Reduction Using a Three-Pronged Approach","authors":"Jordan Anderson, Esteban Oliva, Courtney Richardson, S. Mogus, Dylan Morin","doi":"10.2118/209750-ms","DOIUrl":"https://doi.org/10.2118/209750-ms","url":null,"abstract":"\u0000 The objective of this study is to detail the improper make up related sucker rod connection failure reduction efforts of two operators in reciprocating rod pump applications. The study will give an overview of a \"healthy\" sucker rod connection along with their common failure mechanisms and root causes. Failure data will be shown and ultimately a three-pronged approach will be recommended for connection reliability improvement.\u0000 Failure data will be analyzed using a total sucker rod connection failure metric with one operator in the Permian and another operator in the Bakken. Different forms of the three-pronged approach were carried out over time by both operators, so an analysis of the efficacy of the changes will be made to help understand the necessary operational changes required. A combination of quality assurance/quality control programs, technologies and services were used in efforts to reduce sucker rod connection failures. These efforts will be explained in detail to provide the necessary information to outline the success of the authors.\u0000 The results revealed that there were three main factors that reduced the failures of the operators: 1) Rigorous QA/QC programs to rig operations, vendor facilities and transportation services of sucker rods, 2) implementing sucker rods specifically designed and manufactured to be ran without traditional thread lubricant, and 3) in-shop services of rod/coupling prep and hand-tight or torqued (buck-on) application. These three factors became the three-pronged approach. The data suggests that their simultaneous implementation is the best strategy to deliver the expected reliability improvement.","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":"130833113","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}
Paola Elizabeth Martinez Villarreal, Ana Katherine Escobar Patron, Eder Jean Rosales Ballesteros, Stephen Schreck
Electric submersible pumps (ESPs) have historically been limited when operating in gassy conditions. Studies and evidence gathered during failure analysis confirm the effects of gas on the performance of ESPs. Gas locking, mechanical wear, and low efficiency due to challenging environments have made operators change from a standardized string to a string that can mitigate the effects of gas, which can help maximize the production and increase the pump's run life. The impellers of the centrifugal pump require a minimum amount of liquid mass in the impeller vanes to transfer the kinetic energy to the fluid mixture. This energy will be transformed to potential energy in the diffuser, but if the mass mixture in the impeller cannot perform an efficient energy transfer for the mixture, only the liquid phase will be pushed out the vanes of the pump and most of the gas will stay behind, filling the vanes of the impeller and creating a gas-lock condition. In environments with a high presence of gas, additional equipment such as rotary gas separators are used to remove as much gas as possible before the fluids enter the pump. Gas separators have been proved as effective. However, when the conditions are extreme, such as in unconventional reservoirs, additional devices will be required to maintain a stable operation of the ESP, pump as much as possible a homogenous fluid, and minimize the downtime due to unnecessary trips to maximize the overall performance and run life of the ESP system, and optimize production and total cost of ownership for artificial lift operations. This paper presents the comparative results of the performance of a group of ESPs installed in unconventional wells of a leading Midland basin operator with challenging conditions to operate an ESP. It will analyze the performance of the ESPs and compare the trends of the downhole parameters while operating with a standard string with a single gas separator and gas-handling system with those of an upgraded string that includes a tandem gas separator, an advanced gas-handling system, and a multiphase gas-handling system equipped with helico-axial-flow stages. This change in designs and configuration has improved the run life of the ESPs for unconventional wells with high gas volume fractions.
{"title":"Comparative Results for ESP Applications in Gassy Wells when Using Single Gas Handling Systems vs. Multiple Gas Handling Systems for Pioneer Natural Resources","authors":"Paola Elizabeth Martinez Villarreal, Ana Katherine Escobar Patron, Eder Jean Rosales Ballesteros, Stephen Schreck","doi":"10.2118/209739-ms","DOIUrl":"https://doi.org/10.2118/209739-ms","url":null,"abstract":"\u0000 Electric submersible pumps (ESPs) have historically been limited when operating in gassy conditions. Studies and evidence gathered during failure analysis confirm the effects of gas on the performance of ESPs. Gas locking, mechanical wear, and low efficiency due to challenging environments have made operators change from a standardized string to a string that can mitigate the effects of gas, which can help maximize the production and increase the pump's run life.\u0000 The impellers of the centrifugal pump require a minimum amount of liquid mass in the impeller vanes to transfer the kinetic energy to the fluid mixture. This energy will be transformed to potential energy in the diffuser, but if the mass mixture in the impeller cannot perform an efficient energy transfer for the mixture, only the liquid phase will be pushed out the vanes of the pump and most of the gas will stay behind, filling the vanes of the impeller and creating a gas-lock condition.\u0000 In environments with a high presence of gas, additional equipment such as rotary gas separators are used to remove as much gas as possible before the fluids enter the pump. Gas separators have been proved as effective. However, when the conditions are extreme, such as in unconventional reservoirs, additional devices will be required to maintain a stable operation of the ESP, pump as much as possible a homogenous fluid, and minimize the downtime due to unnecessary trips to maximize the overall performance and run life of the ESP system, and optimize production and total cost of ownership for artificial lift operations.\u0000 This paper presents the comparative results of the performance of a group of ESPs installed in unconventional wells of a leading Midland basin operator with challenging conditions to operate an ESP. It will analyze the performance of the ESPs and compare the trends of the downhole parameters while operating with a standard string with a single gas separator and gas-handling system with those of an upgraded string that includes a tandem gas separator, an advanced gas-handling system, and a multiphase gas-handling system equipped with helico-axial-flow stages. This change in designs and configuration has improved the run life of the ESPs for unconventional wells with high gas volume fractions.","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"26 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":"132310178","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}
A. Delgado, J. Espinosa, M. Hernandez, G. González, L. Guanacas, William Aya, J. Perdomo
One of the most expensive artificial lift systems in the oil industry is the Electric Submersible Pump (ESP) system, hence the unavoidable need of extending the run life of wells that have installed this system. Following the need of extending the run life, a sand regulator has been designed to protect the pump during shutdowns, and it has been incorporated into traditional sand control configurations to offer extensive protection above and below the pump. This paper will explain the mechanism of the sand regulator as well as the benefit of installing this system alone above the pump or complemented with a sand control system below the pump. The candidate wells to this integrated solution were selected from MMV (Middle Magdalena Valley) and Putumayo Basins, in Colombia. The wells had sand problems history and it was necessary to review pump designs, pulling reports and sensor parameters. Well conditions such as production, tubing size, and particle size distribution were analyzed to build the best design for every single well. In the design the geometry of the well was assessed to accommodate the cable and CT (Capillary tube) line downhole. The ADN Field in Colombia is characterized by heavy oil production (API between 13-18°), with fluid production between 1,000-2,000 BFPD, with a viscosity of 270 - 3090 cP @ 122°F, water cuts oscillating depending on the waterflooding effect (Between 1% to 95%) and high fine sand production (200 – 24,000 ppm). The CH Field wells produce between 1,000 – 6,000 BFPD, with API between 17-20°, high water cuts (> 77%) and a high sand production between 100 – 3,000 ppm. The wells selected had other type of sand control and management systems and were highly affected by frequent shutdowns. The Sand Regulator design was installed in 20 wells and was compared with the performance achieved using traditional sand control solutions. After the installation, production has remained stable in all the wells applied, allowing to reduce the PIP of the well of up to 400 psi. Less current consumption has been observed after each shutdown in all the wells, extending the run life of some wells up to double the average. Sensor parameters were analyzed after each pump restart to determine how difficult it was to restart operation after shutdowns. Compared to the tools installed above the ESP, this sand regulator allows flushing operation through it with flow ranges from 0.5 to 5 bpm. In addition, the unconventional design of this tool has opened the door to a new concept of ESP protection that works in wells with light or heavy oil and can be refurbished or inspected completely without cutting the tool.
{"title":"New Mechanism of Sand Management Above ESPs: Cases Study in Colombia","authors":"A. Delgado, J. Espinosa, M. Hernandez, G. González, L. Guanacas, William Aya, J. Perdomo","doi":"10.2118/209734-ms","DOIUrl":"https://doi.org/10.2118/209734-ms","url":null,"abstract":"\u0000 One of the most expensive artificial lift systems in the oil industry is the Electric Submersible Pump (ESP) system, hence the unavoidable need of extending the run life of wells that have installed this system. Following the need of extending the run life, a sand regulator has been designed to protect the pump during shutdowns, and it has been incorporated into traditional sand control configurations to offer extensive protection above and below the pump.\u0000 This paper will explain the mechanism of the sand regulator as well as the benefit of installing this system alone above the pump or complemented with a sand control system below the pump. The candidate wells to this integrated solution were selected from MMV (Middle Magdalena Valley) and Putumayo Basins, in Colombia. The wells had sand problems history and it was necessary to review pump designs, pulling reports and sensor parameters. Well conditions such as production, tubing size, and particle size distribution were analyzed to build the best design for every single well. In the design the geometry of the well was assessed to accommodate the cable and CT (Capillary tube) line downhole.\u0000 The ADN Field in Colombia is characterized by heavy oil production (API between 13-18°), with fluid production between 1,000-2,000 BFPD, with a viscosity of 270 - 3090 cP @ 122°F, water cuts oscillating depending on the waterflooding effect (Between 1% to 95%) and high fine sand production (200 – 24,000 ppm). The CH Field wells produce between 1,000 – 6,000 BFPD, with API between 17-20°, high water cuts (> 77%) and a high sand production between 100 – 3,000 ppm. The wells selected had other type of sand control and management systems and were highly affected by frequent shutdowns. The Sand Regulator design was installed in 20 wells and was compared with the performance achieved using traditional sand control solutions. After the installation, production has remained stable in all the wells applied, allowing to reduce the PIP of the well of up to 400 psi. Less current consumption has been observed after each shutdown in all the wells, extending the run life of some wells up to double the average. Sensor parameters were analyzed after each pump restart to determine how difficult it was to restart operation after shutdowns.\u0000 Compared to the tools installed above the ESP, this sand regulator allows flushing operation through it with flow ranges from 0.5 to 5 bpm. In addition, the unconventional design of this tool has opened the door to a new concept of ESP protection that works in wells with light or heavy oil and can be refurbished or inspected completely without cutting the tool.","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"2015 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":"116914274","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}
Carlos Escobar, Victor Valencia, J. Castro, Carlos León, Laura Pérez, Juan Serrano, Iván Ariza
Over the years, Electro-Submersible Pumps have been considered one of the main Artificial Lift Methods in different fields of the world due to their versatility in handling different well fluids and wide ranges of flow production. However, in many cases, it is not possible to reach the maximum potential of a well due to the perception of avoiding operating the Asynchronous Motors of the ESP system above 3600 RPM because it may induce failures. During the operation of ESP systems, situations may occur during which it may be necessary to operate the motor above the standard frequency 50/60 Hz (3000/3600 RPM) and take advantage of the maximum potential of the well without requiring an immediate intervention. These situations include but are not limited to well productivity index differing from the expected, loss of mechanical transmission in some of the system components, or decrease in efficiency due to wear associated with equipment operation. In the ESP industry there is a design practice of operating frequencies no higher than 60 Hz (3600 RPM) to avoid possible equipment failures associated with rotational instability, high temperatures or poor lubrication in the internal components due to greater friction at higher speeds. The recommended practices or international standards do not have an operating speed limit reference apart from the restrictions that can normally occur in the system, so there is uncertainty in the operating limits of these systems. The main objective of this paper is to verify or disprove the theory of the high speed rotation in 500-series ESPs with Asynchronous Motors (standard technology) with a specific number of wells that were operated at speeds above 4000 RPM.
{"title":"Is It Possible to Run at High Speed Rotation, Above 3600 RPM, Asynchronous Electrical Submersible System? Myth, or Reality","authors":"Carlos Escobar, Victor Valencia, J. Castro, Carlos León, Laura Pérez, Juan Serrano, Iván Ariza","doi":"10.2118/209733-ms","DOIUrl":"https://doi.org/10.2118/209733-ms","url":null,"abstract":"\u0000 Over the years, Electro-Submersible Pumps have been considered one of the main Artificial Lift Methods in different fields of the world due to their versatility in handling different well fluids and wide ranges of flow production. However, in many cases, it is not possible to reach the maximum potential of a well due to the perception of avoiding operating the Asynchronous Motors of the ESP system above 3600 RPM because it may induce failures.\u0000 During the operation of ESP systems, situations may occur during which it may be necessary to operate the motor above the standard frequency 50/60 Hz (3000/3600 RPM) and take advantage of the maximum potential of the well without requiring an immediate intervention. These situations include but are not limited to well productivity index differing from the expected, loss of mechanical transmission in some of the system components, or decrease in efficiency due to wear associated with equipment operation.\u0000 In the ESP industry there is a design practice of operating frequencies no higher than 60 Hz (3600 RPM) to avoid possible equipment failures associated with rotational instability, high temperatures or poor lubrication in the internal components due to greater friction at higher speeds. The recommended practices or international standards do not have an operating speed limit reference apart from the restrictions that can normally occur in the system, so there is uncertainty in the operating limits of these systems.\u0000 The main objective of this paper is to verify or disprove the theory of the high speed rotation in 500-series ESPs with Asynchronous Motors (standard technology) with a specific number of wells that were operated at speeds above 4000 RPM.","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"62 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":"127581796","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}
Reza Asgharzadeh Shishavan, J. C. Serrano, Jose R Ludena, Qian Li, Bradley J Hager, Eduardo Saenz, G. Stephenson, A. Hendroyono, Slavoljub Stojanovic, Dipti Sankpal, Asher N Alexander
Significant value can be achieved by optimizing production of a gas-lift network. Operators have traditionally performed this work manually using network models, but maintaining these models is often labor-intensive. To address this challenge, a closed-loop optimization system was developed that leverages both advanced analytics and physics-based techniques, as well as Internet of Things (IoT) Edge technology. The objectives of such system are to control and optimize the gas-lift network automatically, reduce downtime during compressor upsets, and mitigate any potential flare events. The new closed-loop gas-lift optimization algorithm consists of well and surface network models, optimization and regression solvers, and disturbance adaptation, all running in real time. The closed-loop optimizer works as follows: (1) in every cycle, the optimizer receives measurements; (2) disturbance adaptation compares the model's estimates with the measurements and adapts the surface network model to make it more accurate; (3) the adapted surface network model and well models are used to find the optimum lift gas setpoints; and (4) the calculated setpoints are sent to the automation system through IoT Edge technology. Integral to this system is a single-well nodal analysis model that automatically generates updated models daily for all gas-lift wells. This model is used both as a monitoring tool by the engineers and as part of the network model in the closed-loop gas-lift optimizer, which has been deployed in multiple fields and is running continuously (24/7). The optimizer has saved both production engineering time per network and well specialist time per compressor upset event. Field case studies have shown that the closed-loop optimizer has been successful in maintaining compressor station outlet pressure and optimizing the gas-lift networks during compressor upsets or potential flare events. A significant improvement in oil production has been achieved in fields using optimizer due to both optimized lift gas distribution and reduced downtime. This new algorithm can optimize gas-lift networks during normal operating conditions, compressor upsets, or potential flare events, while simultaneously controlling compressor station outlet pressure within an acceptable range in real time. Significantly, disturbance adaptation is used for the first time to improve the surface model accuracy immediately as additional measurements are received.
{"title":"Closed Loop Gas-Lift Optimization","authors":"Reza Asgharzadeh Shishavan, J. C. Serrano, Jose R Ludena, Qian Li, Bradley J Hager, Eduardo Saenz, G. Stephenson, A. Hendroyono, Slavoljub Stojanovic, Dipti Sankpal, Asher N Alexander","doi":"10.2118/209756-ms","DOIUrl":"https://doi.org/10.2118/209756-ms","url":null,"abstract":"\u0000 Significant value can be achieved by optimizing production of a gas-lift network. Operators have traditionally performed this work manually using network models, but maintaining these models is often labor-intensive. To address this challenge, a closed-loop optimization system was developed that leverages both advanced analytics and physics-based techniques, as well as Internet of Things (IoT) Edge technology. The objectives of such system are to control and optimize the gas-lift network automatically, reduce downtime during compressor upsets, and mitigate any potential flare events.\u0000 The new closed-loop gas-lift optimization algorithm consists of well and surface network models, optimization and regression solvers, and disturbance adaptation, all running in real time. The closed-loop optimizer works as follows: (1) in every cycle, the optimizer receives measurements; (2) disturbance adaptation compares the model's estimates with the measurements and adapts the surface network model to make it more accurate; (3) the adapted surface network model and well models are used to find the optimum lift gas setpoints; and (4) the calculated setpoints are sent to the automation system through IoT Edge technology.\u0000 Integral to this system is a single-well nodal analysis model that automatically generates updated models daily for all gas-lift wells. This model is used both as a monitoring tool by the engineers and as part of the network model in the closed-loop gas-lift optimizer, which has been deployed in multiple fields and is running continuously (24/7). The optimizer has saved both production engineering time per network and well specialist time per compressor upset event. Field case studies have shown that the closed-loop optimizer has been successful in maintaining compressor station outlet pressure and optimizing the gas-lift networks during compressor upsets or potential flare events. A significant improvement in oil production has been achieved in fields using optimizer due to both optimized lift gas distribution and reduced downtime.\u0000 This new algorithm can optimize gas-lift networks during normal operating conditions, compressor upsets, or potential flare events, while simultaneously controlling compressor station outlet pressure within an acceptable range in real time. Significantly, disturbance adaptation is used for the first time to improve the surface model accuracy immediately as additional measurements are received.","PeriodicalId":113398,"journal":{"name":"Day 2 Wed, August 24, 2022","volume":"243 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":"121028812","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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